Guidelines on Well Abandonment Cost Estimation
Guidelines on Well Abandonment Cost Estimation First edition published in Great Britain in 2011. Issue 2, 2015 © THE UK OIL AND GAS INDUSTRY ASSOCIATION LIMITED (trading as Oil & Gas UK), 2015 All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without prior written permission of the publishers. Any material within these guidelines that has been sourced from others has been reproduced with the permission of its owners. Contains public sector information licensed under the Open Government Licence v1.0, which can be found at – http://www.nationalarchives.gov.uk/information-management/uk-gov-licensing-framework.htm The information contained herein is given for guidance only. These guidelines are not intended to replace professional advice and are not deemed to be exhaustive or prescriptive in nature. Although the authors have used all reasonable endeavours to ensure the accuracy of these guidelines neither Oil & Gas UK nor any of its members assume liability for any use made thereof. In addition, these guidelines have been prepared on the basis of practice within the UKCS and no guarantee is provided that these guidelines will be applicable for other jurisdictions. While the provision of data and information has been greatly appreciated, where reference is made to a particular organisation for the provision of data or information, this does not constitute in any form whatsoever an endorsement or recommendation of that organisation.
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Contents 1 2 3
Introduction .................................................................................................. 6 Objective of the Guideline ........................................................................... 7 Regulatory Requirements ............................................................................ 8
3.1 3.2
Design & Construction Regulations .......................................................................... 8 Accounting Standards / Protocols ............................................................................. 9
4
Well abandonment Cost Estimation ......................................................... 10
4.1 4.2 4.2.1 4.2.2 4.2.3 4.3 4.3.1 4.3.2 4.3.3 4.3.4 4.3.5
Introduction to the Estimation Process .................................................................... 10 Reasons for Cost Estimate Preparation .................................................................. 11 During Field Operation............................................................................................ 11 Asset Sale or Transfer ............................................................................................ 12 End of Well Life or Cessation of Production ............................................................ 12 Cost Estimate Accuracy in Relation to Abandonment Proximity .............................. 12 Greater than 10 Years to COP................................................................................ 13 Between 5 and 10 Years before COP ..................................................................... 13 Less Than 5 Years before COP .............................................................................. 14 Well Abandonment Imminent .................................................................................. 14 Cost Estimate Process Flow ................................................................................... 15
5
Classifying Wells for Abandonment Cost Estimation ............................. 17
5.1 5.2 5.3 5.3.1 5.3.2 5.3.3 5.4 5.4.1 5.4.2 5.4.3 5.5 5.5.1
Use of a P&A Code................................................................................................. 17 Well Abandonment Location ................................................................................... 18 Well Abandonment Phases..................................................................................... 18 Phase 1 - Reservoir Abandonment ......................................................................... 18 Phase 2 - Intermediate Abandonment .................................................................... 18 Phase 3 - Wellhead and Conductor Removal ......................................................... 18 Well Abandonment Complexity / Work Type ........................................................... 18 Well Abandonment Classification Example 1 .......................................................... 20 Well Abandonment Classification Example 2 .......................................................... 20 Well Abandonment Classification Example 3 .......................................................... 20 Determining Well Abandonment Complexity ........................................................... 21 Using Tables 3.1, 3.2 and 3.3 ................................................................................. 21
6
Well abandonment Duration Estimation ................................................... 25
6.1 6.2 6.3
Benchmarking of Durations .................................................................................... 25 Duration of Operations............................................................................................ 25 Contingency & Extreme Event Allowance............................................................... 26
7
Determining Well Abandonment Phase Costs ......................................... 27
7.1 7.2 7.3
Cost Assumptions .................................................................................................. 27 Equipment Spread Costs ........................................................................................ 27 Operational Support & Ancillary Costs .................................................................... 29
8
Determining Field Well Abandonment Cost ............................................. 30
8.1 8.2 8.3
Integrating durations, spread rates for a well across phases................................... 30 Campaign and Additional Project Costs .................................................................. 30 Determining Field or Platform Well Abandonment Costs ........................................ 31
9 10
References .................................................................................................. 32 Appendix 1 .................................................................................................. 33
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11 12 13
Appendix 2 .................................................................................................. 35 Appendix 3 .................................................................................................. 36 Appendix 4 .................................................................................................. 39
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Abbreviations AFE ARO ASV COP CT DCR DECC DSV E&A HDWIV HLV HWU LWIV NPT NORM O&GUK P&A PM SCP UKCS WBS WDG WOW
Authorisation for Expenditure Asset Retirement Obligation Annulus Safety Valve Cessation of Production of field Coil Tubing The Offshore Installations and Wells (Design & Construction, etc) Regulations 1996 (SI 1996/913) Department of Energy and Climate Change Diving Support Vessel Exploration & Appraisal Wells Heavy Duty Well Intervention Vessel Heavy Lift Vessel, used for topside, jacket removal Hydraulic Work-over Unit Light Well Intervention Vessel Non Productive Time Naturally Occurring Radioactive Material Oil and Gas UK Plug and Abandon Wells Project Management Sustained Casing Pressure United Kingdom Continental Shelf Work Breakdown Structure Well Decommissioning Group Waiting on Weather
Usage of the term “decommissioning” usually relates to the broader project for the decommissioning of an installation or facilities that may include wells.
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1 1.
Introduction
Oil & Gas UK has recognised that decommissioning of facilities and the associated abandonment of wells in the UKCS is becoming a major part of the industry and needs coordination in order to provide timely advice to the Government and provide a consistent voice from the Industry on decommissioning matters.
2.
The Decommissioning Cost Estimating Guidelines first published in 2006, defined typical work breakdown structures based on the collective experience of the represented companies. The updates in 2010 and 2013 reflected Guideline usage, project experience in UK and Norway, and changes in legislation and government and industry bodies.
3.
The Guidelines on Well Abandonment Cost Estimation were developed by the Well Decommissioning Group (WDG) to provide specific guidance on generating Well Abandonment Cost Estimates as a subset of the overall estimates that follow the Decommissioning Guidelines.
4.
The Guidelines on Well
Abandonment Cost Estimation, first issued in 2011, are
applicable throughout the development life-cycle of wells, for example:
5.
•
initial field economics,
•
calculation of the abandonment provision / asset retirement obligation (ARO), during the field life, as used for annual financial reports, abandonment security agreements related to Asset transfer to a new owner,
•
planning the cessation decommissioning plan,
•
high-level decommissioning cost estimation for decommissioning projects.
of
production
and the
preparation
of
the
Additionally, a benchmarking service for well abandonment has been developed, which uses the coding described in these Guidelines.
6.
Well abandonment should comply with the “Guidelines for the Abandonment of Wells”, also prepared by WDG and issued by Oil & Gas UK.
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2 7.
Objective of the Guideline
The principles and practices described in this Guideline provide a common approach to estimating field-wide well abandonment costs. This Guideline outlines best practice based on industry experience. Whilst not prescriptive, their application will aid UK Operators of offshore and onshore oil and gas wells to generate estimates by providing:
8.
•
a template or common framework against which Operators can prepare their well abandonment cost estimates.
•
a checklist of activities in order that an estimate can be built that is both consistent and complete.
•
a methodology which requires that market rates and activity durations are clearly understood and stated in the cost estimate.
