MSc. PETROLEUM ENGINEERING PROJECT REPORT 2013/2014 DIEGO NOROÑA H CHALLENGES IN THE DECOMMISSIONING ON THE NORTH SEA HERIOT-WATT UNIVERSITY

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1 MSc. PETROLEUM ENGINEERING PROJECT REPORT 2013/2014 DIEGO NOROÑA H CHALLENGES IN THE DECOMMISSIONING ON THE NORTH SEA HERIOT-WATT UNIVERSITY INSTITUTE OF PETROLEUM ENGINEERING Supervisor Dr Bahman Tohidi

2 2 Declaration: I, Diego Noroña, confirm that this work submitted for assessment is my own and is expressed in my own words. Any uses made within it of the works of other authors in any form (e.g. ideas, equations, figures, text, tables, programs) are properly acknowledged at the point of their use. A list of the references employed is included. Signed.. Date

3 3 ACKNOWLEDGEMENTS In the first place, I would like to express my deepest gratitude to my supervisor Dr Bahman Tohidi for all his invaluable support, guidance and pragmatic insight needed to succeed in the completion of this work. To the Petroleum Engineering lecturers and staff who have shared their knowledge and confidence during this course. Also, to the following companies who made accessible for public consultation the information published in the Department of Energy & Climate Change of UK website: BP plc, Endeavour Energy UK Ltd., Hess Limited, Energy Resource Technology UK (Limited), Mobil North Sea LLC, Perenco UK, Premier Oil, Shell U.K. Limited, Silverstone Energy Limited, TOTAL E&P UK Limited; without whom, this work could not have been completed. And finally but not last, to my family who have always been at my side providing me with constant encouragement, the strength to endure many challenges, and for the sacrifice that they made on my behalf.

4 4 SUMMARY The decommissioning of installations in the North Sea is a relative new market that will be developed in the near future due to the amount of platforms built since 1970 s. The intent of this document is to review the different technical aspects of decommissioning programmes in several fields looking for their outcomes and recommendations to compile the challenges that these face. Smaller tasks performed during the decommissioning can be grouped in categories such as well plug and abandonment (P&A), subsea and pipeline decommissioning, topsides and structures decommissioning being steel or concrete the principal construction material; and finally disposal of the removed items (Tularak, et al., 2007). Therefore, the fact that all platforms face unique design conditions then challenges to overcome them may be different. Removing the completion, plugging permeable zones, and removing the wellhead have their challenges such as creating a seal that isolates permanently several zones on the reservoir. Pipeline decommissioning presents the challenge of develop a method to retrieve the material in a safe and economical way; but, the inherent uncertainty of pipeline s structural integrity had played an important role on companies, making them choose an alternative option which is leave in place the buried pipelines. Topside and jacket removal has its biggest challenges in the engineering economic balance, reuse possibilities, disassembly methods, onshore transport, and disposal. All of these make a big impact not only on risk and environmental aspects but also on the expenditure required. Furthermore, safety concerns under incomplete tasks during the decommissioning face the challenge of creating a sound cut with minimal environmental impact and without affecting future regional activities but more importantly without exposing personnel to perils.

5 5 Management of drill cuttings during drilling activities has given good results when the option of leaving them on the sea bed for natural degradation is chosen, but the challenge of a more environmental friendly disposal is a constant in the industry.

6 6 Table of Contents Summary Aims Background Technical regulation Stages of decommissioning planning Extent of the removal Economy Consultation Environmental Review of decommissioning programmes Wells abandonment Drill Cuttings Facilities Discussion General Facilities verification Non-technical consideration... 30

7 7 5. Conclusions Suggestions for further work Appendices Appendix 1- figures Appendix 2 - tables Appendix 3. - abbreviations List of References List of Figures Figure 1 Distribution of installation in the UK North Sea Figure 2 Summary of wells abandonment at Figure 3 Topside removal cost comparison Figure 4 Number of platforms in the UK North Sea by Figure 5 HPHT reservoir discoveries Figure 6 Topside material decommissioned in UK North Sea by type and by programme Figure 7 Subsea & pipeline material decommissioned in UK North Sea by type and by programme... 37

8 8 List of Tables Table 1 First stage screening threshold values Table 2 Number and type of installations on the UK North Sea Table 3 List of Decommissioning programmes reviewed Table 4 Recommendation of decommission programmes Table 5 Tendency of Drilling Cuttings decommissioning Table 6 Summary of Topsides material inventory Table 7 Summary of subsea and pipelines material inventory Table 8 Summary of cost of recommended options (1 of 4) Table 9 Summary of cost of recommended options (2 of 4) Table 10 Summary of cost of recommended options (3 of 4) Table 11 Summary of cost of recommended options (4 of 4)... 46

