Brae Area Decommissioning Overview February 2016

Transcription

1 Brae Area Decommissioning Overview February 2016 Copyright Marathon Oil Decommissioning Services LLC. All rights reserved.

2 9000-MIP-99-PM-XE Revision 1 MarathonBraeDecom@Marathonoil.com The illustrations and drawings in this document are for information only. Marathon Oil U.K. LLC does not warrant or represent that it is complete or accurate and will not be liable for any person s reliance upon these illustrations for any purpose.

3 Purpose This document has been produced to provide a concise summary of the scope, considerations and studies that have, to date, been completed to better understand and to identify the most appropriate options for the decommissioning of the Brae Area infrastructure. No formal conclusions have been drawn or decisions made at this time or within this report. This report is not intended to detail all aspects of the decommissioning programme, but should provide the reader with a sound level of understanding on the current status. Feedback, comment and input is invited so that any decision making is completed with consideration of all interested stakeholders, opinions and inputs. In order to remain concise, this report intentionally does not include details that are already captured in reference documents but attempts to summarise each document to the level that is required to provide clarity of the element being discussed only. This document is provided for information only. 3 of 52

4 Brae Area Decommissioning Overview Report Contents 1.. Acronyms Background Regulatory Requirements Brae Area Overview Scope of Decommissioning Programmes Assessment Process Assurance Technical Summary Brae Alpha Brae Bravo East Brae Sub-sea Installations Sub-sea Infrastructure Reuse Assessment Topsides and Sub-structures Sub-sea Installations Well Plug and Abandonment Topsides Decommissioning Reverse of Installation Single Lift Demolition In-situ Hybrid Sub-structure Decommissioning Sub-structure Comparative Assessment Methodology Sub-structure Technical Studies Sub-structure Safety Studies Sub-structure Environmental Studies Noise Waste Socio-Economic Sub-structure Economics Sub-structure HAVR Hazard Assessment Verification Review Drill Cuttings Seabed Analysis Results Summary Drill Cuttings Analysis Results Summary Drill Cuttings NEBA Pipeline and Sub-sea Infrastructure Decommissioning Pipeline and Sub-sea Infrastructure Regulatory Requirements Pipeline and Sub-sea Infrastructure Comparative Assessment Methodology Assessment Outcomes Environmental Impact Assessment Regulatory Context Proportionality in Environmental Impact Assessment The Enhanced Role of Scoping and Consultation Waste Management Brae Area Decommissioning Proposed Timeline References of 52

5 1. Acronyms CA CoG CoP CSV DECC DNS EIA EL ES GHG HLV IRPA LAT MCAA MODU NEBA OPEP O&G UK OGA OSPAR OSRL PL PLL PNEC PON PWA QRA ROV ROVSV SAGE SEPA SLV SSCV SSIV THC UKCS WMS Comparative Assessment Centre of Gravity Cessation of Production Construction Support Vessel Department of Energy and Climate Change Decom North Sea Environmental Impact Assessment Elevation Environmental Statement Greenhouse Gas Heavy Lift Vessel Individual Risk Per Annum Lowest Astronomical Tide Marine & Coastal Access Act Mobile Offshore Drilling Unit Net Environmental Benefit Analysis Oil Pollution Emergency Plan Oil and Gas UK Oil and Gas Authority Oslo Paris Convention Oil Spill Response Ltd Pipe Line Potential Loss of Life Predicted No-Effects Concentration Petroleum Operations Notice Pipeline Works Authorisation Quantified Risk Assessment Remotely Operated Vehicle Remotely Operated Vehicle Support Vessel Scottish Area Gas Evacuation Scottish Environmental Protection Agency Single Lift Vessel Semi-submersible Crane Vessel Sub-sea Isolation Valve Total Hydrocarbon Content UK Continental Shelf Waste Management Strategy 5 of 52

6 Brae Area Decommissioning Overview Report 2. Background This document provides a summary of the considerations, assessments and reviews undertaken to better understand the scope and options for the decommissioning of the Brae Area infrastructure. No conclusions or decisions have been drawn from this effort, although some options and methods have been discounted due to technical and/or safety reasons. These are discussed in later sections. As part of this, stakeholder engagement is essential and this document is intended to provide those individuals and organisations with an interest in the decommissioning of the Brae Area with some background information and the status of study work that has been completed or is on-going to support decision making. 2.1 Regulatory Requirements The decommissioning of offshore oil and gas installations and pipelines on the United Kingdom Continental Shelf (UKCS) is controlled through the Petroleum Act 1998, as amended by the Energy Act The UK s international obligations on decommissioning are governed principally by the Oslo/ Paris 1992 Convention for the Protection of the Marine Environment of the North East Atlantic (OSPAR Convention [1]). The Department of Energy and Climate Change (DECC) is the competent authority on decommissioning in the UK for OSPAR purposes. In July 1998, the OSPAR Commission adopted a binding Decision (OSPAR Decision 98/3) to ban the disposal of offshore installations at sea, thus requiring all installations to be entirely removed, with some derogations (Section 2.3) available. 2.2 Brae Area Overview The Brae fields lie approximately 170 miles (274 km) north-east of Aberdeen principally within three UK Blocks: 16/7a, 16/3a and 16/3b. Marathon Oil UK LLC is the operator. TAQA Bratani Limited, TAQA Bratani LNS Limited, Centrica Resources Limited, and JX Nippon Exploration and Production (UK) Limited are equity partners. Brae Alpha commenced production in 1983, Brae Bravo in 1988 and East Brae in The Central and West Brae/Sedgwick sub-sea tiebacks to Brae Alpha commenced production in 1989 and 1997, respectively. The Braemar sub-sea tieback to East Brae commenced production in Liquids from the Brae Area are exported via the Forties pipeline to Cruden Bay, and then on to Kinneil near Grangemouth. Gas is transported via the Scottish Area Gas Evacuation (SAGE) pipeline to the SAGE terminal at St. Fergus (Figure 2-1). 6 of 52

7 2.3 Scope of Decommissioning Programmes In consultation with DECC, Marathon Oil UK LLC proposes to submit two Decommissioning Programme documents each supported by an Environmental Statement. One of each of these documents will detail the decommissioning of the East Brae and Braemar facilities and associated pipelines and sub-sea structures. The other set will detail the rest of the Brae Area, including the Brae Alpha and Brae Bravo platforms, West Brae (including Sedgwick and the West Brae Extension manifold), Central Brae and all associated pipelines and sub-sea structures. Marathon Oil intends to submit all of these documents simultaneously. In some cases, it may be deemed appropriate to consider applying for an exemption where merited from parts of the regulations governing the decommissioning of offshore oil and gas facilities. These exemptions are granted by member states and are known as a derogations. To determine if derogation is appropriate, a process of comparative assessment and consultation in OSPAR (details and expectations of which are set by DECC) is required. If the results of these assessments conclude that derogation is appropriate, applications will be made in accordance with DECC s requirements. 2.4 Assessment Process Assurance As part of the Decommissioning Programme and any Derogation Application process, it is proposed that the studies and the assessment process that support the chosen decommissioning options and Derogation Applications are subject to independent verification. The purpose of this verification is to confirm that the assessments are reliable and the evaluation of the options is transparent [2]. An independent consultancy was engaged to form an Independent Review Committee (IRC), and deliver this assurance and verification for the processes adopted by Marathon Oil to evaluate, principally, the sub-structure decommissioning options. The key findings from this have been addressed, and endorsed the validity and appropriateness of the methodology adopted by Marathon Oil and the assessments made to date. 7 of 52

8 Brae Area Decommissioning Overview Report 8 of 52

9 Figure 2 1 Brae Area Overview Schematic 9 of 52

10 Brae Area Decommissioning Overview Report 2.5 Technical Summary Brae Alpha Location Water Depth UK Block 16/7a, 161 miles (259 km) north-east of Aberdeen 112m (367ft) Number of Platforms 1 Production Start Date 1983 Recoverable Sub-structure Steel Weight Topsides Weight Accommodation 20,000 tonnes (8 legged steel jacket) 30,200 tonnes (dry) 34,000 tonnes (operating) 25 Modules 211 beds Height of Jacket 123m (404ft) Table 2 1 Brae Alpha Technical Summary Figure 2 2 Brae Alpha Photograph 10 of 52

11 2.5.2 Brae Bravo Location Water Depth Number of Platforms UK Block 16/7a, 167 miles (269 km) north-east of Aberdeen 99m (326ft) 1 (plus flare tripod) Production Start Date 1988 Recoverable Sub-structure Steel Weight Topsides Weight Accommodation Height of Jacket 22,000 tonnes (8 legged steel jacket) 1,000 tonnes (tripod support for flare) 36,200 tonnes (dry) 42,000 tonnes (operating) 28 Modules 191 beds 114m (374ft) Table 2 2 Brae Bravo Technical Summary Figure 2 3 Brae Bravo Photograph 11 of 52