•
recognition that more detailed estimates will be required as Cessation of Production (COP) approaches.
•
assistance in establishing a greater level of confidence in determining decommissioning costs for asset acquisition or divestment (Security Agreements, etc.).
•
a means of both comparing estimates from different sources (third parties e.g. partners, contractors, etc.) and capturing Operator’s experience.
•
a framework for benchmarking.
Cost (non-defined currency) and duration (days) include merely illustrative comparisons of the relative cost / duration of different types / complexity of methods of well abandonment and should not be interpreted as benchmark data.
9.
This Guideline does not describe the process for preparation of detailed, fullyengineered estimates to support Authorisation for Expenditure (AFE) preparation for individual well abandonments, e.g. slot recovery side-tracks or abandonment that are part of a drilling operation.
10.
This Guideline does not consider costs that may be incurred post COP, e.g. platform removal or platform running cost.
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3 11.
Regulatory Requirements
The offshore oil and gas sector is regulated by the Petroleum Act 1998, which allows the obligation for decommissioning offshore infrastructure to be placed on the owners and includes protection against default on decommissioning.
12.
Companies have to formally assess their decommissioning liabilities (Asset Retirement Obligations, ARO) as part of normal accounting process.
The accuracy
of estimating the liability is expected to increase as the decommissioning date approaches. 13.
Under the Petroleum Act 1998, the Department of Energy & Climate Change (DECC) requires financial securities in certain situations to ensure decommissioning is carried out.
14.
15.
Petroleum Act 1998, section 29 (4); an abandonment programme — •
shall contain an estimate of the cost of the measures proposed in it;
•
shall either specify the times at or within which the measures proposed in it are to be taken or make provision as to how those times are to be determined;
The Petroleum Act 1998 was amended by the Energy Act 2008. This has not substantially changed the requirements of the original act with respect to abandonment programmes, however, it has given the Secretary of State further powers to review financial arrangements and enforce removal activities.
3.1 Design & Construction Regulations 16.
The requirements under Design and Construction Regulation (DCR) 13 are for Operators to ‘ensure that a well is so ..... suspended and abandoned that: a) so far as reasonably practicable, there shall be no unplanned escape of fluid from the well’.
17.
In addition DCR Regulation 15 requires Operators to ‘ensure that a well is so designed and constructed that, so far as is reasonably practicable: a) it can be suspended or abandoned in a safe manner; and b) after it’s suspension or abandonment there can be no unplanned escape from it or the reservoir to which it led.’
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3.2 Accounting Standards / Protocols 18.
The likely cost of decommissioning should be in accordance with the accounting protocols or standards in use, in the country of registration of the Company.
19.
A number of accounting protocols or standards are in use, the most common are; FAS 143 (US-based), FRS 12 (UK-based) and IAS 37. These are relatively similar, although policies for the updating of discount rates may differ. The cost estimate should equal to what a third party will charge to accept the liability for performing the well abandonments, based on the best estimate for future costs of performing the decommissioning. Extracts from the accounting standards are contained in Appendix 3.
20.
Future events that may affect the amount required to settle an obligation should be reflected in the amount of a provision where there is sufficient objective evidence that they will occur.
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4
Well abandonment Cost Estimation
4.1 Introduction to the Estimation Process 21.
This Well abandonment guideline provides; guidance on what needs to be considered when generating estimates for abandonment of wells, a description of the recommended process and tables which illustrate the information and data used to prepare estimates.
22.
The estimation process addresses the requirement that the accuracy / certainty of generated estimates need to be enhanced during the later life of an asset.
23.
The Well abandonment estimation process is not fully integrated with the Guidelines on Decommissioning Cost Estimation, but can be used to feed into the comprehensive ‘Work Breakdown Structure’ (WBS) checklist in the Guidelines on Decommissioning Cost Estimation.
24.
Appendix 1 provides background to the interface between Well Abandonment estimates and the broader asset decommissioning estimates and where costs are allocated for activities that support well abandonment and asset decommissioning.
25.
For an estimate to be regarded as representative of good practice the following features or assumptions should be included: •
Assumptions – all assumptions made in building the estimate should be clearly stated, e.g.: I. II.
III.
IV. V.
VI.
Regulatory assumptions, compliance with appropriate Guidelines. State the issue of the relevant Regulation. Number of platform & subsea wells included (and excluded) from the estimate, e.g. wells expected to have been abandoned during earlier campaigns. Execution Methodology – equipment and practice assumptions behind the estimate (e.g. rig or workover vessel selection, lifting and removal techniques). Key market rate and escalation assumptions (rig rates, well abandonment equipment rates, exchange rates). Key activity duration assumptions (rig days, spread durations) including allowances for waiting on weather (WOW), non- productive time (NPT), extreme events. Campaign strategy, e.g. preparation mobilisation and demobilisation.
cost,
re-instatement
of
rig,
•
High Level Method Statement – A description of the overall methodology adopted for the Well Abandonment Project.
•
Scope of the Estimate – The intended coverage of the estimate, i.e. which
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wells are included, which facilities require maintenance / upgrade for well abandonment activities, (cranes, rig, accommodation, helideck, power and life support). •
Accuracy – A statement of accuracy levels represented by the cost estimates is important for clarity and interpretation purposes, given that accuracy should increase as COP approaches (see Section 4.3).
•
Risk Assessment – understanding of key risks that could contribute to the range variation should be clearly identified.
•
Documentation – Cost Estimates evolve over time. It is recommended that the document, together with its key documents and assumptions are maintained securely for future update, review, audit feedback into other cost models and compliance with the appropriate Regulatory Regime (Appendix 3).
•
Ownership – The estimate may need to be split to allow for different equity ownership of individual wells or wells in each field.
4.2 Reasons for Cost Estimate Preparation 26.
Well abandonment cost estimates are normally prepared to support the preparation of ARO. It must be recognised that the context for estimate generation may change over time, ranging between: •
‘Generic’ liability, during early field life (e.g. -30% to +50%)
•
In support of asset sale or transfer (e.g. -15% to +30%)
•
Detailed budget / expenditure, nearing the end of field life (e.g. -5% to +15%)
The most likely cost given by each estimate produced will be expected to be robust. When detailed project planning commences, 3 – 5 years prior to Cessation of Production (COP), the estimate accuracy will be within a smaller range. The level of detail will also vary based on the contracting strategy.
4.2.1 During Field Operation 27.
An annual check is usually made to update well numbers and status of rig facilities that may be required for well abandonment activities. If significant changes are made to the asset a re-estimation may be appropriate.
Other issues that
may trigger a revision are changes to regulatory requirements, integrity status of wells, industry expectations or significant changes to abandonment technology.
28.
Annual revisions to the estimate due to changes in market rates (e.g. HLV, rig rates) may be considered unnecessary as rates are subject to cyclical variation. However, in the last 5 years of field life, it is important that market conditions are more carefully considered.
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4.2.2 Asset Sale or Transfer 29.
The level of cost estimate expected depends upon when, in the life cycle, the sale or transfer is taking place and the terms and conditions of the financial transactions.
30.
This Guideline can be used to provide a common understanding and structured enquiry into the Owners’ decommissioning estimate and the assumptions made in its creation.
Use of the checklist and guideline can assist if the current estimate is
deemed not to be at the appropriate level of detail for the asset life, or the last update is not recent.