9 9 1. AIMS Summarize and compare information from several decommissioning programmes in the UK North Sea. Summarize and identify possible challenges that can lead to new opportunities of investigation in decommissioning processes. 2. BACKGROUND The North Sea corresponding to the UK has more than 15000km of pipelines and 298 platforms with increasing numbers every year (see Figure 4). Based on the year of first oil production, around 100 structures have 30+ years of production, while more than 200 have more than 20 years. Overall, small structures (weight less than tonnes) surpass in number to larger platforms in more than 7:1 (See Table 2). Cost-wise, this activity forecasts expenditures close to 31.5 billion between 2013 and The decommissioning expenditure in 2012 money was around 2 billion and by now the total expenditure, including exploration and production, has reached over 500 billion since 1970 (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2013, pp. 8, 9); this gives a possible idea of size of this growing industry if the numbers of platforms also keep increasing TECHNICAL REGULATION The UK government has accepted and use the OSPAR decision 98/3, The United Nations Convention on the Law of the Seas 1982 (UNCLOS) as guidelines for the decommissioning of topside facilities and structures made of steel, concrete or others. The considered

10 10 categories of installations are: floating and subsea installations, fixed steel, and concrete gravity. Pipelines are not covered by the first document mentioned and the base for their decommissioning is the expressed by the Guidelines for the Removal of Offshore Installations (The International Maritime Organisation (IMO), 1989). Regulations for the environmental assessment and impacts of decommissioning are outside of the scope of this document. One of the biggest changes from the guidelines used before and after year of applicability of the regulation- is the classification of the structures by weight from 4000 to tonnes, and the actions approved after 1999 is the prohibition of partial removal or leaving the structures in place. However, it also contemplates the complex nature of the removal of large structures (fixed steel heavier than tonnes and concrete gravity type), especially those installed before the 9 th of February of 1999, and this option can be feasible only after an extensive study and with government approval. Outside of this consideration, all installations built after 1999 should be designed to be completely removed at the end of the project s lifetime. The last commentary is also applicable to concrete gravity structures for which sea disposal was an option before (Department of Energy & Climate Change UK, 2011, p. 33) 2.2. STAGES OF DECOMMISSIONING PLANNING The initial steps on field decommissioning are the engineering and planning; where the data is reviewed and compared with the actual equipment or programs performed on the field. Proposals for a programme arise and are evaluated under the criteria of environmental impacts, safety, technical and economic feasibility, and social impact.

11 11 This stage also comprises government discussions, interaction with society, stakeholders, contractor s technology review, etc., and the plan is reviewed by government and regulations departments to obtain approval. Once the data has been reviewed and discussed, the next step is to structure a Cease of Production (COP). In this stage the production stops, the topside inventory is performed, and the wells are plugged and abandoned (P&A). It has to be noted that the last two tasks can be performed during the life of the field and the planning stages before the COP. After obtaining the approval, the on-site works are planned and these will include the P&A of wells, subsea equipment and structures recovery, pipeline cleaning and removal, topside cleaning and removal, structures removal, and drill cuttings 1 treatment if it is considered necessary by previous assessment. When the works are finished, the Operator has to perform a survey or surveys and start with the monitoring phase to review the area and fulfilment of the decommissioning programme EXTENT OF THE REMOVAL The guidance notes of decommissioning oil and gas installations (Department of Energy & Climate Change UK, 2011, pp ) consider the following points: Topside and structures with a weight less than tonnes have to be removed completely. The piles should be severed at a depth from the seabed that ensures the remains are not going to be uncovered later on. 1 The normal practice is to deposit the drilling cuttings on the sea bed surrounding the platforms.

12 12 As it was mentioned before, structures heavier than tonnes and concrete gravity structures have a partial removal option, but both must ensure that the remains allow a minimum clearance of 55m from the sea level. This partial removal should be well justified by the Operator. The removed parts should be transported to land to be reused, recycled, or disposed according to the approved decommissioning plan. Subsea equipment is considered the same as steel fixed structures or concrete gravity and the same guidelines are applied. The normal practice is to remove the wellhead and structures from the seabed and casing strings are cut at a minimum depth of 10 ft. Although pipelines are not covered by the OSPAR 98/3, decommissioning guidelines suggest the consideration of points such as the pipeline not becoming a future issue while expecting to be buried, self-bury over the years, or not moving it from the actual location. Therefore, the analysis of the final option will depend of the configuration, type, location in relation with other installations and initial construction process. In case the option to leave it in place is approved, the Operator has to implement a monitoring program that can be revised in time depending on the circumstances. The Operator has to conduct a study to assess the impact of the drill cuttings disturbance; this report has to include, based on scientific principles, possible outcomes and the possibility of treatment of this waste. These assessments have to go through two stages where the first stage is a screening process based on threshold values (Department of Energy & Climate Change UK, 2011, p. 46), and the second one is the planning, evaluation and monitoring of the results.