12 Brae Area Decommissioning Overview Report East Brae Location Water Depth UK Block 16/3a, 175 miles (282 km) north-east of Aberdeen 116m (380ft) Number of Platforms 1 Production Start Date 1993 Recoverable Sub-structure Steel Weight Topsides Weight Accommodation Height of Jacket 10,000 tonnes (4 legged steel jacket) 20,000 tonnes (dry) 22,500 tonnes (operating) 10 Modules 188 beds 136m (446ft) Table 2 3 East Brae Technical Summary Figure 2 4 East Brae Photograph 12 of 52

13 2.5.4 Sub-sea Installations As part of the on-going Brae Area development, additional hydrocarbon reservoirs have been drilled and connected to the host facilities by means of equipment and materials placed on the seabed. Sub-sea solutions have been used in these circumstances as this technology allows otherwise uneconomic hydrocarbon reserves to be recovered without the need for new platform facilities. Fluids recovered from these installations are transported to a host facility via pipelines for processing and onward transportation to market. Location Water Depth Weight Number of Wells 8 Distance from Host Central Brae - Block 16/7a 105m (345ft) >650 tonnes 4.4 miles (7km) from Brae Alpha Figure 2 5 Central Brae Template Installation Location West Brae - Block 16/7a Water Depth Weight Number of Wells Distance from Host 107m (351ft) >140 tonnes plus wellheads 10 (including Sedgwick and West Brae Extension) 5.5 miles (8.8km) from Brae Alpha Figure 2 6 West Brae Manifold Installation Location Braemar - Block 16/3c Water Depth Weight Number of Wells Distance from Host 120m (394ft) >20 tonnes 2 (1 suspended) 7.8 miles (12.5km) from East Brae Table 2 4 Sub-sea Installations Figure 2 7 Braemar Wellhead and Christmas Tree (without protective structure) 13 of 52

14 Brae Area Decommissioning Overview Report Sub-sea Infrastructure The Brae Area sub-sea infrastructure consists of: A 30-inch diameter oil export line from Brae Alpha to the Forties pipeline system A 30-inch diameter gas export pipeline from the East Brae platform to the SAGE pipeline system An 18-inch diameter condensate pipeline from Brae Bravo to Brae Alpha An 18-inch diameter condensate pipeline from East Brae to Brae Alpha via a Wye connection at Brae Bravo An 18-inch diameter gas pipeline between East Brae and Brae Bravo An 18-inch diameter gas pipeline between Brae Bravo and Brae Alpha Gas and liquids pipelines from sub-sea wells to the Brae platforms Control and chemical injection umbilicals between the Brae platforms and sub-sea wells Manifolds that connect production flowlines from sub-sea wells to pipelines that carry the produced oil and gas to the Brae platforms Sub-sea valves and valve actuators associated with the various pipelines Junctions/connections between pipelines Power cables between the Brae Alpha, Brae Bravo and East Brae platforms. These provide electrical power between the three platforms Mattresses, grout bags and other stabilisation features Flowlines 45 miles (75km) Umbilicals 23 miles (38km) Pipelines 120 miles (195km) Cables 35 miles (57km) Table 2 5 Sub-sea Pipeline etc. Lengths Figure 2 8 Cross Section of 6 West Brae Umbilical 14 of 52 Figure 2 9 West Brae Area with Stabilisation and Protection Structures

15 Figure 2-10 Example well head protection structure (Braemar) 15 of 52

16 Brae Area Decommissioning Overview Report 16 of 52

17 Figure 2-11 Brae Area Sub-sea Installations and Infrastructure 17 of 52

18 Brae Area Decommissioning Overview Report 1 East Brae/B LAT 2 3 East Brae Platform KP 0.0 EL -116m 28 Mats SSIV Control Umbilical Mats 9 4a 5 4b East Brae SSIV/ Crossover Structure KP Direction of flow Structure co in mattresses - quantity unk (NB. damaged mattre East Brae 500m Zone Limit 12 Rev Date Drn Orig Chk App Revision Title B DP RCA DMO KJS Issued for Client Comment Marathon Document No GEN-99-PL-SH Sht 11 Rev. I01 Genesis Document No. J60016C-A-SH Rev. B1 Brae Bravo/East Brae PMS Cable KP Brae Bravo 500m Zone L Brae Bravo/BP Miller 16" Gas Transfer PL Kingfisher Control Umbilical PL SSIV Control Umbilical Kingfisher 10" Produ Kingfis Figure 2 12 Example Pipeline Schematic (PL894 East Brae Brae Bravo Condensate) 18 of 52

19 rae Bravo Wye Structure 18" Condensate Export Pipeline (PL894) Ident a 4b Description East Brae Platform Pig Launcher VX-0106X East Brae Riser ESDV XXV0802 East Brae Platform Riser East Brae Tie-In Spool East Brae Tie-In Spool Pipeline East Brae SSIV Tie-In Spool East Brae SSIV/Crossover Pipework East Brae SSIV XXV " Manual Valve VE East Brae SSIV Tie-In Spool Pipeline Lateral Tie-In Structure Pipework 10" Manual Valve VE Brae Bravo Wye Tie-In Spool Length (m) O.D. (mm) Coating Notes mm FBE, 25mm Neoprene between EL +8.7m & -2.7m mm FBE mm CTE & 40mm Concrete mm CTE & 40mm Concrete mm FBE mm FBE mm FBE 6mm CTE & 40mm Concrete mm FBE sacrificial anodes along pipeline. Untrenched, no protection Unknown quantity of grout bags over pipeline at 1 location Unknown quantity of grout bags under pipeline at 1 location Lateral Tie-In Structure KP vered nown sses) Rock Cover Start KP imit Rock Cover End KP KP KP ction P1 - PL1488 KP her 10" Production P2 - PL1489 KP KP 14.9 Brae Bravo Wye Structure 19 of 52

20 Brae Area Decommissioning Overview Report 3. Reuse Assessment An assessment has been completed to evaluate the options available for the reuse of the platform and sub-structures and whether they are feasible. Reuse of the facilities for purposes other than hydrocarbon extraction and processing, such as wind/wave energy, carbon capture and storage or reuse outside the energy sector have been considered. 3.1 Topsides and Sub-structures A qualitative assessment [4] of the reuse options for the Brae Area installations shows that there are no credible or economically viable options for reuse. This is principally as a result of limited remaining fatigue life of the sub-structure, obsolescence issues associated with the topsides of the installation, and economic factors associated with converting the installations for any intended reuse. Components from the installation may be reused if suitable alternatives can be found. This will be developed as the Decommissioning Programmes progress and suitable markets are identified. Because the sub-structures are exceeding their fatigue life and removing, transporting and preparing for reuse will over utilise key elements of the sub-structure, it is concluded [5] that reusing the Brae sub-structures in-situ, or relocating to another area is not technically feasible. 3.2 Sub-sea Installations The Brae sub-sea installations were originally engineered and built for the specific conditions at the Brae Area and the facilities are reaching the end of their design life. After cessation of production, there are no options for reuse of these facilities in their current locations. Marathon Oil continues to investigate the possibility of reusing some equipment, such as wellheads at different locations. 20 of 52

21 4. Well Plug and Abandonment The Brae Area consists of multiple platform and sub-sea wells that are required to be plugged and abandoned 1. Platform Number of Wells Brae Alpha 34 Brae Bravo 28 East Brae 21 Table 4 1 Platform Wells to be Plugged and Abandoned Sub-sea Installation Number of Wells Central Brae 8 West Brae (inc. Sedgwick & Extension) 10 (2 suspended) Braemar 2 (1 suspended) Table 4 2 Sub-sea Installation Wells to be Plugged and Abandoned The Brae Area well abandonments will be designed and conducted to ensure there is no unplanned escape of fluids from the well or from the reservoir to which it was connected. Abandonment design will be consistent with the principles set out in Oil and Gas UK guidelines [14] for well suspension and abandonment in order to demonstrate compliance with UK regulations. Conductor 2 removal is not included in the abandonment phase for the platform wells and will be managed as part of the topsides decommissioning activities. It is intended that all platform based wells that have no further utility will be plugged and abandoned prior to the platform Cessation of Production (CoP). Sub-sea wells will be plugged and abandoned once the host platform has reached CoP and as the availability of appropriate vessels allows subsequent to that date. Sub-sea wells will be formally suspended (i.e. fully isolated from the reservoir) if left for any significant duration prior to final abandonment. 1 When a well is no longer required, multiple plugs of concrete of several 100ft in length are injected into the well at various depths to permanently seal the reservoir from the surface. Only once these plugs have been installed can the well be considered abandoned. Temporary plugs can be installed to provide this isolation, but the well is then only considered suspended as these plugs can be removed at a later date for operational purposes. 2 A conductor is a steel pipe that is used to guide and protect the production pipework that connects the reservoir to the platform. The conductor extends from the seabed, through the water column up to the platform deck. 21 of 52