4.2.3 End of Well Life or Cessation of Production 31.
In the last 5 years of development life, a much more detailed cost estimate becomes necessary for budget and planning purposes, based on analysis of the decommissioning requirements for the specific facility. In particular, the phasing of the expenditure becomes more significant leading ultimately to a comprehensive cost estimate (suited to the size of the abandonment project) which properly incorporates schedule and project phasing, contract strategy, project engineering requirements and the project approval process.
32.
Typically, discussion of the decommissioning proposals may commence with the Department of Energy & Climate Change (DECC) 2-3 years in advance of anticipated Cessation of Production (COP), leading to submission of the Decommissioning Programme. For this the first planning may have to commence 5 years in advance of COP.
33.
It should be noted that wells partially abandoned prior to the main COP approval, would be classified as abandonment spend. However, consideration needs to be given to determine which costs are eligible, under the accounting standards, to be charged to the well abandonment.
4.3 Cost Estimate Accuracy in Relation to Abandonment Proximity 34.
This guideline recognises that the detail and accuracy of estimates will need to be enhanced as COP approaches.
35.
As the first step in the preparation of an estimate, it is necessary to determine the appropriate number/proportion of wells within a field or asset that will be included in the analysis of the prospective decommissioning activity.
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36.
Table 1 provides an overview of the proportion of wells and the expected detail of analysis that should increase in relation to the decreasing duration before expected COP. Table 1 also provides an indication of the expectation that the range of an estimate will reduce with proximity to execution of abandonment.
Increasing level of accuracy required
Table 1: Level of accuracy and review relative to proximity to COP Proportion of Wells Required for Review
Expected Accuracy Range
Well-by-well review of sample to define Concept design
10-25%
-30% to +50%
< 5yrs
Detailed, full, well-by-well review. Timing of Abandonment Phases may need to be considered.
All
-15% to +30%
Imminent
Detailed well by well review of status, integrity, work units required + services cost
All
Time To COP
Approach recommended to review wells
> 10 years
Field-wide review of representative wells
5 to 10 yrs
-5% to +15% For AFE
AFE estimates are out-with the scope of these guidelines
All
4.3.1 Greater than 10 Years to COP 37.
For wells with a COP more than 10 years away, there is significantly less requirement to be as accurate as for wells for which abandonment is imminent.
38.
This is because the financial discounting of cost estimates forward to the year of COP diminishes the effect on the end result of current cost provision figures. Changes to the well status as a result of workovers or integrity changes, addition of new wells, as well as market rates are pronounced at a horizon of 10 years and beyond.
39.
It is recommended that a sample of 10-25% randomly selected wells are examined with the methodology described in Chapter 5.4 and then scaled up by applying the established distribution of P&A codes to the full wells portfolio.
4.3.2 Between 5 and 10 Years before COP 40.
When COP approaches (5 to 10 years before COP), the clarity of the work scope and accuracy of the cost estimate should be enhanced by examining sample wells.
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41.
With reference to 5.3.1, it is recommended that the estimates are based on a sample of 10-25% wells selected to be representative of the well population.
4.3.3 Less Than 5 Years before COP 42.
Well abandonment within 5 years to COP will require effort to define the work- scope and associated cost further. It is recommended that all wells are examined with the methodology described in Chapter 5.4.
43.
Experience has shown that an early start of the well assessments and planning (say 5 years before COP), improves the ultimate efficiency of abandonment significantly. This planning may allow for early Phase 1 and possibly Phase 2 abandonment of shut-in wells. The period may be required for review of the subsurface status and the wells, engagement with stakeholders like DECC, possible platform upgrade, contract awards, preparation of HSE cases, diagnostics. Being ready will reduce the idle time until final abandonment and will reduce the associated cost. After all, the timing when the production stops or becomes uneconomic is rarely a business decision and wells are the first critical path activities during a decommissioning project
4.3.4 Well Abandonment Imminent 44.
When well abandonment becomes imminent, the estimate would reflect a conceptual design in which the number and place of permanent barriers are indicated and casing and conductor operations are identified. Cost estimates are part of a project and have to incorporate full well and site details, contract strategies and spread rates, eventually culminating into AFE type cost estimates.
45.
For Cost Estimates requiring a high degree of accuracy (e.g. for AFE purposes), the characteristics of every individual well will have to be assessed.
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4.3.5 Cost Estimate Process Flow 46.
The estimation process flow shown below is the same whether for; field-wide, longterm, high-level, low-accuracy cost estimates, or individual wells assessment for more accurate operational planning estimates. 1.
Maintain a Wells List that identifies all Wells & Fields and Nominal COP
2.
Carry out Well Review (Table 1) and update Wells List
3.
Assess the adequacy of analysis, acceptability of uncertainty and/or carry out risk assessment
4.
Classify Location / Phases / Abandonment Complexity of field / wells (Table 2)
5.
Determine P&A Codes & Required Type of Abandonment (Tables 3.1-3.3)
6.
Update Wells List with P&A Codes
7.
Record Benchmarked or Deterministic Operational Durations (Table 4)
8.
Cost build-up, Criteria, inclusions / exclusions / assumptions stated (Section 8)
9.
Define Work Units and Spreads required (Table 5 & Appendix 2)
10. Determine rig rate / Spread rate (Table 6) 11. Cost from Duration (Table 4) & Rates (Table 6) (Tables 7 & 8 examples) 12. Recognise Additional Costs: one-off campaigns, support, mobilisation, refurbishment, contingency (Table 9 examples) 13. Determine project cost estimate for wells (Figure 1)
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Phase 1, Type 2 Phase 1, Type 2 Phase 3, Type 1 Phase 2, Type 1 Phase 1, Type 1
Duration
(in P&A Code Table)
Spread rate
(in P&A Code Table)
Cost Estimate
(in P&A Code Table)
Number of wells
(in P&A Code Table)
Cost Estimate Wells for Field
Figure 1: Schematic of ARO Estimation Process for a Field
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Campaign one-off Cost
ARO Estimate Wells for Field
Guidelines on Well Abandonment Cost Estimation
5 Classifying Wells for Abandonment Cost Estimation 47.
The development of consistent well P&A cost estimates depends on a common approach to classifying the type of well abandonment, either of wells individually or within a field, and the assumptions that are applied with respect to the execution of well abandonment operations.
48.
49.
This guideline proposes classification of wells according to three factors: •
Location – Of a Well, Platform or Field whether offshore or onshore
•
Abandonment Complexity – the methodology and equipment required
•
Abandonment Phases – reflecting the three phases of an abandonment operation
For the purpose of generating an ARO for relatively new wells and fields or for assets where COP is more than 10 years away, it may be appropriate to group all wells at a location into a single class or coding.
50.
As COP is approached, increased estimate accuracy will be required. More detailed definition of requirements for decommissioning relating to the status of individual wells will require the classification of each well in relation to the complexity and phasing of abandonment activity.
51.
The appropriate sample size of randomly selected wells, or all wells as determined in the relation to the proximity of abandonment activity in the previous chapter, should next be examined and classified in relation to the complexity of the abandonment work. Refer to Section 5.3.
52.
Please note that the categorisation of suspended subsea wells as described in the current Guidelines for the Suspension & Abandonment of Wells will be reassessed prior to release of Issue 5 of those guidelines. The classification of wells for abandonment described in these guidelines provides a more complete classification of wells than the ‘categories’ previously applied to suspended subsea wells.