13 13 Table 1 First stage screening threshold values FIRST STAGE SCREENING THRESHOLD VALUES Rate of oil loss to water column Persistence over the area of seabed contaminated 2 10 tonnes per year 500 km 2 yr The possible options for decommissioning are maintain in situ to remediate (e.g. cover and natural degradation), or transport to land to treat and dispose ECONOMY The market of facility decommissioning is growing in the North Sea with a forecast of expenditures of around 31.5 billion between 2013 and 2040 (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2013, p. 9). Taking into account that close to 100 installations have 30+ years of production and almost 200 have 20 years of production by now, the market has the possibility to grow quickly in this industry (see Figure 4) CONSULTATION Decommissioning processes have public consultation with third parties and other users of the sea; this has been addressed in programmes and proves to be a general concern of shareholders to obtain the best option to the analysis process. In this document, the review of that information will be not treated. 2 Interpreted as persistence in 1km 2 during 500 years or 500 km 2 during 1 year (Department of Energy & Climate Change UK, 2011, p. 124)

14 ENVIRONMENTAL The environmental impact is one of the biggest concerns when a decommissioning option assessment is performed. The main parameters of the programmes are the impact caused by the remains of the installations and drill cuttings on the ecosystem and other users of the area, necessary energy and CO2 emitted during the required removal and or recycling operations. In this document the review of this information will be not treated in detail. 3. REVIEW OF DECOMMISSIONING PROGRAMMES In order to summarize potential challenges, a review of several decommissioning programmes will be realized; with focus on available options, outcomes and recommendations derived from the analysis performed by the author of each one of them. Analysis of the possibilities will be performed if there is available information, otherwise a tendency of the outcomes will be shown. For this document the proposed review structure is: Wells abandonment, Drill cuttings pile abandonment, Facilities, considered as Topside, related structures and pipelines, Sense of economy. The list of programmes selected is based on the information available on the website of the Department of Energy & Climate Change of UK from 2006 to date (see Table 2). However, some of the programmes do not mention in detail the assessment for the selected option of well abandonment. Therefore, the review of wells P&A study will be carried on.

15 WELLS ABANDONMENT Part of the decommissioning programme is the permanent abandonment of wells. A common practice is to place permanent barriers with a measured depth (MD) of at least 100 ft. of good cement; this is typically placed considering the following: A first barrier to isolate potential inflow from the formation or formations should be placed. It should be located on the top of perforations or top of the formation considering its feasibility. An alternative is to place it at the closest point if the former solution is not possible. Place a second barrier to isolate shallow formations and be the backup of the first barrier. An acceptable barrier can be created with cement, but it has to have at least 100 ft. MD of good cement. Different permeable zones should be separated by a barrier. The casing annulus cement job must have at least 1000 ft. MD of good cement above a permanent barrier. Verification of the barrier or barriers should be done by several test or logs which are described in guidelines and standards such as NORSOK D-010 or Guidelines for the suspension and abandonment of wells (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2012) It is important to notice that the final design and variants have to consider the appropriate solutions to ensure safety for a temporal or permanent abandonment and avoid unplanned fluids escape (Health and Safety Executive, 2008, pp. 10, 11). Many companies are aligned with these practices and guidelines, and this is mentioned in the decommissioning programmes.

16 16 HIGH PRESSURE HIGH TEMPERATURE WELLS (HPHT) The Department of trade and industry define as HPHT developments those with conditions of more than psi and or 300 F (Health and Safety Executive, 2005, p. xi); with several discoveries of this type of reservoirs in the North Sea (see Figure 5). For HPHT wells the same guidelines are used, but their nature introduces conditions which need to be carefully analysed because the trend of developing these fields may increase in the future (Health and Safety Executive, 2005, p. 2). These conditions of the reservoirs add factors of complexity to the field development as well to the future decommissioning, which in turn presents the challenge of selecting a technology that can achieve a fast and reliable result. Hence obtaining a good cement job on these conditions is a constant challenge for wells development and P&A. An appropriate selection of technology used to plug and cement the wells must be developed for each case, as experiences in other regions can show. (Rudnik, et al., 2013) For wells crossing the Hod formation, in order to reach the reservoir prospect it is necessary to have a historic record of this zone s behaviour during its producing lifetime for the sake of avoiding future challenges in the decommissioning. Possible pressure increments in the annuli may occur after plugging the well. (Health and Safety Executive, 2005, p. 22) 3.2. DRILL CUTTINGS The cuttings from many of the platforms in the North Sea are usually left on the seabed surrounding the platform. After the removal of the structures, these cuttings on the seabed have the possibility of being disturbed by other sea users and produce particle movement or traces of hydrocarbon (HC) releases known as HC loss.

17 17 In shallow water, trawling can produce the disturbance of the cuttings, but preliminary monitoring and simulation studies have reached a conclusion of low calculated values and possible low measures of a severe environmental impact. This conclusion was reached with the use of a tracer agent which was measured up to 2km from the origin and comparison with the results obtained from a particle deposition simulation. (OSPAR Commission, 2009, p. 6) Dredging operations can create a HC loss between 5 to 200 times compared to when cuttings are left undisturbed. On the other hand, trawling operations produce low values similar in order of magnitude as the ones presented when cuttings are left undisturbed on the seabed, e.g. an study of cuttings from Ekofisk and Albuskjell fields show a HC loss of 0.5 tonnes per year and trawling operations a HC loss of 0.2 ( (OSPAR Commission, 2009, p. 7) FACILITIES TYPES OF FACILITIES The North Sea installations are diverse but in major quantities these are steel structures or jackets; this represented the 89% of the facilities in 2011, and as it was seen before, they are increasing with time. From this, the greater part is formed by small steel structures with a weight lower than tonnes and the 10% consist of large structures above the tonnes.