22 Brae Area Decommissioning Overview Report 5. Topsides Decommissioning There are a variety of technically feasible methods to remove the topsides of an installation. No decision has been made on the most appropriate or preferred option for any of the Brae Area topsides. Ultimately, given that the safety implications of the options being considered are acceptable and as low as reasonably practicable (ALARP) [7], the selected removal method will be the one that delivers the best all-round solution (taking into account the elements listed above). The following sections summarise the considerations that need to be made for each of the viable options. 5.1 Reverse of Installation All three Brae platform topsides were installed as a number of modules by a Heavy Lift Vessel (HLV). The modules were fabricated onshore and then transported to site by barge. They were lifted into place by an HLV and then the interconnecting pipework and cables installed (or hooked-up ) on site. As part of the modular design, careful consideration and assessment work was carried out to ensure that all the lifting points and the centre of gravity (CoG) were well understood and appropriately engineered. Some modules weigh in excess of 8,000 tonnes. To enable removal in a similar manner, significant preparatory work is required. In order for an HLV vessel to safely lift a module off the topsides, it must have a significant clearance on all sides. This requires all the interconnecting pipework and cable to be cut and removed. In addition, the structural integrity of the module and lifting points must be verified (and if required strengthened). The CoG will also have likely changed as modifications have been made to multiple areas of the plant since they were installed. These challenges can be overcome, but require significant engineering and preparatory work. Once the module has been removed, it must be transported to a disposal yard where it will be dismantled for reuse or cut into small, transportable pieces for delivery to a recycling or disposal facility. 22 of 52 Figure 5 1 An HLV Installing a Module on East Brae

23 5.2 Single Lift New technology is being developed to assist the removal of installations that are being decommissioned. This includes the development of a vessel capable of lifting the entire topsides in a single lift and then transporting it onshore for dismantling. The Pioneering Spirit is the only Single Lift Vessel (SLV) currently on the market and, although currently unproven at this, conceptually it has the capability to lift all three of the Brae topsides structures. However all three, and specifically Brae Alpha and Brae Bravo, would require significant structural strengthening as the topsides are supported on a split Module Support Frame (MSF) and if lifted as one could fold and result in structural collapse. It is estimated that up to 2,000 tonnes of additional steel would be required to fully strengthen these structures. As with the HLV solution, the dismantling efforts would be completed onshore and recyclable material cut into small pieces for transportation to the recycling point. 5.3 Demolition In-situ In-situ demolition uses large hydraulic shears and other cutting methods to cut the topsides into small transportable pieces. These are then loaded into containers and shipped to shore where they can be transported to the appropriate recycling point. Given that the dismantling of the structure has occurred offshore, there is limited requirement for further work onshore once the containers holding the already cut and sorted materials have arrived. They can simply be transported to the recycling/disposal facility. There is minimal preparatory work required for the dismantling teams offshore. However, those individuals completing the dismantling work will be offshore for a significant duration with a consequential increase in risk and energy use. 5.4 Hybrid The hybrid approach is a combination of techniques. In-situ demolition would be utilised to remove some of the structure where appropriate to do so, for example all the modules above the Module Support Frame (MSF) (the lowest deck). A HLV would then be used to lift off the MSF and return it to shore for disposal. 23 of 52

24 Brae Area Decommissioning Overview Report 6. Sub-structure Decommissioning The sub-structure includes the jacket, jacket piles, drilling template (if relevant) and jacket ancillary items. All three Brae Area sub-structures 3 exceed 10,000 tonnes in steel recovery weight [6] and were installed before February Figure 6-1 illustrates the height of these structures relative to other well known UK landmarks. An on-going comparative assessment for all the main sub-structures is considering the impact and risks associated with their removal, a possible outcome of which may be an application to OSPAR to permit leaving the sub-structure footings in-situ. If approved, the footings (everything below the top of the piles as shown in Figure 6-2, Figure 6-3 and Figure 6-4) of the sub-structure may be left in-situ. Elements shown in red will be removed. See Section 6.1. The following sections detail the methodology and studies that have been completed to date for this assessment. No conclusions have been drawn from these works and they are reported here for information and to support on-going review and assessment. Brae A Jacket Scott Monument East Brae Jacket St Paul s Cathedral Brae B Jacket & Flare Tower Elizabeth Tower 123.3m 60m 136m 111m 114m & 123.6m (Big Ben) 96m Figure 6 1 Jacket Size Comparison 3 Brae Bravo has an additional flare boom jacket (tripod). This is assumed to be removed fully and is not subject to derogation considerations 24 of 52

25 Figure 6 2 Brae Alpha Sub-structure Figure 6 3 Brae Bravo Sub-structure Figure 6 4 East Brae Sub-structure 25 of 52

26 Brae Area Decommissioning Overview Report 6.1 Sub-structure Comparative Assessment Methodology The OSPAR Decision 98/3 recognises that there are technical challenges with the removal of very large steel sub-structures. As such, an exemption from the decision to remove to shore, or derogation, is an option should it be shown that it is appropriate to leave the footings in-situ and just remove the upper part of the sub-structures. The purpose of the comparative assessment is to provide a balanced analysis of the main alternatives for sub-structure removal; in this case full removal versus partial removal to the footings of the sub-structures as shown in Figure 6-2/3/4. These figures show a possible separation point between the footings and jacket; the exact depth at which the jacket would be cut in any derogation proposal will be subject to detailed technical and environmental considerations. Before determining the methodology to be used to complete the comparative assessment for the Brae Area sub-structures, a review was completed of industry experience to date, including BP Miller [10] and CNRI Murchison [11] installations, to identify any lessons to be learnt. The comparative assessment for the sub-structure will be evaluated based on the expectations set down in the DECC guidance notes [2]. Principally this defines five criteria that each option should be assessed under: 1. Safety 2. Environmental 3. Technical 4. Socio-Economic 5. Economic 4 An independent body (IRC - Independent Review Committee) comprising external subject matter experts was engaged, in line with industry expectations, to review, verify and validate the approach adopted to provide assurance that the process had been completed without bias and in sufficient detail/scope to support decision making. Structural Assessment Safety Assessment Technical Studies & Removal Methods Statements Environmental Assessment Societal Assessment Executive Summary Report Independent Review Stakeholder Engagement CA Workshop CA Document and Decision Independent Technical Review Economic Assessment Figure 6 5 Comparative Assessment Method Overview 4 Cost is important but is not used as a prime differentiator. It is included for completeness and is a measure of proportionality when considering the other four criteria. 26 of 52

27 Figure 6-5 shows the flow of the comparative assessment process that has been adopted by Marathon Oil for the Sub-structures. To determine if derogation is appropriate for the Brae substructures, a comparison between removal options for full and partial removal is needed. To simplify and complete this comparison, bounding (or base) cases were selected for each and then evaluated. The selection of these bounding cases was based on technical assessments (see subsequent sections in this document) and lessons learned from others in the industry. These bounding cases were then assessed within the five key areas of the comparative assessment process, summarised and verified by the IRC. Stakeholder engagement in the outcomes of these studies will feed in to the comparative assessment evaluations that will be used to support the ultimate decisions that will be made in terms of determining if derogation is appropriate. This is an iterative process and each element in the flow diagram may be revisited on multiple occasions Sub-structure Technical Studies Technical assessments were commissioned to review all currently known options and methods available for both the complete and partial removal of the Brae Area platform sub-structures to verify that they are technically achievable and appropriate for the application to the Brae Area. The options technically assessed were: Section Cut and Lift using a HLV Buoyancy Aided Removal Removal by SLV e.g. Allseas Pioneering Spirit To focus on critical factors and standardisation of an approach, Marathon Oil contracted with external consultants who maintain a database which holds a significant quantity of data gathered from previous Decommissioning Programmes and from the experience gained during actual decommissioning. This database provides information on the type and number of activities, equipment and resources needed for each phase of each method that can then be applied and factored to the specifics of the structures in the Brae Area. This database was independently verified to ensure its suitability for the Brae Area. For each removal method, statements were generated utilising this database and additional technical studies (conducted where any gaps or specific Brae Area data was required) to highlight the major activities and equipment required. For each of the methods identified for sub-structure removal (both partially and fully), a detailed estimate of the resources (people, equipment, vessels, HLVs etc.) was developed using the norms from the approved and verified database. Using this input, further studies in each of the five criteria were completed. Single lift and buoyancy tank removal methods have been studied for complete removal only. Partial removal by these methods may in time merit further investigation if they are able to improve the likelihood of a successful complete removal of the sub-structure, but at this time these methods are only of interest in the context of comparative assessment to satisfy OSPAR 98/3. The technical assessments have shown that complete and partial removal by Section Cut and Lift using an HLV is technically feasible. It is a proven method, has been used to remove similar sub-structures in the United Kingdom Continental Shelf (UKCS) and carries a relatively low element of technical risk. East Brae partial removal is technically feasible by a single lift using an HLV. The technical studies have also shown that removal using buoyancy tanks may be possible, but to date, this method has not been proven on a sub-structure of similar size and weight to Brae Alpha or Brae Bravo. The East Brae sub-structure is smaller than the Brae Alpha or Brae Bravo sub-structure, but water depth and sub-structure height poses significant concerns with 27 of 52