5.1 Use of a P&A Code 53.
P&A coding is suggested as a method to summarise the classification of wells included in an abandonment estimate. Individual wells or groups of wells can be classified using the P&A Code to represent the location of the well and the complexity of the three phases of well abandonment work.
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54.
The P&A Code commences with 2 letters indicating the location of the well(s), followed by 3 digits representing the complexity of each of the 3 phases of well abandonment. Classification or coding well abandonments is explained in the following sections.
5.2 Well Abandonment Location 55.
This simply defines the physical location of the well. •
PL – Platform well
•
SS – Sub-Sea well
•
LA – Land well
5.3 Well Abandonment Phases 56.
The abandonment of any well can be divided into three distinct phases, reflecting: the work-scope, equipment required, and / or the discrete timing of the different phases of work
57.
The objective is to generate high-level cost estimates, and therefore the process does not need to finesse sub-divisions of work, e.g. diagnostic and preparatory operations. Allowance for such tasks should be included within the most appropriate Phase.
5.3.1 Phase 1 - Reservoir Abandonment 58.
Primary and secondary permanent barriers set to isolate all reservoir producing or injecting zones. The tubing may be left in place, partly or fully retrieved. Complete when the reservoir is fully isolated from the wellbore.
5.3.2 Phase 2 - Intermediate Abandonment 59.
Includes: isolating liners, milling and retrieving casing, and setting barriers to intermediate hydrocarbon or water-bearing permeable zones and potentially installing near-surface cement. The tubing may be partly retrieved, if not done in Phase 1. Complete when no further plugging is required.
5.3.3 Phase 3 - Wellhead and Conductor Removal 60.
Includes; retrieval of wellhead, conductor, shallow cuts of casing string, and cement filling of craters. Complete when no further operations required on the well.
5.4 Well Abandonment Complexity / Work Type 61.
A digit is chosen (0 to 4) to reflect the complexity of abandonment work for each of the three phases defined above, according to the following:
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TYPE 0:
No work required – A phase or phases of abandonment work may already have been completed
TYPE 1:
Simple Rig-less Abandonment - Using wireline, pumping, crane, jacks. Subsea will use Light Well Intervention Vessel and be riser-less
TYPE 2:
Complex Rig-less Abandonment - Using CT, HWU, wireline, pumping, crane, jacks. Subsea will use Heavy Duty Well Intervention Vessel with Riser
TYPE 3:
Simple Rig-based Abandonment - requiring retrieval of tubing and casing The Operator may decide to include sub classification of subsea rig based reservoir abandonment to reflect the time and spread differences relating to through tubing, coil tubing or completion pulling operations.
TYPE 4:
62.
Complex Rig-based Abandonment – May have poor access and poor cement requiring retrieval of tubing and casing, milling and cement repairs.
Table 2 provides a matrix that can be used to record the abandonment complexity / methodology for the three phases for a well or wells at a location. If multiple wells are being considered, the number of wells of each Type of Abandonment Complexity for each Phase, may be summarised in this matrix Table 2: Location, Abandonment Complexity Type and Abandonment Phase Abandonment Complexity Location (Single Well, Field or Platform) (May be Offshore or Onshore)
Phase
63.
Type 0 No work required
Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig-based
Type 4 Complex Rig-based
1 Reservoir Abandonment 2 Intermediate Abandonment 3 W ellhead Conductor Removal
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5.4.1 Well Abandonment Classification Example 1 64.
For a Platform well, requiring a simple rig based abandonment across the reservoir then requiring the tubing to be pulled, shallow barriers placed and the conductor removed, the P&A Code would be PL 3/3/3 Abandonment Complexity Type 0 No work required
Phase
Platform Well 17/19-A57
Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig-based
1 Reservoir Abandonment
X
2 Intermediate Abandonment
X
3 W ellhead Conductor Removal
X
Type 4 Complex Rig-based
5.4.2 Well Abandonment Classification Example 2 65.
For a Platform well, to be abandoned across the reservoir with CT , then intermediate P&A using a rig & no conductor to be removed (e.g. removed by HLV), the P&A Code would be PL 2/3/0 Abandonment Complexity Type 0 No work required
Phase
Platform Well 17/19-A59
Type 1 Simple Rig-less
Type 2 Complex Rig-less
1 Reservoir Abandonment
Type 3 Simple Rig-based
Type 4 Complex Rig-based
X
2 Intermediate Abandonment
X
3 W ellhead Conductor Removal
X
5.4.3 Well Abandonment Classification Example 3 Platforms with 30 wells: 5 already suspended at the reservoir, with two fully abandoned,
but
with
Conductor
&
wellhead
remaining.
Reservoir
and
Intermediate abandonments require a range of methods for different wells. Conductors & Wellheads will be recovered during platform removal. No Single P&A Code is applicable, but the matrix summarises the number of wells that will require a particular method of abandonment for each phase. Abandonment Complexity Platform Well 17/19-A59
Phase
66.
1 Reservoir Abandonment
Type 0 No work required
Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig-based
5
10
10
5
10
10
2 Intermediate Abandonment
2
3 W ellhead Conductor Removal
30
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8
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5.5 Determining Well Abandonment Complexity 67.
The characteristics or conditions of a well at the time of abandonment will influence the complexity of abandonment, the facilities required and method to be used.
68.
Tables 3.1, 3.2 and 3.3, and associated notes, summarise some of the key factors that will determine the complexity of the abandonment of a well.
69.
The tables indicate the feasibility of each ‘Type’ of abandonment in relation to a number of key characteristics of the well.
70.
Tables 3.1, 3.2 and 3.3 relate to the three phases of abandonment respectively. However, some of the characteristics or conditions of the well may be applicable to more than one phase of abandonment.
71.
The characteristics in all three tables may also be used to establish the complexity and equipment requirements when a well(s) is to be fully abandoned in a single (multi-phase) abandonment programme.
5.5.1 Using Tables 3.1, 3.2 and 3.3 72.
The complexity of abandonment is determined by assessing the characteristics in the sequence listed in each table. The characteristics are assessed in sequence, and eventually the feasibility of the ‘Type’ of abandonment will become established.
73.
In each table more characteristics will need to be assessed in order to confirm that a lower complexity method of abandonment is feasible.
74.
The feasibility of rig-less abandonment operations, may be affected by a number of factors. In case of doubt, assume that; ‘Type 3’ simple rig abandonment is required.
75.
As an example of assessing Phase 1 abandonment for a platform well, using Table 3.1: Assess Characteristic 1: If the well has Sustained Casing Pressure (SCP) then it is a Type 4 for that Phase, i.e. P&A code is PL-4-x-x.
76.
If the well has no SCP then continue the assessment of each characteristic in turn until the required ‘Type’ of abandonment is confirmed.
77.
The P&A Code for each / all phases can be completed by assessing the characteristics in Tables 3.2 and 3.3.