18 18 Jackup 1% Concrete Gravity Based 3% Process Storage & Offloading FPSO 5% semi sub. Process Facility 2% Type of structures in the North Sea UK at 2011 Steel Structures 89% Large Steel 10% Small Steel 79% Figure 1 Distribution of installation in the UK North Sea (Department of Energy & Climate Change UK, 2011) From these values, it is the possibility of reuse what comes to mind, but in the North Sea this has not been the case so far based on the conclusions from most of the decommissioning programmes reviewed. REUSE OF FACILITIES The reuse of facilities is an option to reduce environmental impact and try to obtain revenue from decommissioned equipment. For concrete structures, which are large installations, the reviewed decommissioning programme has found that leaving them in place presents the best of the options analysed (TOTAL E&P UK Limited, 2007, pp. 153, 154). Hence, the reuse option for this type of installations has not been addressed by the reviewed programmes. In case of reuse, these installations have to manage uncertainties and risks related to removal, transport, and re-floating operations. Nevertheless, in the actual regulation, the use of them has to have a justification based on technical, safety parameters and feasibility of removal (Department of Energy & Climate Change UK, 2011, p. 36).

19 19 For steel structures or jackets a common aspect of the decommissioning programmes reviewed is the lack of opportunity for reuse (see Table 4). In few of them, the assessment of this option has concluded that it is not economically viable due to environmental and location constrains, maintenance costs required during the remaining life of the structures. (BP plc, 2006, pp. 9, Sec 6). In the case of topsides, it is more common the reuse of their parts because an overall view of these facilities show that the process is based on older technology and individual elements can still be useful. Nevertheless, the complete reuse is not out of possibilities as it was stated in the Welland field decommissioning programme (Perenco UK, 2010, p. 25). Floating production, storage and offloading (FPSO) on the other hand have open possibility for reuse because of the nature of the equipment. This possibility gives a great advantage compared to the platforms due to the majority of the work being related to the connections removal from the rest of the facilities compared to the topsides removal which may require more effort. For pipelines the reuse is limited and neither of the reviewed plans state a specific use rather than further considerations will be carried on. It is important to take into account that some of past programmes do not recover all the material, and only the exposed parts and connections spools are retrieved. The rest is comprised by the buried pipeline and the recommendation of programmes is to leave them in place. RECYCLE OF FACILITIES The next environmental approach on the destination of installations apart from the reuse is the recycling and a review of the material inventory from several decommission programs should be carried to identify the best possibilities.

20 20 The objective is to try to obtain a point of view of the range of possibilities that companies faces when a decommissioning plan has to be analysed. Figure 6 and Figure 7 show the different materials reported in the decommissioning programmes; from these it can be seen that steel, carbon steel and structural steel, represent more than 60% for topsides and up to 80% in the case of subsea equipment and pipelines. A jacket, concrete and FPSO comparison is not necessary because the most used material in the structure will define the type of analysis required. The outcome from the programmes is to recycle the majority of materials if it is attainable (e.g., the concrete coating of pipelines can be removed and leave the bare metal to recycling). The lower portion of material may present contamination due to heavy metals, Normally Occurring Radioactive Material (NORM), etc., should be treated and disposed (Energy Resource Technology (UK) Limited, 2013, p. 14). INSTALLATION REMOVAL As it was mentioned before, the removal of installations has three options at the moment: complete removal, partial removal leaving a minimum clearance of 55m, and leave in place. However, the last two are available only under certain circumstances and government approval. The reviewed programmes state a complete removal for structures with a weight less than tonnes, and for structures above this weight, partial removal, leaving the footings in place, has been recommended as the most suitable option. In the majority of programmes the uncertainty of achieving a reliable cut in the footings, characterized by their big thickness, and the increase in the risk of shortcoming in the technology to realize a complete removal also influence on the selection of the removal

21 21 method; this makes the safest option to remove the structure from certain depth and leave the footings in place. However, the programmes address the challenge of removal of the rest of the structure by sections using underwater cutting which also requires a study of the effect of reduced stability on the structure when its parts are removed (BP plc, 2011, p. 13) (BP plc, 2006, p. 15). In the reviewed cases, the single lift is also an uncertainty because of the lack of experience for large structures removal using this method and it could lead to an increase in risk perception during the analysis. The trend on decommissioning this type of structures is offshore deconstruction for large structures and complete removal for the small ones in accordance with regulations. For concrete structures, the same options and considerations are available, including the disposal at sea, but the current regulation has restriction of their use as it was mentioned before. The topsides, on the other hand, have to be removed completely and programmes consider the option of offshore dismantling, reversal installation or removal as a complete unit. The latter requires structural reinforcement of the topsides structures, especially in old installations, to be able to withstand the removal operations. The comparison based on risk, environmental impact, and extent of work until now has been based on the fact that the technology for a single lift removal is not available at that moment but in the future it may change and new programmes may address this as an option. Table 6 and Table 7 contain a summary of subsea and pipeline materials and give the total weight to recover, but the net amount that will be recovered from the total isn t specified in