28 Brae Area Decommissioning Overview Report respect to draft if the sub-structure was to be floated to an inshore location. Ultimately the sub-structure will have to be sectioned, cut and lifted at an inshore location in a similar manner to the offshore location. However, the additional preparation activities at the offshore location to install the buoyancy tanks and the actual flotation to an inshore location results in extensive additional work. This carries significant technical risks during offshore installation of the tanks, transportation of the sub-structure in the water column and set down at an inshore location. The technical studies conclude that buoyancy aided removal does not increase the possibility of successful complete removal when compared to section cut and lift at the offshore location. To date the Allseas vessel Pioneering Spirit has no proven motion characteristics. Structural analysis of the sub-structure transportation case was completed using accepted industry upper and lower bound vessel motion scenarios. The analysis indicates that the full removal of the Brae Alpha and Brae Bravo sub-structures may survive transportation at the lower bound motion scenario, and with significant modification/strengthening to both the jacket and lift vessel as it is expected, even at these lower bound conditions, that elements of the jacket may fail and result in collapse as it is transported to shore. The East Brae sub-structure may fare better due to its design and construction but this assessment is subject to further detailed engineering. No assessment has been completed for the retrieval phase of the removal process, the phase where the jacket is lifted from the water and rotated from the vertical to horizontal position. At this stage, transportation as a single lift by the Pioneering Spirit cannot be assured and buoyancy aided removal cannot offer a greater chance of complete removal when compared to section cut and lift. Neither of these options was carried forward to the safety and environmental studies with the exception of the East Brae sub-structure which, being of a different design to Brae Alpha and Brae Bravo may be a candidate for using an SLV, subject to further detailed engineering assessment. Table 6-1 presents the findings of these reviews and provides an indicative scale of technical feasibility. The colour banding ranges from dark green, which implies the option and techniques proposed are known and have a track record of success, to red where the option is not considered technically achievable. 28 of 52

29 Full Removal Partial Removal Technique Alpha Bravo East Alpha Bravo East Cut and Lift Small / Medium Sections Large Sections Technically feasible with use of proven technology. Stability of cutting arrangement for sub-structure pile structures requires detailed analysis. Technically feasible with use of proven technology. Buoyancy Significant concerns over the technical feasibility with respect to tank capacity, design and installation. Transit route over live pipelines with very shallow draft problematic. Still requires full marine lifting and transportation spread once in inshore waters to facilitate section cut and lift, and transfer to shore for final dismantling and disposal. Significant concerns over the technical feasibility with respect to tank capacity, design and installation. Transit route over live pipelines with very shallow draft problematic. Still requires full marine lifting and transportation spread once in inshore waters to facilitate section cut and lift, and transfer to shore for final dismantling and disposal. Footings have been removed so set down in shallow waters an issue due to instability or additional fabrication/ disposal required for temporary mud mats. Pioneering Spirit (SLV) Not considered possible. Concerns with the substructure integrity during transport phases with footings intact. Not considered possible. Concerns with the substructure integrity during transport phases with footings intact. Possible. Extensive modification to Pioneering Spirit required to support the substructure and pile clusters. Subject to lift and tilt assessment. Conceptually possible subject to detailed structural analysis and lift and tilt assessment. (Note: Not assessed further for the purpose of the comparative assessment process as Section Cut and Lift assumed to be more onerous in terms of safety and environmental considerations). Single Lift HLV Not considered possible. Substructure was barge launched so not retrievable to a barge at sea and weight exceeds HLV capacity. Potential for retrieval to inshore waters on hook. Pile clusters, buoyancy concerns, HLV hook height and capacity prevent lifting onto a barge. Weight and buoyancy of substructure prevents rotation into horizontal at sea and therefore prevents transfer to barge at sea. However potential to transfer to inshore water on hook. Footings have been removed so set down in shallow waters an issue due to instability - additional fabrication/disposal would be required for temporary mudmats. Technically feasible with use of proven technology. Best Worst Table 6 1 Summary of Technical Options for Sub-structure Removal 29 of 52

30 Brae Area Decommissioning Overview Report Sub-structure Safety Studies The safety studies form a core part of the comparative assessment process and involve identification of all hazards associated with the decommissioning of the sub-structure, as detailed in the method summaries in Section 2.5. Quantitative Risk Assessment (QRA) techniques have been used to provide a numerical evaluation of the risks these hazards generate; these values are expressed as Potential Loss of Life (PLL 5 ) and Individual Risk (IR). The QRA has been undertaken using established techniques drawn from experience and lessons learned from similar works such as the BP Miller [10] platform to provide an estimate of the removal and disposal risks Risk from Sub-structure Removal The average IR per removal operation for either full or partial removal of any of the Brae platform sub-structures is well below the risk level of 1x10-3 per year (an individual having a 1 in 1,000 chance of being a fatality in any one year) which is regarded by the Health and Safety Executive (HSE) [7] as intolerable. Therefore no option for any platform can be excluded based on the risks associated with the removal activities as being intolerable. For the purpose of the comparative assessment, an evaluation of the difference in PLL has been made between full and partial removal. For example, full removal of the Brae Alpha sub-structure has been assessed as having a statistical likelihood of 0.32 fatalities per year (or one fatality within the project every three years) compared to partial removal which is 0.16 (or one fatality every six years). Note this is not the same as IR which is the risk to an individual; PLL represents the aggregated risk of a fatality over the whole workforce. The best options (in terms of safety) have been selected for the full removal and the worst for partial removal to ensure that the case for leaving the sub-structure footings in-situ has been appropriately challenged from a safety perspective. These are presented below Brae Alpha Brae Bravo East Brae Full Removal Partial Removal Difference 50% 59% 20% Note: If partial removal is completed by SLV, there is an expectation that the risk would be lower than that estimated for the cut and lift options due to the reduction in work scope required offshore. For the purpose of the comparative assessment however, the cut and lift risk has been quoted. Table 6 2 Comparison of PLL between Full and Partial Sub-structure Removal 5 Expected number of statistical fatalities per year. 30 of 52

31 PLL Brae Alpha Brae Bravo East Brae Full Removal Partial Removal Figure 6 6 Comparison of PLL between Full and Partial Sub-structure Removal This does show however that the partial removal represents a lower risk to personnel than full removal for all of the Brae Area platform sub-structures. This is not unexpected as there is, by definition, less work required and hence lower exposure to risk for the partial removal case Risk to Fishermen If the sub-structure footings remain in-situ, there is a risk to fishermen from underwater obstructions and fishing gear snagging should they trawl through the area. The average increase of the individual risk for UK fishermen if the footings of any of the three substructures are left in-situ has been assessed as less than 0.1%. With appropriate mitigations put in place, such as the use of FishSafe [7] and the Kingfisher [9] charts, this risk can be further reduced. Additionally, the potential retention of the 500m safety zone currently around the Brae Area platforms, would provide additional mitigation and control of the area for fishing vessels, including foreign registered vessels that may not have access to the FishSafe system Sub-structure Environmental Studies Energy and Emissions The Institute of Petroleum (IP) provides a standardised set of guidelines for assessing energy and emissions associated with decommissioning, allowing oil and gas operators to make predictions of the potential energy use and gaseous emissions. Complete and partial removal of the sub-structures by section cut and lift using an HLV have been studied in order to estimate the energy consumption required and resultant emissions generated during the removal operations. The study took into consideration the types of vessels required during preparation and removal of the sub-structure and the subsequent treatment of the sub-structure materials through dismantling, reuse, recycling or replacement. 31 of 52