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Table 3.1: Criteria for Classifying PHASE 1 Well Abandonment Complexity x:Not Feasible :Required O:Optional
Note # 1 2 3 4 5 6 7 8 9 10 11
Well Characteristics / Condition at abandonment Sustained Casing Pressure due to hydrocarbons or overpressures Not cemented casing or liner at barrier depths (cap rock) Restricted access to tubing Deep electrical or hydraulic lines present at barrier depth Annulus Safety Valve (ASV) present Packer set above cap rock Site does not allow for CT/HWU pumping operations Multiple reservoirs to be isolated Tubing has leak (e.g. corrosion, accessories) Inclination >60 deg above packer (wireline access) Well with good integrity, no limitations
Well Abandonment Complexity Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig
Type 4 Complex Rig
X
X
X
X
X
X
X
X
O
X
X
O
X
X
O
X
X
O
X
X
O
X
O
O
X
O
O
X
O
O
O
O
O
Notes: 1. Sustained Casing Pressure – SCP related to overpressures or hydrocarbons originating from the reservoir(s) indicates that the primary casing cementation has failed and requires repair at the reservoir caprock level. 2. Not cemented casing or liner at the depth of the barrier (cap rock). Also applies to a (not cemented) scab-liner. The casing will have to be milled or removed to place a competent barrier. Note: The length between top of potential inflow (e.g. bottom of caprock formation) and top of barrier must be more than 200 ft to place permanent barrier (assumed that good cement is achievable). 3. Restricted Tubing Access – tubing may contain a fish, stuck plugs, perhaps be collapsed or parted, hence obstructing or limited access to the depth of the deepest permanent barrier, typically the production packer. Access may be restricted due to internal deposits (scale, wax) if not removable or able to provide a seal in conjunction with cement. The tubing will have to be recovered by a rig. 4. Deep gauge or electrical cables, or hydraulic lines – a data or power cable or hydraulic line is not acceptable to cross a permanent barrier and has to be removed. The tubing is to be recovered possibly requiring a rig. 5. Annulus Safety Valve (ASV) – An Annulus Safety Valve may not allow adequate flow for a through-tubing circulation and cementation, thus will require the tubing to be removed, possibly requiring a rig. 6. Packer set above cap rock – if the deepest barrier is to be placed below the production packer, this will have to be milled unless coiled tubing access is possible. 7. Poor access of CT/HW U to site – offshore platform may not be capable of accommodating equipment, crew or crane and a support vessel is required. 8. Multiple reservoirs to be isolated. This can often be achieved will coiled tubing. If not a rig is required to remove the completion and packers as a TYPE 4 operation.
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9. Leaking tubing – if the tubing is leaking, it cannot be used as a conduit for pumping cement. This will have to be recovered unless coiled tubing access is possible. 10. High inclination (no wireline access) – due to inclination above 60 deg, wireline access may not be possible for setting wireline plugs and punching casing. 11. Well with good integrity – no limitations for through-tubing rig-less abandonment.
Table 3.2: Criteria for Classifying PHASE 2 Well Abandonment Complexity x:Not Feasible :Required O:Optional
Note # 1 2 3 4 5 6 7 8 9 10
Well Characteristics / Condition at abandonment Sustained Casing Pressure due to hydrocarbons or overpressures Restricted access to casing Not isolated fresh water aquifers / zones Not cemented casing or liner at barrier depths (cap rock) Not isolated Shallow gas Site does not allow for CT/HWU pumping operations Poor primary casing cementation No tubing in well Inclination >60 deg above barrier depth (wireline access) Well with good integrity, no limitations, tubing in place
Well Abandonment Complexity Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig
Type 4 Complex Rig
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
O
X X
X
O
O O
X
O
O
O
O
O
Notes:
1. Sustained Casing Pressure – SCP on any of the casing annuli related to overpressures or hydrocarbon zones shallower than the reservoir, indicates that primary casing cementations have failed and require repair for final abandonment. 2. Casing access restricted – casing may have collapsed or parted, obstructing access to the production packer, where the deepest barrier is anticipated. 3. Fresh water zones – Fresh water zones will require protection if poorly isolated. 4. Not cemented casing or liner at the depth of the barrier (cap rock). Also applies to a (not cemented) scabliner. The casing will have to be milled or removed to place a competent barrier. Note: The length between top of potential inflow (bottom of caprock formation) and top of barrier must be more than 200 ft to place permanent barrier (assumed that good cement is achievable). 5. Shallow gas not isolated – Un-cemented (low saturation) gas zone will cause leaks to surface when casing is cut and removed. This can be related to Sustained Casing Pressure. Such zones require isolation after the tubing has been removed by a rig. Requires casing removal or milling. 6. Poor access of CT/HW U to site – offshore platform may not be capable of accommodating equipment, crew or crane and a support vessel is required. 7. If primary casing is poorly cemented, then a rig may need to remove long sections of casing. 8. No tubing in well – if the tubing has been removed under Phase 1, a work string is required to place a permanent barrier. This can be provided by CT, HW U, or rig. 9. High inclination (no wireline access) – due to inclination above 60 deg, wireline access may not be possible for setting wireline plugs and punching casing.
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10. Well with good integrity – no limitations for through-tubing rig-less abandonment. Only a surface barrier is required that can be placed through the tubing.
Table 3.3: Criteria for Classifying PHASE 3 Well Abandonment Complexity x:Not Feasible :Required O:Optional
Note # 1 2 3 4
Well Characteristics / Condition at abandonment Poor integrity of conductor Platform unable to suspend conductor load during raising Water depth beyond limitation for cutting by LWIV (Subsea well) Conductor cutting/retrieval rig-less
Well Abandonment Complexity Type 1 Simple Rig-less
X
Type 2 Complex Rig-less
X
Type 3 Simple Rig
X
Type 4 Complex Rig
X
X
O
X
X
O
O
O
O
Notes: 1.
Poor integrity of conductor – An involved programme will be required in case a conductor has poor integrity (corrosion, weak connectors) or a shallow restriction or damage.
2.
Platform unable to suspend conductor load during retrieval – The platform may not be strong enough to suspend the heavy conductor load, which may include cemented inner casing.
3.
Water depth beyond limitation for cutting conductor by LW IV – The cutting equipment typically used by a Light W ell Intervention Vessel (LW IV) may have water depth limitations, beyond which a rig is required.
4.
Conductor: Site can accommodate ri g -less cutting and retrieval spread or retrieval planned with heavy lift vessel. Site can support loads of raising a multi-string conductor from the seabed, accommodate jacking spread, crane and crew. Annuli are free of polluting fluids. No need to install
environmental plug. The Operator will need to decide from a budget-holding s t a n d p oi nt whether to include or exclude conductor retrieval in Phase 3, in the event that the conductors are to be retrieved by Heavy Lift Vessel.
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6 78.
Well abandonment Duration Estimation
Having assigned P&A codes to wells base on location and complexity, it is then necessary
to
determine
the
likely
duration
of
each
Phase
of
the
well
abandonment activity.
79.
Generally this is done by benchmarking against similar operations, or by deterministic modelling of the phase. Either method is acceptable, but assumptions made in the process must be stated.
6.1 Benchmarking of Durations 80.
To determine the likely duration of each well Type and Phase listed above it is anticipated the Operator will use some form of benchmarking using internal and external data sources. Benchmarking from a suitable data set will allow Operators to determine typical times for proposed operations and estimates of Non-Productive Time (NPT) and Waiting on Weather (WOW). Correct benchmarking will also establish the degree of skew within the dataset and determine key factors such as P10, P50, P90 and Mean within the distribution. These factors can then be used in probabilistic modelling of the sequence of Phases or Wells to determine the most likely outcome to a project.