22 22 some of the programmes. This list is also comprised by the material of well structures, wellhead, casing, and pipelines. The analysis carried by each company reflects that the major concern of pipelines is the uncertainty in their capability to be removed by S-lay and J-lay procedures because these procedures impose extra stress to the pipeline. The basis of both methods is to use a vessel to cut and recover the lifted sections of pipe which will be transported to land later on. However, an alternative method to the S-lay and J-lay is the subsea cutting and lifting which will be dependent on the underwater cut effectiveness. For umbilicals, the recovery process is similar to pipelines and many of programmes also have studied the method of reeling which consists in lifting the cable and then use a reel to transport them to land. After the assessment, many programmes agree that a partial removal is a safe and environmental friendly option for decommissioning. During the review of decommissioning plans it is possible to recognize influences from several factors such as the weight of the structure, weather and availability of lifting and transport vessels which were also identified by previous publications (Coleman, 1997, p. 97). 4. DISCUSSION 4.1. GENERAL The programmes reviewed present the summary of key information required by the government to analyse the impact of decommissioning in several levels. The use of government and industry guidelines or practices gives a structured way to compile information, but in some cases it is only superficial or not mentioned at all (e.g., the cost description).

23 23 Thus, the current information will be useful to identify trends, but it won t lead to conclusive data because it may be influenced or biased by the number and type of decommissioning programmes reviewed. In the case of risk and environmental assessment the guidelines to calculate values of environmental impact such as emissions and energy necessary are well delineated, hence it is possible to think that values can be comparable to a base measure. However, on several of the reviewed programmes the base value is not equal for all of them concluding that values from emissions are low (e.g. MCP-01 equivalent CO2 emissions are compared to the total UK Offshore operations, Miller compares against the UK household emissions and Rubie and Renee compares against the 2012 United Kingdom Continental Shelf (UKCS) total emissions) (TOTAL E&P UK Limited, 2007, p. 272) (BP plc, 2011, p. 113) (BMT Cordah Limited, 2013, p. 91). In the case of material inventory, the difficulty when comparing them is more notorious because it is based on individual characteristics of each installation since their design and changes performed through their field life, reaching by the end different outcomes that will affect in different ways to the further user of sea (Department of Energy & Climate Change UK, 2011, p. 21). Although each field must have its own programme, there is still a challenge in this topic to expand to the actual industry methodology in order to obtain standardized comparable approaches and measurable indexes of effectiveness of the different decommissioning options. In the case of subsea equipment, many companies have their own abandonment procedures and practices aligned with the regulations and the guidelines of the United Kingdom Offshore Oil and Gas Association (Oil and Gas UK). Considering this, the programmes reviewed indicate a complete wellhead and casing removal below certain depth, 10 ft. minimum (The

24 24 United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2012, p. 29), of the sea bed to minimize the obstruction of other activities in the area and environmental impact. However, this has been evaluated in each case due to the nature of the facilities. A study performed by The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK) shows a summary of decommissioning possibilities based on the current technology and highlights the possible areas where developments and improvements of technology can be made. The results are obtained classifying the wells in 5 groups by the technology used to their decommissioning at the moment and the requirements to a safety P&A (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2008). Group 1 are wells where a Drilling Rig will be required due to the nature of the well (HPHT, High GOR etc.) or drilling tasks are required. Group 2 are wells where the retrieval of the entire completion is required due to tubing compromised. Group 3 is for wells in which partial recovery of the completion is required due to gas lift or bottom hole equipment such as gauges. The previous two groups together are approximately 31% for platforms and 5% for Subsea wells. Group 4 are those wells were the abandonment can be done without Light Intervention Vessels (LIV) and wireline and coiled tubing techniques, and hence, they do not require a Drilling Rig (Rigless). From the total of wells by 2008 this group represents the 47% and 5% for platforms and subsea wells respectively (see Figure 2).

25 25 Finally, for wells that were abandoned in previous operations, Group 5 represents a 12% in total, where 2% are Platform wells and 10% Subsea wells. These results suggest that more than 1/3 of the number of wells (Group 2 and 3) in the UK North Sea may have the potential to Rigless abandonment once the required technology is developed, and they could contribute to increase the Group 4 up to a 78% for Platforms and 10% for Subsea wells (see Figure 2). However, the study also recognizes that 70% of the Platforms in the North Sea have a Rig as part of their facilities which can influence the total number of Rigless decommissioning at the end. This has been evidenced in decommissioning programmes where the majority suggests that a Rig will be needed in the cases of Platforms even for Subsea programmes. For the wells in the groups 2 and 3 performing a Rigless P&A can lower the cost and save time performing tasks that were performed with a Rig before. (Moeinikia, et al., 2014) Figure 2 Summary of wells abandonment at 2008 (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2008, pp ) Decommissioning programmes recognize that most of the cuttings were placed on the seabed before considering the increase in environmental compromise during time, and despite this

