hs096 op106 guidelines on well abandonment cost estimation issue 2 july 2015

7/24/2019 HS096 OP106 Guidelines on Well Abandonment Cost Estimation Issue 2 July 2015

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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, ortransmitted in any form or by any means, electronic, mechanical, photocopying, recording orotherwise, without prior written permission of the publishers.

Any material within these guidelines that has been sourced from others has been reproduced withthe permission of its owners. Contains public sector information licensed under the OpenGovernment 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 toreplace 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 theseguidelines 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 noguarantee 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 madeto a particular organisation for the provision of data or information, this does not constitute in anyform whatsoever an endorsement or recommendation of that organisation.

ISBN: 1 903 004 51 9

PUBLISHED BY OIL & GAS UK

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Contents1 Introduct ion .................................................................................................. 6

2 Objective of the Guideline ........................................................................... 7

3 Regulatory Requirements ............................................................................ 8

3.1 Design & Construction Regulations .......................................................................... 8

3.2 Accounting Standards / Protocols ............................................................................. 9

4 Well abandonment Cost Estimation ......................................................... 10

4.1 Introduction to the Estimation Process .................................................................... 10

4.2 Reasons for Cost Estimate Preparation .................................................................. 11

4.2.1 During Field Operation ............................................................................................ 114.2.2 Asset Sale or Transfer ............................................................................................ 124.2.3 End of Well Life or Cessation of Production ............................................................ 12

4.3 Cost Estimate Accuracy in Relation to Abandonment Proximity .............................. 12

4.3.1 Greater than 10 Years to COP ................................................................................ 134.3.2 Between 5 and 10 Years before COP ..................................................................... 134.3.3 Less Than 5 Years before COP .............................................................................. 144.3.4 Well Abandonment Imminent .................................................................................. 144.3.5 Cost Estimate Process Flow ................................................................................... 15

5 Classi fying Wells for Abandonment Cost Estimation ............................. 17

5.1 Use of a P&A Code................................................................................................. 17

5.2 Well Abandonment Location ................................................................................... 18

5.3 Well Abandonment Phases..................................................................................... 18

5.3.1 Phase 1 - Reservoir Abandonment ......................................................................... 18

5.3.2 Phase 2 - Intermediate Abandonment .................................................................... 185.3.3 Phase 3 - Wellhead and Conductor Removal ......................................................... 18

5.4 Well Abandonment Complexity / Work Type ........................................................... 18

5.4.1 Well Abandonment Classification Example 1 .......................................................... 205.4.2 Well Abandonment Classification Example 2 .......................................................... 205.4.3 Well Abandonment Classification Example 3 .......................................................... 20

5.5 Determining Well Abandonment Complexity ........................................................... 21

5.5.1 Using Tables 3.1, 3.2 and 3.3 ................................................................................. 21

6 Well abandonment Duration Estimation ................................................... 25

6.1 Benchmarking of Durations .................................................................................... 25

6.2 Duration of Operations ............................................................................................ 256.3 Contingency & Extreme Event Allowance ............................................................... 26

7 Determining Well Abandonment Phase Costs ......................................... 27

7.1 Cost Assumptions .................................................................................................. 27

7.2 Equipment Spread Costs ........................................................................................ 27

7.3 Operational Support & Ancillary Costs .................................................................... 29

8 Determining Field Well Abandonment Cost ............................................. 30

8.1 Integrating durations, spread rates for a well across phases ................................... 30

8.2 Campaign and Additional Project Costs .................................................................. 30

8.3 Determining Field or Platform Well Abandonment Costs ........................................ 319 References .................................................................................................. 32

10 Appendix 1 .................................................................................................. 33



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11 Appendix 2 .................................................................................................. 35

12 Appendix 3 .................................................................................................. 36

13 Appendix 4 .................................................................................................. 39



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AbbreviationsAFE Authorisation for Expenditure

ARO Asset Retirement Obligation

ASV Annulus Safety ValveCOP Cessation of Production of field

CT Coil Tubing

DCR The Offshore Installations and Wells (Design & Construction, etc)Regulations1996(SI 1996/913)