81.
Alternatively, Operators may wish to use a deterministic value for each Type and Phase, and also include estimated allowances for NPT or WOW, based on benchmarks.
6.2 Duration of Operations 82.
To establish well P&A durations, the process is anticipated to include the following steps: •
Define scope and assumptions for each phase and Type, as captured in the P&A code.
•
Determining phase durations either by benchmarking using internal and external data sources or using deterministic modelling.
•
Determining NPT and WOW, either by benchmarking or using deterministic modelling.
•
Establish degree of skew and determine P10, P50, P90 and Mean. (if applicable)
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Guidelines on Well Abandonment Cost Estimation
83.
Table 4 provides illustrative durations for different phases and complexities of abandonment.
84.
Table 4: Illustrative Durations for Different Well Abandonment Complexities & Phases Abandonment Complexity Type 0 No work required
Type 1 Simple Rig-less
Type 2 Complex Rig-less
Type 3 Simple Rig-based
Type 4 Complex Rig-based
1 Reservoir Abandonment
0
3
5
3
7
2 Intermediate Abandonment
0
3
6
5
10
3 W ellhead Conductor Removal
0
2
4
2
8
Phase
Platform Well (Days)
6.3 Contingency & Extreme Event Allowance 85.
With deterministic estimates it is not possible to determine a range of possible outcomes.
86.
Inclusion of contingency in estimates may require risk assessment to establish the potential impact of the uncertainties of information, the absence of detailed engineering and planning, etc.
87.
An allowance for contingency reflecting real life performance should also be considered. For example, an assumption on extreme event frequency could be made, e.g. one in ten phases will take twice the expected duration. Such assumptions must be stated.
88.
The term extreme event is being used in this context for wells or well phases that take considerably longer than would normally be expected; possibly due to well condition, unusual weather etc. These would be beyond a P90 estimate.
89.
If a sufficient dataset is available and it is possible to use a probabilistic analysis, then consideration of an extreme event is less important provided there is a sufficient range of possible outcomes in the dataset. However, the possibility of an extreme event should not be ignored.
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7
Determining Well Abandonment Phase Costs
7.1 Cost Assumptions 90.
Well abandonment cost of a phase is modelled as time related cost: the cost estimate should be determined by multiplying expected duration of a phase and the applicable spread-rate.
91.
The equipment spread for each phase should firstly be determined. Table 5 outlines example equipment spreads for different locations, complexities and phases. Once the equipment spread is defined a spread cost should be calculated as follows.
7.2 Equipment Spread Costs 92.
Equipment spread costs can be calculated by either a top-down analysis of actual abandonment data or a bottoms-up analysis of individual services costs.
93.
In the top-down case the spread rates are determined by benchmarking with similar operations and equipment spreads that have been used.
94.
In the bottom-up case the spread rate is determined from the assumed utilisation and cost/day of the required equipment and services to be used. Potential synergies in service provision may be considered.
95.
The assumptions made in determining spread costs must be stated, for example if current or expected rig rates have been used etc. Assumptions for future rig rates are a key input to the final estimate; hence these need investigation and documentation; today’s rig rates are considered a good starting point. It must be kept in mind that price escalation factors may be applied to the decommissioning estimate in order to arrive at the final ARO value.
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Guidelines on Well Abandonment Cost Estimation
Table 5: Work unit & Equipment Spreads for different locations, complexity Location Onshore Platform with support vessel Platform with modular rig Platform with fixed rig
Type 1 Simple Rig-less Pump spread
Type 2 Complex Rig-less
Type 3 Simple Rig
Type 4 Complex Rig
CT, HWU
Rig / hoist
Rig / hoist
Pump spread
CT spread
Pump spread
CT spread
Modular Rig
Modular Rig
spread
spread
Pump spread
CT spread
Platform Rig
Platform Rig
spread
spread
Platform with
Pump spread +
jack-up
Accom. spread LWIV
Subsea
Spread
CT spread LWIV spread
Subsea – Deep water
Jack-up spread
Jack-up spread
Semi spread
Semi spread
Semi/drillship
Semi/drillship
spread
spread
Legend Pump
Electric and slick line, pumping services, cementing spread.
spread CT /HWU
Coiled tubing (CT) or Hydraulic Work-over Unit (HWU), electric and slick line,
spread
pumping services, cementing spread. Tubing and casing cutting and recovery services.
Rig
Functional drilling rig, electric and slick line, cementing and pumping services,
spread
tubing and casing cutting and recovery.
LWIV
Light Well Intervention Vessel, equipped with all services necessary to
spread
perform that phase of work. This may include diving services.
Semi
Functional semi-submersible rig suitable for the location, electric and slick
spread
line, cementing and pumping services, tubing and casing cutting and recovery services.
96.
Note: The scope of Coil Tubing work can range from a standalone operation, to deployment through the derrick for both simple and complex well abandonment. Assumptions relating to the potential deployment of CT in Type 2, 3 and 4 abandonments must be clearly stated, as this may add to the Type 3 and 4 spread costs.
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Table 6 – Illustrative Example Spread Costs for Different Complexity/Types Site/Installation type (nominal currency per day)
Type 1 Simple Rigless 5,000
Type 2 Complex Rig-less 10,000
Platform with support vessel
20,000
25,000
Platform – modular rig
25,000
Platform – fixed rig
25,000
Onshore
Platform – jack-up
Type 3 Simple Rig
Type 4 Complex Rig
35,000
35,000
35,000
55,000
55,000
35,000
55,000
55,000
70,000
90,000
110,000
110,000
140,000
170,000
220,000
220,000
Subsea – Deep water 300,000 300,000 • The numbers used in this table are illustrative
300,000
300,000
Subsea
7.3 Operational Support & Ancillary Costs 97.
In determining spread costs, consideration should be made for the following logistic support
(boats,
helicopters,
storage
space
rental,
dock
operations,
etc),
accommodation, operational overheads, onshore support, preparation work, DSV support to provide access to older sub-sea wells. 98.
Ancillary charges e.g. the transport, disposal and decontamination of waste fluids, tubing, and other equipment may be significant and should be stated.
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8
Determining Field Well Abandonment Cost
8.1 Integrating durations, spread rates for a well across phases 99.
Having classified a well by its Location, Phases, Complexity and Phase Spread Costs it is then a simple matter to integrate these factors to determine a likely duration and cost for the abandonment of the well. For example an abandonment consisting of Phase 1 Type 2 and Phase 2 Type 3 would cost 5 x 35,000 + 5 x 55,000 = 450,000 (nominal currency units). Table 7 - Example of Estimated Duration per Phase Type 1 Simple Rig-less 3
Type 2 Complex Rig-less 5
Type 3 Simple Rig 3
Type 4 Complex Rig 7
2 Intermediate Abandonment
3
6
5
10
3 Wellhead Conductor Removal
2
4
2
8
Platform Well (Days) Phase
1 Reservoir Abandonment
Table 8 - Example of Estimated Spread cost per Phase Site/Installation type (nominal currency per day) Platform – fixed rig
Type 1 Simple Rigless 25,000
Type 2 Complex Rigless 35,000
Type 3 Simple Rig
Type 4 Complex Rig
55,000
55,000
8.2 Campaign and Additional Project Costs 100.
Developing a well abandonment cost estimate for ARO or similar purposes needs to recognise the other costs that will be incurred in the project and campaign(s).