26 26 fact studies carried on show that for now the best environmental and safe option is to leave them in place for natural degradation. However, in the future this may change due to new projects and the improvement in the technology to achieve environment-friendly solutions for disposal. (Maliardi, et al., 2014) Management of drill cuttings for future decommissioning programmes will have uncertainties as long as environmental regulations change with time, but as it was seen from past operations, the best practices during drilling can give good results in long term and keep up with this constant challenge. For example, a pile of drill cuttings from 30-year old operations (BP plc, 2011) today can be considered suitable to remain on the seabed for natural degradation according to current regulations. Although trawling, dredging or another processes can create low local pollution, regulations addressed that further studies have to be realized to quantify the impact of cuttings disturbing. It is important to consider that high values of HC loss were reached when there was a complete loss of the material during the dredging operation, and processes or equipment used for dredging or during trawling can influence both scenarios. (OSPAR Commission, 2009, p. 7) The challenge for drill cuttings decommissioning is to maintain adequate drilling procedures and practices that ensure the least possible contamination in later days and years. This has been seen in a trend on the approved plans of several companies who report values of HC losses lower than the thresholds and make feasible the option of leaving in situ (see Table 5). Technology such as drill mud injection can be evaluated, but there is also the consideration of the knowledge required to achieve a good injection process; this entails gathering

27 27 information, analysis and management (Maliardi, et al., 2014), not only of the producing reservoir but also of the disposal domain. Based on tendencies found during the review, the challenge of decommissioning large structures is one of the greatest because of uncertainties as well as risk and engineering management associated to large structures. Therefore, a decommissioning plan implemented during the design stage can help to improve the required actions to accomplish the removal. The conclusion of several decommissioning programmes is that the reuse of structures and topsides is limited or simply not feasible at the moment; in some cases this is based on companies policies (Perenco UK, 2010, p. 19) or probably because it is biased by the fact that the oil business always looks for reliability, safety and long productive life of the installations. This being said, refurbished facilities and structures have inherent uncertainties due to their production periods and maintenance performed; also, longer time of production implies more demanding maintenance which will influence the final productive life of the equipment (Russell & Keith, 2014). The reuse of topsides and structures has been addressed by programmes as not possible, but more options should be considered in the future. The case of the Welland field, for instance, shows that the reuse is possible; probably not in the North Sea but in different places it can be done. The reverse situation was analysed by (DeFranco, et al., 1998) looking into the feasibility of using a platform from Gulf of Mexico in the North Sea. The study considered that the structure should be reinforced to withstand environmental and installations loads in the North

28 28 Sea; having this in mind, the possible option of reuse is still there and the challenge is to find a market for the installations that will be decommissioned in the next years. The potential of pipelines reuse can be seen as an option to extend the life of this equipment on the field, but it is dependent on parameters such as the maintenance received during the productive life and the remaining life of the line. However, is important to notice that many of the pipelines will carry the uncertainty of feasible removal. Having a review of the wells at 2008, 19% of them are subsea wells (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2008, p. 11) and they will need a pipeline to send the production to the topsides; also, many pipelines may cross other operational pipelines thus creating a complex scenario for the removal plans. This can influence the pipeline outcome of selecting a partial removal or leaving in situ as the preferred option. Therefore, the challenge of developing procedures and technology that allow a safe and costsuccessful removal or reuse options is present now (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2013, p. 5). In overall, the reviewed programmes are based on the available technology at the time and certain parameters are not taking further consideration due to this restriction, (e.g. the single lift was discarded on many programmes due to the lack of technology than can handle this issue on large platforms; however, with new equipment such as the Pieter Schelte, a new point to consider will be the single lift removal of topsides facilities and possible large part of the jackets in the North Sea. (Allseas, s.f.)). This new type of equipment can overcome the challenges of a single lift installation and decommissioning.

29 29 The extension of the productive life of the installations has been addressed by Shell s previous experiences (Russell & Keith, 2014); this extension is dependent on many factors but mainly of facilities and process integrity in order to continue with production. A new consideration to extend the productive life may be the use of new processes such as CO 2 storage but it has restrictions that must be analysed and deeply studied before choosing it as an option. (Loizzo, et al., 2009) The final condition of the reservoir is not addressed by the decommissioning programmes which it may be an important player in the decision to extend the life of the facilities FACILITIES VERIFICATION KNOWLEDGE OF THE FACILITIES This factor makes important to develop a good working plan and if part of the risk can be minimized with the expertise of contractors and their familiarity with the facilities it may improve the accomplishment of tasks. (Prise, et al., 1993) UNCERTAINTIES One of the uncertainties that decommissioning programmes have to consider is the weather. The schedule has to be flexible enough to minimize the consequences of paralyzed activities waiting for good weather. This can also be one of the components that affect cost due to an extended work campaign and sensible operations that must be executed within good-weather windows (Apache North Sea Limited, 2013, p. 16).