32 Brae Area Decommissioning Overview Report Energy and emissions associated with replacement with new steelwork of any structure left in-situ must be assessed and accounted for in the calculations. The energy required to recycle steel into a useable form is much less than that required to create new steel (i.e. credit can be taken for recycling over new manufacture). So although the energy required to recover the steelwork is less for partial removal, when the energy required to create new steel (materials processing) equivalent to that which is not recovered is considered, the total energy attributable to the steelwork is greater for partial removal than complete removal. The types of vessels and equipment used for complete and partial removal are broadly the same. Complete removal takes longer than partial removal and therefore higher energy and atmospheric emissions are estimated for complete removal. The total energy requirements of each option and the emissions expected to be released into the atmosphere from the consumption of the fuel to generate that energy were calculated and a comparison of the energy requirements and the CO 2 emissions is summarised in Table 6-3. Brae Alpha Brae Bravo East Brae Full Partial Full Partial Full Partial Materials Processing (GJ) 6 225, , , , , ,500 Vessel Requirements (GJ) 6 955, , , , , ,000 Total Energy (GJ) 6 1,180, ,500 1,109, , , ,500 CO 2 Emissions (tonnes) 92,000 64,000 87,000 58,500 61,500 32,500 Note: Worst case options selected for those that have a range. The East Brae sub-structure is conceptually suitable for full removal by Single Lift but further technical assurance is required - See Section Cases presented are considered bounding options for comparative assessment purposes. If partial removal is completed by SLV, there is an expectation that the emissions and energy use would be lower than that estimated for the cut and lift option presented here due to the reduction in work scope required offshore. For the purpose of the comparative assessment however, the cut and lift values have been used. Table 6 3 Summary of Energy Requirements and Emissions 6 Overall, partial sub-structure removal uses less energy and creates fewer emissions than complete removal case for all Brae platform sub-structures. 6 GJ Giga Joules 32 of 52

33 1,400, ,000 1,200,000 90,000 Total Energy (GJ) 1,000, , , ,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 Total CO 2 Emissions (tonnes) 200,000 10,000 0 Full Partial Full Partial Full Partial Brae Alpha Brae Bravo East Brae 0 Total Energy (GJ) Total CO 2 Emissions (tonnes) Noise Figure 6 7 Summary of Energy Requirements and Emissions Underwater noise can be harmful and potentially fatal to marine wildlife, specifically marine mammals. The noise sources associated with all the sub-structure removal options are expected to be the same, i.e. they will use the same type of vessel, and the same cutting methods. Therefore it is duration of those activities, or the number of events involved, that determine how the environmental impact differs between full and partial sub-structure removal. Due to longer duration and additional activity, there is expected to be more acoustic energy emitted into the marine environment for the complete removal option compared to the partial removal option. Complete removal is likely to have an increased potential to impact marine mammal populations compared to partial removal. However, it is likely that mitigation measures could be deployed for both removal options that would eliminate the likelihood of such marine mammal injury. Explosive cutting has not been specified in the current technical method statements (Section 6.1.1) but was studied in the event that it is considered in the future. The risk of injury to marine mammals will increase with use of any explosives in addition to the decommissioning options considered in this assessment due to the high peak sound pressure levels, particularly close to the source. However, mitigation measures could be deployed that would significantly reduce the likelihood of such injury Inshore Environmental Impacts The complete removal option may result in increased interaction with important conservation sites. The level of magnitude of this interaction will depend on the inshore locations selected for either option. With appropriate management procedures the impact magnitude may be similar for both full and partial decommissioning options. 33 of 52

34 Brae Area Decommissioning Overview Report Onshore Environmental Impacts There are potential impacts associated with bringing marine growth onshore, and for potential contaminants or pollution associated with the dismantling and treatment of the sub-structure. Although the extent of these impacts is as yet undefined, the quantity of material (such as the sub-structure and marine growth) is greater for the complete removal option. However, the assumption can be made that site environmental management systems and local environmental regulatory controls would ensure that the environmental impact of both full and partial decommissioning options is similarly low Waste Overall, the impact of waste to landfill is anticipated to be small, but this will depend on a number of factors including the nature and condition of the recovered materials and the availability of reuse or recycle opportunities. The key variability is the quantity of steel and other materials removed; the complete removal option will result in a greater quantity of materials returned to shore. See also Section Socio-Economic Consideration of the impact on society of all sub-structure decommissioning activities and potential removal options was undertaken, with a particular focus on: Offshore societal impacts (impact on other sea users, primarily the commercial fishing industry) Onshore societal impacts (impact on neighbours to onshore dismantlement and disposal sites) Employment and regional development opportunities Offshore Societal Impacts The impact from full or partial sub-structure removal may be so small as to render the difference effectively insignificant in societal terms. In terms of interactions with other sea users during the execution of the decommissioning project, the complete removal option will require more vessels on station for longer periods of time than the partial removal option, presenting an increased potential for vessel collision, obstruction of usual access, etc. However, with deployment of appropriate mitigation measures, it may be the case that the difference in vessel days between decommissioning options results in no real difference in impact magnitude Onshore Societal Impacts There may be disturbance to communities onshore in close proximity to decommissioning yards and waste treatment facilities. As much of the detail around the disposal of the sub-structures is currently unknown, the number of trips and quantity of material to be disposed of has been used as the comparator; on such a basis the potential for negative impact is increased for the complete removal option relative to partial removal. However, resulting issues should largely be mitigated and managed within existing site environmental management plans and permits. It must be noted that there are likely benefits to local communities through the associated increase in employment and other direct/indirect economic activities; the duration and volume of work associated with complete removal is likely to have a greater positive benefit to communities than partial removal. 34 of 52

35 6.1.7 Sub-structure Economics The economics associated with the decommissioning of the sub-structure are primarily based on cost impacts and are expressed as costs valued in today s currency. It is important to develop representative cost estimates based on current industry experience, but this information will not be used as a prime differentiator. It is included in the comparative assessment process for completeness and a measure of proportionality when considering the other four criteria. For the purpose of cost estimating, the costs associated with the removal of the sub-structure have been assumed, in line with industry normal practice, to be directly proportional to the weight to be removed. This therefore results in the costs associated with full removal being marginally underestimated as it does not include the costs associated with the cutting of the steel piles or any ground (sea-bed) preparatory works. However, for comparative assessment purposes this is considered an appropriate and balanced assumption. Brae Alpha Brae Bravo East Brae Full Removal 100% 100% 100% Partial Removal 56% 56% 41% Note: the economics have been based on a cut and lift solution for all platforms in both the full and partial removal cases, and on 2015 estimates. Absolute costs have not been presented as these are considered commercially sensitive. Table 6 4 Comparison of Costs between Full and Partial Sub-structure Removal 100% 100% 100% 100% 80% Relative Cost 60% 40% 56% 56% 41% 20% 0% Brae Alpha Brae Bravo East Brae Full Removal Partial Removal Figure 6 8 Comparison of Costs between Full and Partial Sub-structure Removal 35 of 52

36 Brae Area Decommissioning Overview Report 6.2 Sub-structure HAVR Hazard Assessment Verification Review The principal aim of the HAVR was to identify major hazards for each potential method of sub-structure removal. The HAVR was completed as a structured brainstorming workshop. However no discussion was curtailed and hazards that will require management once detailed engineering and decommissioning plans have been developed were recorded and added to a risk register to ensure they are managed in the future. The study assessed the hazards to a detailed level that would facilitate comparative assessment between the removal options and to verify that the hazard had been accounted for in one of the studies undertaken. Where a gap was identified, an action was taken and appropriate assessments completed outside the workshop to close the gap. The team that took part in the workshop included the following competencies: Management Compliance Technical Safety Occupational Health and Safety Sub-sea Environment Structural Decommissioning Twenty recommendations arose from the HAVR workshop. The most critical actions were those pertaining to understanding the scope of diving activities required for sub-structure removal. It was concluded that should full sub-structure removal be required, there was a high probability that divers would be required to support the cutting of the sub-structure structural piles as the configuration and complexity of the structure prevented access by a suitably sized work class remotely operated vehicle (ROV). These, and the other findings, were fed into the relative assessments presented in this document. 7. Drill Cuttings Drill cuttings are the broken pieces of solid material removed from a borehole as it is drilled. Drill cuttings are produced as the rock is broken by the drill bit advancing through the rock. The cuttings are usually carried to the surface by drilling fluid circulating up from the drill bit. Historically, drilling fluids have been oil based, but this was phased out to water based fluids in accordance with changes in regulations that prohibited cuttings contaminated with oil being discharged to the seabed. OSPAR Decision 2006/5 requires all cuttings piles to be screened. Piles below specified thresholds (or with no oil based drilling muds) can be left to degrade naturally. All three Brae Area installations have a drill cuttings pile located within the sub-structure. These range in size and volume. The sub-sea tie-backs (West Brae, Central Brae and Braemar) have no cuttings piles; this has been confirmed by survey and ROV footage. Three dimensional surveys have been completed for the three platform cuttings piles and the size and volume are presented in Table 7-1. Field Height (m) Seabed Area (m 2 ) Estimated volume of cuttings (m 3 ) Brae Alpha ,700 28,000 Brae Bravo 8 17,000 22,500 East Brae 9 6,900 12,300 Braemar No cuttings pile West Brae Area No cuttings pile Central Brae No cuttings pile Table 7 1 Drill Cuttings 36 of 52

