5. MARCO TEORICO
5.1 BASES TEORICAS
5.1.10. La Enseñanza Problémica
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.
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
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 pro- rated.
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.
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 SERVICES
to 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 + crew 6 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
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.
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.
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.
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
Number of Wells of Each Type of Abandonment for Each Phase: Number of Wells of each
Type and Phase
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 P hase 1 Reservoir Abandonment 5 10 10 5 2 Intermediate Abandonment 2 10 10 8 3 Wellhead Conductor Removal 30
Duration - Number of Days required for each Well for each Type and Phase: Number of Days for each
Well, Type and Phase
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 P hase 1 Reservoir Abandonment 0 3 5 3 2 Intermediate Abandonment 0 6 5 10 3 Wellhead Conductor Removal 0
Spread Rate for each Type: Spread Rate for each Type (nominal currency per day)
TYPE 1 Simple Rig-less TYPE 2 Complex Rig-less TYPE 3 Simple Rig TYPE 4 Complex Rig
Platform – fixed rig 25,000 35,000 55,000 55,000
Cost Estimate for All Wells by Type & Phase: Cost Estimate for All Wells
by Type & Phase
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 P hase 1 Reservoir Abandonment 0 10x3x 25000= 750000 10x5x 35000= 1750000 5x3x 55000= 825000 2 Intermediate Abandonment 0 10x6x 35000= 2100000 10x5x 55000= 2750000 8x10x 55000= 4400000 3 Wellhead Conductor Removal 0
Estimate for Campaign cost (as per Table 9) = 2,000,000 Cost Estimate Wells for Platform = 14,575,000
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)