DECC Department of Energy and Climate Change

DSV Diving Support Vessel

E&A Exploration & Appraisal Wells

HDWIV Heavy Duty Well Intervention Vessel

HLV Heavy Lift Vessel, used for topside, jacket removal

HWU Hydraulic Work-over Unit

LWIV Light Well Intervention Vessel

NPT Non Productive Time

NORM Naturally Occurring Radioactive Material

O&GUK Oil and Gas UK

P&A Plug and Abandon Wells

PM Project Management

SCP Sustained Casing Pressure

UKCS United Kingdom Continental Shelf

WBS Work Breakdown Structure

WDG Well Decommissioning Group

WOW 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 Introduction

1. 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:

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 of production and the preparation of thedecommissioning plan,

high-level decommissioning cost estimation for decommissioning projects.

5. 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 Objective of the Guideline

7. The principles and practices described in this Guideline provide a common approach

to estimating field-wide well abandonment costs. This Guideline outlines best practicebased 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:

a template or common framework against which Operators can prepare theirwell abandonment cost estimates.

a checklist of activities in order that an estimate can be built that is bothconsistent and complete.

a methodology which requires that market rates and activity durations areclearly understood and stated in the cost estimate.

recognition that more detailed estimates will be required as Cessation ofProduction (COP) approaches.

assistance in establishing a greater level of confidence in determiningdecommissioning costs for asset acquisition or divestment (SecurityAgreements, etc.).

a means of both comparing estimates from different sources (third partiese.g. partners, contractors, etc.) and capturing Operators experience.

a framework for benchmarking.

8. 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, fully-

engineered 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 Regulatory Requirements

11. 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 ownersand 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. 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 itare to be taken or make provision as to how those times are to bedetermined;

15. 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 its suspension or abandonment there can be no unplanned escapefrom 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 Introduct ion 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 Guidelineson 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:

Assumpti ons all assumptions made in building the estimate should beclearly stated, e.g.:

I. Regulatory assumptions, compliance with appropriate Guidelines. Statethe issue of the relevant Regulation.

II. Number of platform & subsea wells included (and excluded) from theestimate, e.g. wells expected to have been abandoned during earlier

campaigns.

III. Execution Methodology equipment and practice assumptions behind theestimate (e.g. rig or workover vessel selection, lifting and removaltechniques).

IV. Key market rate and escalation assumptions (rig rates, well abandonmentequipment rates, exchange rates).

V. Key activity duration assumptions (rig days, spread durations) includingallowances for waiting on weather (WOW), non- productive time (NPT),

extreme events.

VI. Campaign strategy, e.g. preparation cost, re-instatement of rig,mobilisation and demobilisation.

High Level Method Statement A description of the overall methodologyadopted 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 wellabandonment activities, (cranes, rig, accommodation, helideck, power and lifesupport).

Accuracy A statement of accuracy levels represented by the cost estimates

is important for clarity and interpretation purposes, given that accuracy shouldincrease as COP approaches (see Section 4.3).

Risk Assessment understanding of key risks that could contribute to therange variation should be clearly identified.

Documentation Cost Estimates evolve over time. It is recommended thatthe document, together with its key documents and assumptions aremaintained securely for future update, review, audit feedback into other costmodels and compliance with the appropriate Regulatory Regime (Appendix3).

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 carefullyconsidered.



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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 Product ion

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 theDepartment 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 AbandonmentProximity

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.

Table 1: Level of accuracy and review relative to proximity to COP

Increasing

levelofaccuracy

required

Time ToCOP

Approach recomm ended toreview wells

Proportion ofWells Required

for Review

ExpectedAccuracy

Range

> 10 yearsField-wide review ofrepresentative wells

10-25% -30% to +50%5 to 10 yrs

Well-by-well review of sampleto define Concept design

< 5yrs

Detailed, full, well-by-wellreview. Timing of

Abandonment Phases mayneed to be considered.