37 Platform North Figure 7 1 Brae Alpha Drill Cuttings 3D Survey Image Platform North Figure 7 2 Brae Bravo Drill Cuttings 3D Survey Image 37 of 52

38 Brae Area Decommissioning Overview Report Platform North Figure 7 3 East Brae Drill Cuttings 3D Survey Image 38 of 52

39 Figure 7 4 Representation of Brae Alpha Cuttings Pile Interaction with Sub-structure Seabed surveys have been conducted in the Brae Area throughout the life of the field. These have demonstrated that pollution within the sediments, including total hydrocarbon concentrations (THC), is low in the area although THC and barium have previously been recorded at elevated levels. Recent desktop studies have found that contamination from the cuttings piles in the Brae Area does not exceed OSPAR thresholds, and that sediment hydrocarbon concentrations and faunal distribution has improved since the cessation of discharge of cuttings contaminated with oil in Since the 1990s, environmental surveys have shown that THC has declined substantially, although barium does not appear to have changed to such a degree. There are three methods for drill cuttings management: 1. Leave in-situ to degrade naturally within the marine environment 2. Redistribute the drill cuttings over a wider area, thus removing the pile 3. Recover the drill cuttings to the surface, treat them for any contamination and transport onshore for reuse or disposal During 2013 and 2015, a full suite of seabed samples and drill cuttings pile core samples have been taken and analysed to further support the decision-making process and assessment of which of these management options is most appropriate. In order to support the evaluation process, a Net Environmental Benefit Analysis (NEBA) has been completed (Section 7.3). 39 of 52

40 Brae Area Decommissioning Overview Report 7.1 Seabed and Cuttings Analysis Results Seabed sediments in the Brae Area indicate a gradient in sediment type from finer and muddier in the north, to coarser sediments with less mud in the south. Sediments contain a low level of organic matter and carbonates. There was no indication of the sediments being modified through the platform or infrastructure activities and can generally be considered background for the central North Sea region. Sediments around the installations exhibited a background of recent and weathered, low level petroleum and biogenic hydrocarbons commonly found in marine sediments of the central North Sea. A number of inner stations (those nearest the platforms) showed evidence of lowtoxicity drilling fluid, with some showing an input of weathered diesel/lubricating oil to the sediment. The concentrations of metals in the sediments are relatively constant throughout the Brae Area. Any elevated levels found were at the sample locations nearest the platforms which is likely to be a result of the discharge of barites and associated trace metals (weighting agent in drilling muds) during drilling operations (see Section 7.2). In general, the metals concentrations of the sediments could be ascribed as within the range of natural background levels and of no obvious environmental concern. The benthic community identified in the Brae Area is largely dominated by the bristle worm Paramphinome jeffreysii, with other species present, such as Spiophanes bombyx, Galathowenia oculata, Tharyx killariensis and Pholoe assimilis. Paramphinome jeffreysii is a scavenger species and is found throughout the North Sea in areas of soft sediment at water depths greater than 50m. It is tolerant of high hydrocarbon levels, often present in areas impacted by oil contaminated drill cuttings, as one of the first species to recolonize such areas. The long lived bivalve (>100 years), Arctica islandica, was identified in low abundances across the East Brae survey area (mainly juvenile specimens). This bivalve is an OSPAR listed species known for its slow growth rate and long lifespan. This bivalve is known to occur throughout the UK waters (>30m) and was recorded in the East Brae survey area during the previous survey (2013). In general, the benthic community found in the Brae Area can be classed as representative of the central North Sea area. 7.2 Drill Cuttings Analysis Results Summary Coring at the Brae Bravo cuttings pile was undertaken using the standard technique of a vessel deployed vibrocorer. Several cores were recovered of approximately 3.5m. For the Brae Alpha and East Brae platforms, the drill cuttings piles are obstructed by the jacket and thus prevent the use of the vibrocorer. Instead, a piston corer was deployed directly from the platforms. Two cores were retrieved from each platform, with two in excess of 8m. Numerous surface grab samples and ROV push cores were also recovered from the cuttings piles. The following analysis was undertaken on the cores: Particle Size Distribution Carbonates Metals: Arsenic, Barium, Cadmium, Copper, Nickel, Chromium, Mercury, Lead and Zinc Hydrocarbons: Total Hydrocarbon Concentration (THC), Polycyclic Aromatic Hydrocarbons (PAH), Naphthalene, Phenanthrene, Dibenzothiophene (NPD) Polychlorinated Biphenols (PCBs) Endocrine Distruptors 40 of 52

41 Naturally Occurring Radioactive Material (NORM) Benthic (seabed) Macro-fauna Physical Characteristics The parameters have been selected as those most likely to be associated with impacts from offshore operations and those of current interest to OSPAR monitoring programmes. Hydrocarbons are an important constituent of cuttings waste material and have been indicated as the main cause of acute toxicity exhibited by oil based fluid cuttings. The level of sediment hydrocarbons will have a strong influence on whether a viable benthic community is able to exist on the seabed. Endocrine disrupting chemicals are substances that alter the function of the endocrine (hormone) system and produce adverse developmental, reproductive, neurological and immune effects on humans and wildlife. They include chemicals related to the oil and gas industry. High levels of metals are normally found in drilling waste, derived from barites used in the preparation of drilling mud. These elements can have a direct toxic effect on marine organisms when present at high levels and their concentrations (most notably barium) can be used to assess the spatial distribution of cuttings on the seabed. There are a number of potential sources of radionuclides in the marine environment including naturally occurring radioactive material (NORM). The primary source is from produced water discharges. Precipitation of NORM scale may also occur in production equipment which may be subsequently discharged to sea. Biological analysis of the macro-fauna show how the contaminants present have affected the seabed communities in the area. In addition, the presence of burrowing animals increases the disturbance of the surface layer of the seabed which can contribute to increased biodegradation of any underlying organic contamination. A total of 38 surface grab samples, 5 ROV push cores, 3 vibrocores and 4 platform based piston cores were collected from the Brae Alpha, Brae Bravo and East Brae drill cuttings piles. Table 7-2 provides a summary of the key findings from the survey. Analysis Particle Size Distribution Key Observations Brae Alpha Brae Bravo East Brae Little variation throughout the pile. Classified as extremely poorly-sorted fine sands. Carbonates Metals Hydrocarbons Polychlorinated Biphenols (PCBs) Endocrine Disruptors Low. Elevated levels of all metals when compared to central North Sea background seabed levels. Elevated compared to central North Sea background seabed levels. Levels of a kerosene-like low toxicity oil based fluid (LTOBF) present at various stages of degradation. Low with most below detection limits. Octylphenol levels were lower than values quoted from OSPAR monitoring in the Baltic and Irish Seas. Elevated levels of nonylphenol present. Most results for organotins were below detection limits although detectable levels of tributyltin found in some surface grab samples. 41 of 52

42 Brae Area Decommissioning Overview Report Analysis Naturally Occurring Radioactive Material (NORM) Benthic Macro-fauna Key Observations Background level. The number of macrofauna taxa identified across the piles were low and consistent with communities found on similar cuttings piles in the North Sea. Dominant taxa included polychaetes (Capitella sp, Paramphinome jeffreysii and Cirratulus cirratus) and the bivalve Thyasira sasrsi. Some survey stations contained anemones (Actinaria spp) on dead Mytilus shells which had fallen from the jacket. Table 7 2 Brae Area Drill Cutting Sampling Findings Overall, the data obtained indicates that the sediments are heavily modified from background seabed but could generally be described as typical for cuttings piles at North Sea platforms. 7.3 Drill Cuttings NEBA A NEBA (Net Environmental Benefit Assessment) on the management options associated with the drill cuttings piles at the three Brae Area platforms has been completed. This analysis is preliminary in that, although the data indicates the likely outcome, not all sampling data and measurements have been finalised. The options considered in this analysis were: Leave in-situ to degrade naturally within the marine environment Redistribute the drill cuttings over a wider area, thus removing the pile Recover the drill cuttings to the surface, treat them for any contamination and transport onshore for reuse or disposal A NEBA is a comprehensive, objective, scientific, transparent and quantitative approach to comparison between alternative actions, incorporating internationally recognised concepts and approaches. The NEBA framework incorporates ecosystem service valuation concepts, from which the effects of alternative actions on the environment can be quantified and compared. The basic objective of a NEBA is to assist in understanding how actions affect the environment so that solutions that maximise benefits to the environment and the public can be developed while managing site risks and costs. Incorporation of ecosystem service valuation concepts within an alternatives decision-making process provides decision makers with an opportunity to make informed choices about the net benefits of actions that affect the environment. An informed approach is: Systematic Transparent and understandable to stakeholders Non-arbitrary Scientifically-based and defendable Quantitative in nature where possible Based on internationally recognized concepts and approaches Considerate of all stakeholder concerns and thus, provides a holistic perspective to decisionmaking. 42 of 52