101.
Table 9 provides guidance on the issues to be considered; it is not exhaustive and the range of issues will depend on individual project circumstances.
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Table 9 - Project / Campaign Factors for Consideration Issues Management overhead and engineering
Well Inspection / Surveys Location surveys
Site preparation Platform Rig Upgrade Riser and subsea well tools Mobilisation & Demobilisation of rig and rig equipment. Mobilisation & Demobilisation Transport to shore / Logistics NORM Scale treatment and decontamination. Post removal survey and trawl
Discussion Most abandonment project ARO will include a management overhead. This is specifically intended to capture the engineering specifically associated with well abandonment i.e. well file review and categorisation, conceptual design, detail programme development, contracting and procurement, HSE documentation, etc. Well diagnostics would include well surveillance, surveys and inspections of the wells prior to detail operational planning to determine well condition and ability to access. For a jack-up rig adjacent to a platform this would include the seabed survey. For a semi-submersible this would include seabed and anchor pattern surveys. For subsea wells this will include fishing net and protective structure removal. This would include rig upgrade cost, recertification etc. Final removal of a platform rig is carried in the facilities removal budget. Inspection/refurbishment of subsea tools and connectors. Preparation of risers may be required. The installation of a temporary modular platform rig. It would also include removal of a temporary modular rig. For a semisubmersible this would include the cost of bringing and removing the rig from site. This is the general cost of mobilising rig or rig-less equipment to well site for the abandonment operations. These include helicopters, vessels and supply base support. These may well have been included in the development of spread costs for the various phases. If not then they should be identified separately. It is possible that tubulars recovered from a well will be contaminated. The cost of dealing with this should be addressed. This specifically applies to subsea wells. It is usual to carry out this survey, post abandonment.
8.3 Determining Field or Platform Well Abandonment Costs 102.
The process to determine the well abandonment cost estimate for a field or platform is to determine the Complexity, Phases and spread costs per phase for each well, as described in 9.1, and making a summation for all wells in the field. The final step for generating the estimate for each field or platform is to add a one-off additional cost associated with the campaign(s) for the field, as described in 9.2.
103.
The process is illustrated in Figure 1. Appendix 4 provides a worked example.
104.
As indicated in chapter 5.1, the entire process and detailed assumptions need to be documented for audit and future reference.
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Guidelines on Well Abandonment Cost Estimation
9
References
1. Guidelines for the Suspension and Abandonment of wells, Oil & Gas UK, Well Abandonment Group 2. Decommissioning Cost Estimating Guidelines, Oil and Gas UK, Decommissioning Workgroup 3. Financial Accounting Standards No. 143: Accounting for Asset Retirement Obligations (June 2001, based in US). http://www.fasb.org/pdf/fas143.pdf 4. International Accounting Standards, IAS 37 - Provisions, contingent liabilities and contingent assets [2005] http://www.iasplus.com/standard/ias37.htm
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10 Appendix 1 O&GUK Decommissioning Estimating Guideline Interface With respect to interfacing with the Guidelines on Decommissioning Cost Estimation WBS, it is important to ensure what is included in the wells estimates and which items are not. This should be documented as part of the estimate. Below is a list of items that should be considered. The Table below provides an overview with cost elements as typically assigned. 1. Platform operational cost, i.e. to keep the platform running and maintained during the well abandonment operations. Such costs are typically not assigned to wells, but to Production (pre-COP) or Facilities (post-COP). 2. Well Engineering includes Contractor Project Management, review of well files, review of well categorisation (both platform and sub-sea wells). Typically assigned to Wells as a once-off campaign cost. 3. Rig upgrade cost, for re-instating a rig that is out of service and certification. These would normally be covered as a one-off cost for abandonment. 4. Site surveys, facilities upgrades and preparation for jack-ups and modular rigs. These costs are typically not assigned to wells. 5. Cost for a crane upgrade for a crane that requires significant maintenance prior to well abandonment. These are typically assigned to Facilities. These costs are typically not assigned to wells. 6. Installation of temporary facilities such as crane or accommodation modules. These costs are typically not assigned to wells. 7. Inclusion of Mobilisation and Demobilisation charges for rigs, spreads and equipment. These include contract start-up, modifications, risers, moves, shipment, commissioning, back-loading, etc. These cost are typically assigned to wells. 8. Logistics cost for supply boats, dock, storage, helicopters etc are typically prorated.
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9. Removal, Decontamination & Disposal of recovered tubulars, wellheads, etc. Waste disposal, including NORM. These costs are typically assigned to wells. Any cost related to drill cuttings piles is typically not assigned to wells but to facilities. 10. Conductor removal costs are typically assigned to wells cost estimate. On certain platforms the conductor may be retrieved by a Heavy Lift Vessel. This cost would typically go to the Guidelines on Decommissioning Cost Estimation WBS. The cost for cutting the conductor is to be defined as per the individual work scope. 11. Accommodation and catering charges for the well abandonment crew. These costs are typically assigned to wells. 12. Cost associated with simultaneous operations, i.e. both well abandonment and production OR well abandonment and facility decommissioning activities. These costs are typically not assigned to well abandonment costs. 13. Early well abandonment diagnostics activities using wire line, wellhead checks, pressure testing, corrosion assessment, etc. These costs are typically assigned to wells. 14. Subsea diving support for wells. These costs are typically assigned to wells. 15. Site Preparation for subsea wells includes: seabed and other surveys, net removal, leak check, tree preparation and protective structure check. These costs are typically assigned to wells. 16. Typically, one mob/demob estimate is used, where a workover vessel or rig is necessary for decommissioning, wells are generally treated, plugged and abandoned and, where relevant, conductor removed in one operation. 17. Work on wells during the Preparation stage (Rig or Rigless) should be included in the wells estimate. 18. Post-removal debris survey & trawling verification/certification. These costs are typically not assigned to wells.
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11 Appendix 2 Generic Well Abandonment Services The list below provides generic services for consideration when determining a bottoms-up estimate of a spread rate. This is not specific to phases, locations, rig or rigless, but intended as checklist for completeness.