All -15% to +30%

ImminentDetailed well by well review of

status, integrity, work unitsrequired + services cost

All

-5% to +15%

For AFEAFE estimates are out-with the

scope of these guidelinesAll

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, long-

term, 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 carryout risk assessment

4. Classify Location / Phases / Abandonment Complexity of field / wells (Table2)

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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Figure 1: Schematic of ARO Estimation Process for a Field

ARO

Estimate

Wells for

Field

Campaign

one-off

Cost

Cost

Estimate

Wells for

Field

Cost

Estimate(in P&A Code

Table)

Spread

rate(in P&A Code

Table)

Duration(in P&A CodeTable)

Number

of wells(in P&A Code

Table)

Phase 1, Type 1

Phase 2, Type 1

Phase 3, Type 1

Phase 1, Type 2

Phase 1, Type 2



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5 Classifying Wells for Abandonment CostEstimation

47. The development of consistent well P&A cost estimates depends on a commonapproach 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. This guideline proposes classification of wells according to three factors:

Location Of a Well, Platform or Field whether offshore or onshore

Abandonment Complexit y the methodology and equipment required

Abandonment Phases reflecting the three phases of an abandonmentoperation

49. 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 andphasing 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 installingnear-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 withRiser

TYPE 3: Simple Rig-based Abandonment - requiring retrieval of tubing and

casing

The Operator may decide to include sub classification of subsea rigbased reservoir abandonment to reflect the time and spreaddifferences relating to through tubing, coil tubing or completion pulling

operations.

TYPE 4: Complex Rig-based Abandonment May have poor access and poor

cement requiring retrieval of tubing and casing, milling and cement repairs.

62. 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.

63. 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

Location(Single Well, Field or Platform)(May be Offshore or Onshore)

Abandon ment Complexity

Type 0

No workrequired

Type 1Simple

Rig-less

Type 2ComplexRig-less

Type 3Simple

Rig-based

Type 4ComplexRig-based

Phase

1 Reservoir Abandonment

2 IntermediateAbandonment

3 Wellhead 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

Platfo rm Well 17/19-A57


Type 0No workrequired

Type 1SimpleRig-less


Type 3Simple

Rig-based


Phase

1 Reservoir Abandonment X

2 IntermediateAbandonment X

3 Wellhead Conductor Removal X


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






Type 3Simple

Rig-based


Phase

1 Reservoir Abandonment X

2 IntermediateAbandonment X

3 Wellhead Conductor Removal X


66. 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.



Type 0

No workrequired



Type 3Simple

Rig-based


Ph

ase

1 Reservoir Abandonment 5 10 10 5

2 IntermediateAbandonment 2 10 10 8

3 Wellhead Conductor Removal 30



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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.



22/41


Table 3.1: Criteria for Classifying PHASE 1 Well Abandonment Complexity

x:Not Feasible :Required O:OptionalWell Abandonment Complexity

Note #Well Characteristics /Condition at abandonment



Type 3Simple

Rig

Type 4Complex

Rig

1Sustained Casing Pressure due tohydrocarbons or overpressures

X X X

2Not cemented casing or liner atbarrier depths (cap rock)

X X X

3 Restricted access to tubing X X O

4Deep electrical or hydraulic linespresent at barrier depth

X X O

5Annulus Safety Valve (ASV)present

X X O

6 Packer set above cap rock X X O

7Site does not allow for CT/HWUpumping operations

X X O

8 Multiple reservoirs to be isolated X O O

9Tubing has leak (e.g. corrosion,accessories)

X O O

10Inclination >60 deg above packer(wireline access)

X O O

11Well with good integrity, nolimitations

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 restric ted 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 possiblyrequiring 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.



23/41


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.


x:Not Feasible :RequiredO:OptionalWell Abandonment Complexity

Note #Well Characteristics /

Condition at abandonment

Type 1

SimpleRig-less

Type 2

ComplexRig-less

Type 3

SimpleRig

Type 4

ComplexRig

1Sustained Casing Pressure due tohydrocarbons or overpressures

X X X

2 Restricted access to casing X X X

3Not isolated fresh water aquifers /zones

X X X

4Not cemented casing or liner atbarrier depths (cap rock)

X X X

5 Not isolated Shallow gas X X X

6Site does not allow for CT/HWUpumping operations

X X O

7 Poor primary casing cementation X X O8 No tubing in well X O O

9Inclination >60 deg above barrierdepth (wireline access)

X O O

10Well with good integrity, nolimitations, tubing in place

O O O

Notes:

1. Sustained Casing Pressure SCP on any of the casing annuli related to overpressures orhydrocarbon zones shallower than the reservoir, indicates that primary casing cementations have failed andrequire repair for final abandonment.