30 30 In several programmes, weather has been taken in account during the analysis but it will always be an uncertainty and a constant challenge is to reduce the time required for each activity. Cutting large structures represents an issue; especially securing a sound underwater cut has an amount of uncertainty for steel and concrete structures of great thickness. An incomplete cut can create many outputs where the following activities can be compromised and become a hazard; therefore, the consideration of this uncertainty is vital in the decommissioning programme analysis. (TOTAL E&P UK Limited, 2007, pp. 143,144) STRUCTURES CONDITIONS The conditions of the topsides, structures and pipelines have a degree of uncertainty that in many cases can affect the selection of the removal method. For example, the presence of leaks or lack of seal that prevents re-floating operations on concrete structures represents an important issue for decommissioning (TOTAL E&P UK Limited, 2007, p. 134). These are important concerns because the basis of the possible options of structure removals depends on the capacity of the structure to float again without being compromised or interfere with following operations. In the case of the pipelines, they must possess structural integrity to resist the forces imposed by removal equipment; and afterwards be able to withstand a new installation and operation in case of reuse NON-TECHNICAL CONSIDERATION DECOMMISSIONING DELAY The option of delaying decommissioning has been studied from an economic point of view on different papers and publications.

31 31 Decommissioning delaying may be an attractive option but certain considerations should be made such as oil price, selecting the time for cease of production which is dependent on the reuse feasibility, new technologies, expenses management and tax regulations at the time, and the cost of the decommissioning itself. (Griffith & Cox, 1986, p. 162) (The United Kingdom Offshore Oil & Gas Industry Association Limited (Oil & Gas UK), 2010, p. 43). All these factors confer a degree of uncertainty to this delay option, but in the case of taxes regulation there has been a consulting process to give the industry a tax certainty increase through decommissioning relief deeds whose main objective is try to maintain accepted values of tax allowances at the end of the field life. (HM Treasury, 2013, p. 5) A different mechanism of decommissioning delay can be selling the assets to another company (e.g. Mobil UK sold the mature field Beryl to Apache Ltd. in 2011), and by this the new company has the liability over the remains of the facilities including the decommissioning programmes to be performed. Nevertheless, the UK Decommissioning Guidelines consider that companies that have or have had interest in the field remain with the liability if the government has not freed them from this liability. (Department of Energy & Climate Change UK, 2011, p. 56) There is a series of security insurances that the other company has to accomplish in order to be part of the trade, but essentially, it is to prove that they have the means to support the cost of the decommissioning programme. SENSE OF ECONOMY The economic analysis of a decommissioning programme has to incorporate many variables in each stage. For example, guidelines to estimate the cost generated by well abandonment has been presented by (The United Kingdom Offshore Oil & Gas Industry Association

32 32 Limited (Oil & Gas UK), 2011) and these have in consideration that the selected technology to be used can affect the outcome. Also, the Operator incorporates their process, industry consultation and previous experiences in specific areas. Making a comparison between different programmes (see Table 8 totable 11 ) might inhibit the identification of factors that dominate every one of them, but a breakdown by areas may give certain clarification. An appraisal of the ratio of the expenditure -calculated in 2004 money using the Retail Prices Index (RPI) until 2013 (Office of National Statistics, 2013)- and tonnes of material removed can be useful to compare the programmes. Nevertheless, this approach shows that this ratio has a great variability and can be affected by the method used as it can be seen in Figure 3. Here the use of platform cranes for the MCP-01 programme get a lower cost per tonne removed even for a heavier structure compared with the other programmes. The cost reported by North West Hutton also has included the abandonment of 40 wells which does not give an appropriate value for this index, and therefore, was not used in the comparison.

33 33 FIELD MCP-01 INDEFATIG ABLE WELLAND Method of removal Topside Reverse installation HLV + Platform cranes Reverse installation HLV Reverse installation HLV Topside removal cost [10 3 x / Ton, 2004 terms] Weight of Topside [kg] INDEFATIGABLE WELLAND MCP-01 Figure 3 Topside removal cost comparison Technology used, removal extent, number of wells to be abandoned, schedule and many other factors may influence the economic output; therefore, further study of the influence of these parameters may be of interest in this market. The reviewed programmes do not show values of costs related to treatment of cuttings. This can be based on the option of leaving the cuttings on the seabed undisturbed and because the survey and studies are part of the engineering and planning reported cost. 5. CONCLUSIONS The process of decommissioning has many uncertainties and they can be reversed to challenges in many cases, such as the possibility of field installation reuse. The wells plug and abandonment has adopted practices that can ensure good final conditions when they are well performed, and the challenge of improving the technology to reduce the use of Drilling Rigs is important to achieve faster results. The drilling cuttings management has proved that proper procedures in the past can comply with current environmental regulations, but constant compromise with the