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35
EQUIPMENT and SERVICES to be considered for spread rate estimate Office staff management, support, consultancy On-board supervision Rig equipment + crew Coiled tubing unit + crew Hydraulic Workover Unit + crew Accommodation and Catering Crane operation Electrical generators Scaffolding service BOP rentals Riser rentals Slick line service + crew Electric line service + crew Perforations, punches, tubing cutting + expert Logging cement tops and bond, corrosion Pumping, cementing services (tanks, pumps, blenders + crew) Cement and additives Packers, bridge plugs Wellhead and X-tree removal services Temporary pipe work, valves (chicksans, etc) Casing cutting, retrieval Casing milling services Tubular handling services Fluids and chemicals + services Fluid waste storage tanks, transport, disposal Equipment disposal NORM disposal HSE equipment (H2S, Norm, survival, etc) Supply vessels, dock and storage fees, road transport Move vessels, positioning Helicopter transport Diving support ROV services Conductors cutting + crew Conductor retrieval (sectioning, raising, handling, cleaning, transport) + crew
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12 Appendix 3 Accounting Regulations for Asset Retirement Obligations Financial Accounting Standards No. 143:
Accounting for Asset Retirement
Obligations (June 2001, based in US). http://www.fasb.org/pdf/fas143.pdf FAS 143 paragraph 7 The fair value of a liability for an asset retirement obligation is the amount at which that liability could be settled in a current transaction between willing parties, that is, other than in a forced or liquidation transaction. Quoted market prices in active markets are the best evidence of fair value and shall be used as the basis for the measurement, if available. If quoted market prices are not available, the estimate of fair value shall be based on the best information available in the circumstances, including prices for similar liabilities and the results of present value (or other valuation) techniques. FAS 143 paragraph A20 In estimating the fair value of a liability for an asset retirement obligation using an expected present value technique, an entity shall begin by estimating cash flows that reflect, to the extent possible, a marketplace assessment of the cost and timing of performing the required retirement activities. The measurement objective is to determine the amount a third party would demand to assume the obligation. Considerations
in
estimating
those
cash flows
include
developing
and
incorporating explicit assumptions, to the extent possible, about all of the following: a. The costs that a third party would incur in performing the tasks necessary to retire the asset b. Other amounts that a third party would include in determining the price of settlement, including, for example, inflation, overhead, equipment charges, profit margin, and advances in technology c. The extent to which the amount of a third party’s costs or the timing of its costs would vary under different future scenarios and the relative probabilities of those scenarios d. The price that a third party would demand and could expect to receive for bearing the uncertainties and unforeseeable circumstances inherent in the obligation, sometimes referred to as a market-risk premium.
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It is expected that uncertainties about the amount and timing of future cash flows can be accommodated by using the expected cash flow technique and therefore will not prevent the determination of a reasonable estimate of fair value. FAS 143 paragraph A21 An entity shall discount estimates of future cash flows using an interest rate that equates to a risk-free interest rate adjusted for the effect of its credit standing (a credit-adjusted risk-free rate). The risk-free interest rate is the interest rate on monetary assets that are essentially risk free and that have maturity dates that coincide with the expected timing of the estimated cash flows required to satisfy the asset retirement obligation. Concepts Statement 7 illustrates an adjustment to the risk-free interest rate to reflect the credit standing of the entity, but acknowledges that adjustments for default risk can be reflected in either the discount rate or the estimated cash flows. The Board believes that in most situations, an entity will know the adjustment required to the risk-free interest rate to reflect its credit standing. Consequently, it would be easier and less complex to reflect that adjustment in the discount rate. In addition, because of the requirements in paragraph 15 relating to upward and downward adjustments in cash flow estimates, it is essential to the operationality of this Statement that the credit standing of the entity be reflected in the interest rate. For those reasons, the Board chose to require that the risk-free rate be adjusted for the credit standing of the entity to determine the discount rate. International Accounting Standards, IAS 37 - Provisions, contingent liabilities and contingent assets [2005] http://www.iasplus.com/standard/ias37.htm The amount recognised as a provision should be the best estimate of the expenditure required to settle the present obligation at the balance sheet date, that is, the amount that an entity would rationally pay to settle the obligation at the balance sheet date or to transfer it to a third party. http://www.iasplus.com/interps/ifric001.htm IAS 37 requires the amount recognised as a provision to be the best estimate of the expenditure required to settle the obligation at the balance sheet date. This is measured at its present value, which IFRIC 1 confirms should be measured using a current market-based discount rate. http://www.iasplus.com/pressrel/2003pr07.pdf
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In the spirit of convergence, the IFRIC considered the US GAAP approach in Statement of Financial Accounting Standards No. 143 Accounting for Asset Retirement Obligations and, in particular, that changes in estimated cash flows are capitalised as part of the cost of the asset and depreciated prospectively, and the decommissioning obligation is not required to be revised to reflect the effect of a change in the current market-assessed discount rate. The IFRIC did not choose this approach because IAS 37, unlike SFAS 143, requires a decommissioning obligation to reflect the effect of a change in the current market-assessed discount rate. The IFRIC agreed that it was important that any Interpretation it developed should deal consistently with changes in estimated cash flows and changes in the discount rate.
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13 Appendix 4 Worked Example of Well Abandonment Estimate for Platform with 30 Wells Phase 1, Type 2 Phase 1, Type 2 Phase 3, Type 1 Phase 2, Type 1 Phase 1, Type 1
Duration
(in P&A Code Table)
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Spread rate
(in P&A Code Table)
Cost Estimate
(in P&A Code Table)
Number of wells
(in P&A Code Table)
Cost Estimate Wells for Field
39
Campaign one-off Cost
ARO Estimate Wells for Field
Guidelines on Well Abandonment Cost Estimation
Number of Wells of Each Type of Abandonment for Each Phase:
Phase
Number of Wells of each Type and Phase
TYPE 4 Complex Rigbased
5
Abandonment Complexity TYPE 1 TYPE 2 TYPE 3 Simple Complex Simple RigRig-less Rigless based 10 10 5
2
10
8
TYPE 0 No work required
1 Reservoir Abandonment Intermediate 2 Abandonment Wellhead Conductor 3 Removal
10
30
Duration - Number of Days required for each Well for each Type and Phase:
Phase
Number of Days for each Well, Type and Phase
TYPE 4 Complex Rigbased
0
Abandonment Complexity TYPE 1 TYPE 2 TYPE 3 Simple Complex Simple RigRig-less Rigless based 3 5 3
0
6
10
TYPE 0 No work required
1 Reservoir Abandonment Intermediate 2 Abandonment Wellhead Conductor 3 Removal
5
0
Spread Rate for each Type: Spread Rate for each Type (nominal currency per day) Platform – fixed rig
TYPE 1 Simple Rig-less 25,000
TYPE 2 Complex Rig-less 35,000
TYPE 3 Simple Rig 55,000
TYPE 4 Complex Rig 55,000
Cost Estimate for All Wells by Type & Phase: Cost Estimate for All Wells by Type & Phase
TYPE 0 No work required
Phase
1 Reservoir Abandonment Intermediate 2 Abandonment 3
Wellhead Removal
0
0 Conductor
Abandonment Complexity TYPE 1 TYPE 2 TYPE 3 Simple Complex Simple Rig-less Rig-less Rigbased 10x3x 10x5x 5x3x 25000= 35000= 55000= 750000 1750000 825000 10x6x 10x5x 35000= 55000= 2100000 2750000
TYPE 4 Complex Rigbased
8x10x 55000= 4400000
0
Estimate for Campaign cost (as per Table 9) = 2,000,000 Cost Estimate Wells for Platform
Issue 2, July 2015
= 14,575,000
40
Guidelines on Well Abandonment Cost Estimation
Prepared by the following Oil and Gas UK Workgroup members: Issue 1 – April 2011
Issue 2 - 2015
Bill Inglis (BP)
Martin Mosley (Talisman)
Garry Skelly (CNRI)
Sandy Fettes (Fairfield)
Jules Schoenmakers (Shell)
Taiwo Olaoya (Oil & Gas UK)
Martin Mosley (Talisman)
Tom Gillibrand (BP)
Max Baumert (ExxonMobil) Phil Chandler (Interact) Steve Brealey (Hess) Steve Kirby (Sasok)
Issue 2, July 2015
41