2. Casing access restricted casing may have collapsed or parted, obstructing access to the productionpacker, 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) scab-

liner. The casing will have to be milled or removed to place a competent barrier. Note: The length betweentop of potential inflow (bottom of caprock formation) and top of barrier must be more than 200 ft to placepermanent barrier (assumed that good cement is achievable).

5. Shallow gas not isolated Un-cemented (low saturation) gas zone will cause leaks to surface whencasing is cut and removed. This can be related to Sustained Casing Pressure. Such zones require isolationafter 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 apermanent 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 bepossible 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 barrieris required that can be placed through the tubing.


x:Not Feasible :RequiredO:Optional Well Abandonment Complexity

Note #Well Characteristics /Condition at abandonment

Type 1

SimpleRig-less

Type 2

ComplexRig-less

Type 3

SimpleRig

Type 4

ComplexRig

1 Poor integrity of conductor X X X

2Platform unable to suspendconductor load during raising

X X O

3Water depth beyond limitation forcutting by LWIV (Subsea well)

X X O

4 Conductor cutting/retrieval rig-less O O O

Notes:

1. Poor integrity of conductor An involved programme will be required in case a conductor has poorintegrity (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 LWIV The cutting equipment typicallyused by a Light Well Intervention Vessel (LWIV) may have water depth limitations, beyond which arig is required.

4. Conductor: Site can accommodate r ig -less cutting and retrieval sp read 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 standpoint whether to include or

exclude conductor retrieval in Phase 3, in the event that the conductors are to be retrieved byHeavy Lift Vessel.



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6 Well abandonment Duration Estimation

78. 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 wellabandonment 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 isanticipated 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 thefollowing steps:

Define scope and assumptions for each phase and Type, as captured in theP&A code.

Determining phase durations either by benchmarking using internal andexternal data sources or using deterministic modelling.

Determining NPT and WOW, either by benchmarking or using deterministicmodelling.

Establish degree of skew and determine P10, P50, P90 and Mean. (if

applicable)



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83. Table 4 provides illustrative durations for different phases and complexities of

abandonment.

84. Table 4: Illustrative Durations for Different Well Abandonment Complexities & Phases

Platform Well (Days)





Type 3Simple

Rig-based


Phase

1 Reservoir Abandonment 0 3 5 3 7

2 IntermediateAbandonment 0 3 6 5 10

3 Wellhead Conductor Removal 0 2 4 2 8

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 Costs92. 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;

todays 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.



28/41


Table 5: Work unit & Equipment Spreads for different locations, complexity

LocationType 1

SimpleRig-less

Type 2

Complex Rig-less

Type 3

Simple Rig

Type 4

Complex Rig

Onshore Pump spread CT, HWU Rig / hoist Rig / hoist

Platform with

support vesselPump spread CT spread

Platform with

modular rigPump spread CT spread

Modular Rig

spread

Modular Rig

spread

Platform with

fixed rigPump spread CT spread

Platform Rig

spread

Platform Rig

spread

Platform with

jack-up

Pump spread +

Accom. spreadCT spread

Jack-up

spreadJack-up spread

SubseaLWIV

SpreadLWIV spread Semi spread Semi spread

Subsea

Deep water

Semi/drillship

spread

Semi/drillship

spread

Legend

Pump

spread

Electric and slick line, pumping services, cementing spread.

CT /HWU

spread

Coiled tubing (CT) or Hydraulic Work-over Unit (HWU), electric and slick line,

pumping services, cementing spread. Tubing and casing cutting and recovery

services.

Rig

spread

Functional drilling rig, electric and slick line, cementing and pumping services,

tubing and casing cutting and recovery.