34 34 environment will impose the challenge to the industry to improve the management of this waste using new technology. The reduction of activities required to remove topsides and structures is a challenge that has been tackled for many years; it still is constant for current decommissioning programmes but improving technologies are going to be a factor in future assessments. The final destination of large amount of installations in the North Sea represents a challenge that has not been defined properly and it will be necessary to do so in the near future due to the large amount of installations that will be decommissioned in the nearly future. The cost of decommissioning has been addressed as a total, but there still is no comparative method or effectiveness measurement to monitor improvements realized on the programmes. Therefore, the challenge is to obtain a method that can capture the variations between different conditions. 6. SUGGESTIONS FOR FURTHER WORK It is also important to research the impacts on decommissioning programmes if a cuttings injection programme is proposed; this might generate new environmental, safety, technical, and economic challenges that should be considered as well. The study for reuse of the North Sea platforms around the world may be realized provided that the North Sea is regarded as a more severe design environment. The experience of the Welland field is the proof that the possibility of reuse is present but it has to be extensively reviewed. All the programmes reviewed do not give information about the conditions of the reservoirs prior the cease of production. For further implementation of technologies such as the CO 2

35 35 storage, if the conditions are optimum, it will be important to perform analyses on reservoirs whose information has been already obtained during their years of production. This can be a method to extend the life of the facilities. In the economic area the use of past programmes experiences can give indications to perform an analysis focused in the effect of the technology selection on the cost of decommissioning.

36 36 7. APPENDICES 7.1. APPENDIX 1- FIGURES Number of Platforms in the North Sea UK to 2011 Number platforms per year years old 25 years old 15 years old 5 years old Cumulative of platforms Qty. Platforms Cumulative Platforms Qty Figure 4 Number of platforms in the UK North Sea by 2014 (Department of Energy & Climate Change UK, 2011) Oil field / discovery Gas field / HPHT play area discovery HPHT field / discovery Conden sate field / discovery Major basin (Permian to Cretaceous) Viking Graben Major basin (Permian to Cretaceous) HPHT play area Viking Graben Moray Firth Moray Firth Central Graben Central Graben North Sea Oil Province: all fields 100 km North Sea Oil Province: HPHT fields 100 km Figure 5 HPHT reservoir discoveries (Department of Energy & Climate Change UK, 2010)

37 37 TOPSIDE MATERIAL REMOVED BY TYPE AND BY PROGRAMME 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% NORTH WEST HUTTON CAMELOT MCP-01 MCP-01 MILLER CAMELOT INDEFATIGABLE NORTH WEST HUTTON WELLAND Figure 6 Topside material decommissioned in UK North Sea by type and by programme SUBSEA & PIPELINE MATERIAL REMOVED BY TYPE AND BY PROGRAMME 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% INDEFATIGABLE TRISTAN NW DON CAMELOT SCHIEHALLION AND LOYAL RUBIE AND RENEE RUBIE AND RENEE SCHIEHALLION AND LOYAL (Phase one) CAMELOT DON TRISTAN NW INDEFATIGABLE MILLER IVANHOE AND ROB ROY FIFE, FERGUS, FLORA AND ANGUS WELLAND SHELLEY NORTH WEST HUTTON Figure 7 Subsea & pipeline material decommissioned in UK North Sea by type and by programme

38 APPENDIX 2 - TABLES Table 2 Number and type of installations on the UK North Sea Fluid Type semi-sub. Process Facility Process Storage & Offloading Concrete Gravity Based Jackup Large Steel Small Steel Oil Oil / Gas Gas Oil / Condensate Condensate Subtotal per type Floating Type of structure Platform PLATFORMS TOTAL Total per fluid 298 Total Number of Oil and Gas Installations Total Number of Operational Installations (Department of Energy & Climate Change UK, 2011)

39 39 FIELD Table 3 List of Decommissioning programmes reviewed Main Operator Decommissioning Plan Year of approval Scope CONCRETE GRAVITY MCP-01 Total UK 2008 Topside, GBS JACKET STRUCTURE MILLER BP 2013 CAMELOT Energy Resource Technology INDEFATIGABLE Shell 2007 NORTH WEST HUTTON BP 2006 Topside, jacket, subsea, pipelines 2012 Topside, jacket, subsea, pipelines Topside, jacket, subsea, pipelines Topside, jacket, subsea, pipelines WELLAND Perenco 2010 Topside, jacket, subsea, pipelines SCHIEHALLION AND LOYAL (Phase one) FIFE, FERGUS, FLORA AND ANGUS FPSO & SUBSEA BP 2013 FPSO, subsea, pipelines Hess 2012 FPSO, subsea, pipelines SHELLEY Premier Oil 2010 FPSO, subsea, pipelines SUBSEA RUBIE AND RENEE Endevour 2014 Subsea, pipelines IVANHOE AND Endevour / Hess 2013 ROB ROY Subsea, pipelines DON BP 2011 Subsea, pipelines TRISTAN NW Silverstone 2010 Subsea, pipelines LINNHE Exon Mobile 2010 Subsea, pipelines (BP plc, 2011) (BP plc, 2011) (BP plc, 2006) (BP plc, 2013) (Endeavour Energy UK Ltd, 2014) (Energy Resource Technology (UK) Limited, 2012) (Hess Limited (Hess), 2013) (Hess Limited (formerly Amerada Hess Limited), 2012) (Mobil North Sea LLC, 2008) (Perenco UK, 2010) (Shell U.K. Limited, 2007) (Silverstone Energy Limited, 2010) (TOTAL E&P UK Limited, 2007) (Premier Oil, 2010)