43 The NEBA approach is used to help balance the risks, benefits and trade-offs associated with competing alternatives. Net environmental benefits are the gains in ecosystem service value (ecological and human use services or other properties) attained by an action minus the value of adverse environmental effects caused by the action. The NEBA framework provides a systematic process for quantifying and comparing the ecosystem service benefits between competing alternatives, relying on both non-monetary and monetary metrics. As such, a NEBA incorporates the use of established ecosystem service valuation methods to evaluate changes in the flow of ecological and human use services associated with an alternative over time (i.e., benefits and impacts over time). The Brae Area NEBA considers the following parameters: Physical impacts on the habitat associated with the cuttings piles Chemical risks associated with contaminant exposures from the cuttings piles Physical and chemical effects on adjacent soft bottom habitat Physical effects of the options on vertical habitat structure Health and safety risks (potential loss of life) Greenhouse gas (GHG) emissions Human use value (commercial and recreational) Technical feasibility of the options Based on the information available to date, the preliminary results of the NEBA indicate that leaving the drill cuttings piles in-situ would be the best overall option. The NEBA analysis will be finalised and published before any final decisions are made. A summary of the preliminary findings is provided below and in Figure Redistribution of the drill cuttings piles will result in negative impacts on benthic habitats and communities through both physical (i.e., removal and smothering) and chemical effects from re-suspension of sediments and contaminants when compared to the in-situ option. In addition, this alternative would also increase GHG emissions and human health risks (implementation risks) while decreasing fish stocks and associated commercial values. 2. The recovery to surface and onshore treatment is the least desirable option as it also would result in negative impacts on benthic habitats and communities though physical (i.e., removal) and chemical effects from re-suspension of sediments and contaminants when compared to the in-situ option. In addition, this alternative would also result in the highest increase in GHGs and human health risks (implementation risks) of all options while also decreasing fish stocks and associated commercial values. 3. When compared to the above two options, the leave in-situ option provides the greatest net benefit for the factors considered as it minimizes ecological benthic and fisheries impacts, GHGs, human health risks, and losses of fish stocks and associated and commercial values. 4. There is a growing weight of evidence that supports the ability of offshore platforms to provide high value ecosystem services to the public. These services include fish production, protection of fish stocks from overfishing, the provision of food and associated commercial value, and the provision of conservation zones supporting multiple ecosystem trophic levels of invertebrates, fish, and wider ranging marine mammal populations (i.e., a variety of whales, porpoises, seals). 43 of 52

44 Brae Area Decommissioning Overview Report 50 Relative Value Compared to the In-situ Alternative Leave in-situ Cuttings displacement Recover to surface and onshore treatment PLL CO 2 (e) emissions NOx emissions SOx emissions Benthic Habitat Fish Production Figure 7 5 Preliminary NEBA Results 44 of 52

45 8. Pipeline and Sub-sea Infrastructure Decommissioning The pipelines and sub-sea infrastructure in the Brae Area are extensive (See Section 2.5.4, and Figure 2-11 and Figure 2-12). The larger pipelines are laid directly on the seabed while the smaller pipelines and umbilicals are generally laid in trenches in the seabed. The smaller lines were originally laid in trenches to protect them from damage due to dropped objects or impact from fishing net trawl-boards etc. The larger pipelines do not require this protection as they are sufficiently robust to withstand these types of impact. Some of the pipelines are concrete coated. This coating provides ballast that stabilises the lines on the seabed. Sub-sea wellheads and manifolds are protected from damage by fabricated steel structures that may be secured in place by structural piles. Other sub-sea facilities are protected and stabilised by concrete structures, concrete mattresses (flexible concrete mats weighing several tonnes), grout bags (of various sizes) or by rock cover which consists of small pieces of quarried rock placed over the protected item in a berm. There are also a number of prefabricated steel and concrete structures sub-sea that form bridges to support pipelines at crossings or at the base of the platform sub-structures. Outside the installations 500m safety zones, sub-sea protection and stabilisation features are designed to provide protection against fishing gear impact. 8.1 Pipeline and Sub-sea Infrastructure Regulatory Requirements The regulatory requirements covering decommissioning pipelines and sub-sea infrastructure differ from those concerning decommissioning platforms. There are no international regulations or guidelines that specifically cover pipelines. However, in the UK, the Petroleum Act [14] governs the decommissioning of offshore oil and gas facilities including pipelines and other sub-sea infrastructure and the DECC guidance [2] sets out its requirements for decommissioning of such equipment. DECC s base line expectations are that all sub-sea structures should be removed unless buried or exceptional and unforeseen circumstances are also present where pipelines are larger than 12-inches in diameter e.g. structural damage or deterioration, and that a comparative assessment should be made of the decommissioning options for pipelines using the criteria set out in OSPAR decision 98/3 [1]. The impact of pipelines on the marine environment was added to the OSPAR Joint Assessment and Monitoring Programme 2014 to Pipeline and Sub-sea Infrastructure Comparative Assessment Methodology Marathon Oil s approach to determining the preferred decommissioning options for pipelines and sub-sea infrastructure is founded on comparative assessment. Marathon Oil will use comparative assessment to select the overall preferred option, which may be one of a number of removal options, or the potential option of leaving the infrastructure in place. A typical sub-sea pipeline in the Brae Area consists of a number of sections or segments. These can include: A riser at one of the platforms A sub-sea pipe spool connecting the base of the riser to a sub-sea isolation valve within a protections structure A surface laid section of pipeline protected by concrete mattresses or rock cover A trenched section of pipeline; a second section of surface laid pipeline protected by rock cover or concrete mattresses Another pipe spool connecting the pipeline to a sub-sea well 45 of 52

46 Brae Area Decommissioning Overview Report Marathon Oil s approach to comparative assessment for the Brae Area pipelines and sub-sea infrastructure consists of the following main steps: Preparing of a definitive list of sub-sea pipelines and infrastructure Defining a comprehensive list of segments that describes all of the sub-sea assets and their constituent parts; e.g. surface laid pipeline, trenched and buried pipeline, structure, etc. Conducting a comparative assessment for each segment in the list Dividing each actual sub-sea asset into its constituent segments Comparing each segment of the sub-sea asset to the relevant segment comparative assessment to determine the preferred decommissioning option for that segment Carrying out a sense check to ensure that the segment comparative assessment is appropriate for the sub-sea asset being considered, and to identify any interdependencies between segments that may modify the conclusions of the sub-sea asset comparative assessment In instances where it is found that there is a part of a sub-sea asset with no matching segment comparative assessment a specific assessment will be conducted. The segment comparative assessments were carried out by a team of subject matter experts in the areas of safety, environment, sub-sea and operations, and included stakeholder representatives. Marathon Oil has consulted stakeholders throughout the comparative assessment process and has received positive and supportive feedback. Marathon Oil s approach to comparative assessment broadly aligns with O&G UK guidance [19] Assessment Outcomes The sub-sea facilities comparative assessment process resulted in a range of preferred decommissioning options, depending on the type of segment under consideration. The preferred options range from leaving equipment in-situ as it is with no intervention other than continuing monitoring and inspection. This would be the option in the case of a securely buried pipeline that is at low risk of forming spans. At the other extreme the preferred option may be complete removal of some items of equipment that pose an intolerable risk to fishermen, for example small structures protecting pipeline junctions that are a snagging hazard for fishing nets. The comparative assessment process also identified a number of intermediate options for certain segments. These include trenching some pipeline segments in-situ, burying other types of segment, and relocating some protection and stabilisation features or removing them to shore. In certain instances there is not a clearly preferred option for a particular segment type The preferred options will be kept under continual review until decommissioning takes place. For a specific segment the preferred option may change as a result of improvements to technology or maturing technology, as a result of changes in the state of knowledge regarding the sub-sea facilities, or because of changes to legislation or other external factors. The resources available to a decommissioning contractor and the final schedule for the decommissioning activities may also influence the selection of the ultimate preferred options. All of the decommissioning options include a monitoring and inspection element. In the case of equipment that is removed, the inspection and monitoring commitment is limited to an inspection of the area once the removal is complete. In the case of any equipment that is left in-situ there will be a continuing requirement for monitoring. If the status of the equipment changes, for example if a pipeline that was thought to be securely buried shows signs of forming spans, then the frequency and type of monitoring required will change to reflect this. 46 of 52