LWIV

spread

Light Well Intervention Vessel, equipped with all services necessary to

perform that phase of work. This may include diving services.

Semi

spread

Functional semi-submersible rig suitable for the location, electric and slick

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.



29/41


Table 6 Illustrative Example Spread Costs for Different Complexity/Types

Site/Installation type

(nominal currency per day)

Type 1

Simple Rig-less

Type 2

ComplexRig-less

Type 3

Simple Rig

Type 4

Complex Rig

Onshore 5,000 10,000 35,000 35,000

Platform with support vessel 20,000 25,000

Platform modular rig 25,000 35,000 55,000 55,000

Platform fixed rig 25,000 35,000 55,000 55,000

Platform jack-up 70,000 90,000 110,000 110,000

Subsea 140,000 170,000 220,000 220,000

Subsea Deep water 300,000 300,000 300,000 300,000

The numbers used in this table are illustrative

7.3 Operational Support & Ancil lary 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.



30/41


8 Determining Field Well Abandonment Cost

8.1 Integrating durations, spread rates for a well across

phases99. 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

Platform Well (Days)Type 1SimpleRig-less


Type 3Simple

Rig

Type 4Complex

Rig

Phase


2 Intermediate Abandonment 3 6 5 10

3 Wellhead Conductor Removal 2 4 2 8

Table 8 - Example of Estimated Spread cost per Phase

Site/Installation type (nominalcurrency per day)

Type 1SimpleRigless

Type 2ComplexRigless

Type 3Simple Rig

Type 4Complex Rig


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.



31/41


Table 9 - Project / Campaign Factors for Consideration

Issues Discussion

Management overhead

and engineering

Most abandonment project ARO will include a management overhead. This is

specifically intended to capture the engineering specifically associated withwell abandonment i.e. well file review and categorisation, conceptual design,detail programme development, contracting and procurement, HSEdocumentation, etc.

Well Inspection /Surveys

Well diagnostics would include well surveillance, surveys and inspections ofthe wells prior to detail operational planning to determine well condition andability to access.

Location surveys 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 patternsurveys.

Site preparation For subsea wells this will include fishing net and protective structure removal.

Platform Rig Upgrade This would include rig upgrade cost, recertification etc.

Final removal of a platform rig is carried in the facilities removal budget.

Riser and subsea welltools

Inspection/refurbishment of subsea tools and connectors. Preparation ofrisers may be required.

Mobilisation &Demobilisation of rigand rig equipment.

The installation of a temporary modular platform rig. It would also includeremoval of a temporary modular rig.

For a semisubmersible this would include the cost of bringing and removingthe rig from site.

Mobilisation &Demobilisation

This is the general cost of mobilising rig or rig-less equipment to well site forthe abandonment operations.

Transport to shore /Logistics

These include helicopters, vessels and supply base support.

These may well have been included in the development of spread costs forthe various phases. If not then they should be identified separately.

NORM Scale treatmentand decontamination.

It is possible that tubulars recovered from a well will be contaminated. Thecost of dealing with this should be addressed.

Post removal surveyand trawl

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.



32/41


9 References1. 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 AssetRetirement Obligations (June 2001, based in US).

http://www.fasb.org/pdf/fas143.pdf

4. International Accounting Standards, IAS 37 - Provisions, contingent liabilities andcontingent assets [2005]http://www.iasplus.com/standard/ias37.htm

http://www.fasb.org/pdf/fas143.pdfhttp://www.fasb.org/pdf/fas143.pdfhttp://www.iasplus.com/standard/ias37.htmhttp://www.iasplus.com/standard/ias37.htmhttp://www.iasplus.com/standard/ias37.htmhttp://www.iasplus.com/standard/ias37.htmhttp://www.fasb.org/pdf/fas143.pdf


33/41


10 Appendix 1

O&GUK Decommissioning Estimating

Guideline InterfaceWith 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 pro-

rated.



34/41


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 andabandoned 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.



35/41


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.

EQUIPMENT and SERVICESto be considered for spread rate estimate

1 Office staff management, support, consultancy

2 On-board supervision

3 Rig equipment + crew

4 Coiled tubing unit + crew

5 Hydraulic Workover Unit + crew6 Accommodation and Catering

7 Crane operation

8 Electrical generators

9 Scaffolding service

10 BOP rentals

11 Riser rentals

12 Slick line service + crew

13 Electric line service + crew

14 Perforations, punches, tubing cutting + expert

15 Logging cement tops and bond, corrosion

16 Pumping, cementing services (tanks, pumps, blenders + crew)

17 Cement and additives

18 Packers, bridge plugs

19 Wellhead and X-tree removal services

20 Temporary pipe work, valves (chicksans, etc)

21 Casing cutting, retrieval

22 Casing milling services

23 Tubular handling services

24 Fluids and chemicals + services

25 Fluid waste storage tanks, transport, disposal

26 Equipment disposal

27 NORM disposal

28 HSE equipment (H2S, Norm, survival, etc)29 Supply vessels, dock and storage fees, road transport

30 Move vessels, positioning

31 Helicopter transport

32 Diving support

33 ROV services

34 Conductors cutting + crew

35 Conductor retrieval (sectioning, raising, handling, cleaning, transport) +crew



36/41


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 partys 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 forbearing the uncertainties and unforeseeable circumstances inherent in the

obligation, sometimes referred to as a market-risk premium.

http://www.fasb.org/pdf/fas143.pdfhttp://www.fasb.org/pdf/fas143.pdfhttp://www.fasb.org/pdf/fas143.pdf


37/41


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, butacknowledges 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

liabiliti es 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

http://www.iasplus.com/standard/ias37.htmhttp://www.iasplus.com/standard/ias37.htmhttp://www.iasplus.com/interps/ifric001.htmhttp://www.iasplus.com/interps/ifric001.htmhttp://www.iasplus.com/pressrel/2003pr07.pdfhttp://www.iasplus.com/pressrel/2003pr07.pdfhttp://www.iasplus.com/pressrel/2003pr07.pdfhttp://www.iasplus.com/interps/ifric001.htmhttp://www.iasplus.com/standard/ias37.htm


38/41


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.



39/41


13 Appendix 4

Worked Example of Well Abandonment Estimate for Platform with 30 Wells

ARO

Estimate

Wells for

Field

Campaign

one-off

Cost

Cost

Estimate

Wells for

Field

Cost

Estimate(in P&A Code

Table)

Spread

rate(in P&A Code

Table)

Duration(in P&A Code

Table)

Number

of wells(in P&A Code

Table)

Phase 1, Type 1

Phase 2, Type 1

Phase 3, Type 1

Phase 1, Type 2

Phase 1, Type 2



40/41


Number of Wells of Each Type of Abandonment for Each Phase:

Number of Wells of eachType and Phase

Abandonment Complexity

TYPE 0No workrequired

TYPE 1Simple

Rig-less

TYPE 2ComplexRig-less

TYPE 3Simple

Rig-based

TYPE 4Complex

Rig-based

Phase


2IntermediateAbandonment

2 10 10 8

3Wellhead ConductorRemoval

30

Duration - Number of Days required for each Well for each Type and Phase:

Number of Days for eachWell, Type and Phase



TYPE 1SimpleRig-less


TYPE 3SimpleRig-

based

TYPE 4ComplexRig-

based

Phase



0 6 5 10


0

Spread Rate for each Type:

Spread Rate for each Type(nominal currency per day) TYPE 1SimpleRig-less


TYPE 3Simple Rig TYPE 4ComplexRig


Cost Estimate for All Wells by Type & Phase:

Cost Estimate for All Wellsby Type & Phase



TYPE 1SimpleRig-less


TYPE 3Simple

Rig-based

TYPE 4Complex

Rig-based

Phase

1 Reservoir Abandonment 010x3x

25000=750000

10x5x35000=1750000

5x3x55000=825000


010x6x

35000=2100000

10x5x55000=2750000

8x10x55000=4400000


0

Estimate for Campaign cost (as per Table 9) = 2,000,000

Cost Estimate Wells for Platform = 14,575,000



41/41


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)

hs096 op106 guidelines on well abandonment cost estimation issue 2 july 2015

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