47 9. Environmental Impact Assessment 9.1 Regulatory Context An Environmental Impact Assessment (EIA) is an integral part of the Decommissioning Programme application as detailed in the DECC guidance [2]. The Brae Area Decommissioning project will be supported with a single integrated EIA. This will be reported in Environmental Statements (ES) to align with the Decommissioning Programmes that are to be submitted. 9.2 Proportionality in EIA Standard practice, governed by published guidance [12][13] and previously applied project specific methodologies within industry [10][11] has developed for the application of EIA to oil and gas infrastructure projects. The EIA for the Brae Area decommissioning activities will be delivered within this framework of current regulatory guidance and the context of current good practice. However the EIA will review and challenge standard practice where appropriate and has been designed to seek and identify areas for additional streamlining/improvement throughout the delivery process. The result will be a focused and proportionate EIA process that is targeted to the specific requirements of the Brae Area Decommissioning Programmes and that takes full account of existing data and prior knowledge of anticipated impacts as well as established mitigation procedures. 9.3 The Enhanced Role of Scoping and Consultation As a key enhancement of current practice, the EIA strategy adopted by Marathon Oil incorporates a two stage scoping and consultation process to achieve sufficient acuity and insight without overworking consideration of the issue either individually or in combination with others. The EIA has been scoped utilising and adapting the Environmental Risk Assessment (ERA) approach designed to determine potential environmental risks and to compare the different options that are currently under consideration for decommissioning of the Brae Area facilities. The scoping stages are: Preliminary scoping (Stage 1). This stage provides high level consideration of anticipated decommissioning activities at the Brae Area at its widest extent against a broad range of potential environmental receptors Detailed scoping (Stage 2). This stage provides an additional level of scoping consideration for those potential effects which may be acceptable, but only if further investigated and/or appropriately mitigated through the implementation of best practice/generic mitigation This two-stage scoping offers an enhanced opportunity for the EIA process to respond when the balance of proof is reached in relation to an individual issue, thereby improving the opportunity to avoid unnecessary inclusion of lengthy and detailed discussions of potential issues within the ES, only to conclude a low or no likelihood of significant effect. Stage 1 objectives: Identify activity/receptor interactions considered to be high risk and therefore require inclusion within the EIA technical studies Identify activity/receptor interactions identified to be medium risk and therefore are required to be carried forward into the Stage 2 Detailed Scoping process for further consideration, and subsequently either scoped into or out of the EIA technical studies 47 of 52

48 Brae Area Decommissioning Overview Report Identify activity/receptor interactions considered to be low or insignificant risk, or of no impact/positive ratings and which can therefore be scoped out of further consideration within the EIA as they are considered unlikely to result in significant environmental effects Stage 2 objectives: To further evaluate activity/receptor interactions initially identified as medium risk in order to provide further clarity on the potential for significant effect Detailed technical studies will then be conducted for all the elements remaining within the scope for the EIA. Final results will be delivered within the ES(s). Any generic or best practice mitigation on which the scoping decision depends will be itemised in the schedule of commitments within the ES(s). 10. Waste Management In order to comply with all relevant legislation, to minimise waste and to optimise re-use/ recycling opportunities, a Waste Management Strategy (WMS) will be developed. The WMS will identify a route map for the management of wastes resulting from the decommissioning process. The primary objectives will be: Protection of the environment and compliance with environmental and waste legislation and industry standards in order to satisfy Marathon Oil UK s Duty of Care Stakeholder satisfaction (e.g. customer/client/regulatory authority) in relation to their expectation of continual improvement in environmental and sustainability management. This includes meeting project targets and objectives with respect to waste management Deliverance of a resource efficient decommissioning process, achieving both waste reduction and improved business efficiency and cost savings. Figure 10-1 Waste Hierarchy 48 of 52

49 11. Brae Area Decommissioning Proposed Timeline A number of factors can influence and may change the planning basis CoP, suspension and decommissioning dates, including: Commodity price Production levels Operating costs Other opportunities Detailed timings for the execution of the decommissioning scopes is yet to be developed. There are many factors that must be evaluated to ensure maximum efficiency is achieved from the operations associated with the assets, and complex commercial arrangements must be managed to support other operations within the vicinity of the Brae Area. For the purposes of planning however the following key dates have been used to support the development of the decommissioning programmes. All platform wells that provide no further utility will be plugged and abandoned before CoP All remaining platform wells will be plugged and abandoned as efficiently as possible immediately following CoP Subject to the gas management requirements within the field, Brae Bravo may remain in warm 7 suspension (non-producing, but still with limited hydrocarbon processing on board, such as gas transfer pipework) for the period that it is required to convey hydrocarbons to/ from Brae Alpha. East Brae is likely to be the first topsides to be removed in this scenario Brae Bravo topsides may be removed before or after Brae Alpha subject to market conditions and vessel availability All sub-structure will be removed as a campaign Scope is to be determined by the substructure comparative assessment process Sub-sea wells will be plugged and abandoned to align with the host platform CoP and as the market availability of appropriate vessels allows subsequent to that date. Note, sub-sea wells will be formally suspended if left for any significant duration prior to final abandonment All pipelines, umbilicals and sub-sea infrastructure may be removed or left in-situ (as determined by the appropriate comparative assessments) based on market conditions and vessel availability with the intent of any removal prior to sub-structure removal 7 The platform is fully isolated from the reservoir and majority of incoming pipelines, but may still have some process hydrocarbon processing on-board. 49 of 52

50 Brae Area Decommissioning Overview Report Task Internal Stakeholder Engagement - Introduction to Brae Area Decommissioning Planning External Stakeholder Engagement - Introduction to Brae Area Decommissioning Planning Expected Date Apr 2015 Apr 2015 Brae Decommissioning Planning website goes live May 2015 On-going engagement and updates to all stakeholders May Nov 2015 Issue of Brae Area Decommissioning Overview Report Nov 2015 Formal Stakeholder feedback opportunity Nov Jan 2016 Review of formal (and all previous) feedback. Provide responses as appropriate Implementation/inclusion of feedback into Comparative Assessment process Jan 2016 Feb 2016 Jan Mar 2016 Conduct jacket derogation Comparative Assessment workshop Mar 2016 Issue Jacket derogation Comparative Assessment reports May 2016 Issue of 1st draft Decommissioning Programme to DECC Jun 2016 Issue of 2nd draft (for consultation) Decommissioning Programme to DECC Oct 2016 Table 11 1 Stakeholder Engagement Timeline 50 of 52

51 12. References [1] OSPAR: [2] Guidance Notes Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998 Version 6 March 2011, DECC [3] 9000-MIP-99-PM-RT Brae Area Decommissioning comparative assessment Process, November 2014, Marathon Oil Decommissioning Services LLC [4] 9000-MIP-99-PM-RT Brae Area Installation Reuse Review, Marathon Oil Decommissioning Services LLC [5] 9000-MIP-99-PM-RT Brae Area Platform Jacket Reuse Review, Marathon Oil Decommissioning Services LLC [6] 9000-ATK-99-ST-TN Brae Field Jacket Weight Technical Review & Summary For Decommissioning, Marathon Oil Decommissioning Services LLC [7] HSE, Reducing Risk, Protecting People, HSE s Decision Making Process, HSE Books 2001, ISBN [8] FishSafe - [9] Kingfisher Information Services - [10] BP Miller Decommissioning Programme - where-we-operate/north-sea/north-sea-decommissioning/miller.htm [11] CNR International Murchiuson Decommissioning Programme - [12] DECC (2009): Guidance Notes on the Offshore Petroleum Production and Pipelines (Assessment of the Environmental Effects) regulations 1999 (as amended). [13] UKOOA (1999): A framework for risk related decision support industry guidelines, UK Offshore Operators Association. [14] Petroleum Act [15] Oil and Gas UK: OP071 - Guidelines for the suspension and abandonment of wells, Issue 4, July 2012 and Guidelines on qualification of materials for the suspension and abandonment of wells, Issue 1, July 2012 (2012) [16] 9010-GEN-99-PM-RT , Brae Bravo Sub-structure Comparative Assessment Executive Summary, Marathon Oil Decommissioning Services LLC [17] 9030-GEN-99-PM-RT , East Brae Sub-structure Comparative Assessment Executive Summary, Marathon Oil Decommissioning Services LLC [18] 9020-GEN-99-PM-RT , Brae Alpha Sub-structure Comparative Assessment Executive Summary, Marathon Oil Decommissioning Services LLC [19] Oil and Gas UK: Guidelines for Comparative Assessment in Decommissioning Programmes, Issue 1, October of 52

52 9000-MIP-99-PM-XE Revision 1 MarathonBraeDecom@Marathonoil.com Printed copies should be used with caution. The user of this document must ensure the current approved version of this document is being used. Copyright Marathon Oil Decommissioning Services LLC. All rights reserved.