Yme new development high level evaluation of … High level evaluation of electrification alternative 21.12.2017 Confidential © 2017 Aker Solutions inspirer-Yme ,new ,development,

REPSOL Page 1 of 16 104174-Z-RA-00001

YME, High level evaluation of electrification alternative 21.12.2017

Confidential © 2017 Aker Solutions

Yme new development, High level evaluation of

electrification alternative




Table of Contents

1 Introduction and Objectives ................................................................................................... 4

1.1 Introduction............................................................................................................................. 4

1.2 Objective ................................................................................................................................ 4

1.3 Changes in revision 2 ............................................................................................................. 4

2 Summary and Conclusions .................................................................................................... 5

3 Technical evaluation ............................................................................................................... 6

3.1 Electrical Calculations / Verifications ...................................................................................... 6

3.2 Electrical Equipment Arrangement ......................................................................................... 8

3.3 Onshore installation ................................................................................................................ 8

3.4 Offshore installation ................................................................................................................ 9

4 Cost elements and risks evaluations ................................................................................... 11

4.1 Cost estimate evaluation ...................................................................................................... 11

4.2 Onshore and Subsea cost elements ..................................................................................... 11

4.3 Maersk Inspirer modifications ............................................................................................... 11

4.4 Secondary CAPEX ............................................................................................................... 11

4.5 OPEX ................................................................................................................................... 12

4.6 ABEX.................................................................................................................................... 12

4.7 Quantitative cost risk assessment ........................................................................................ 12

4.8 Risk Register ........................................................................................................................ 14

5 Project schedule – schedule risk evaluations ..................................................................... 15

6 Appendices ............................................................................................................................ 16

Appendix A4.1: ............................................................................................................................. 16




1 Introduction and Objectives

1.1 Introduction

Aker Solutions have been requested by Repsol Norge AS to perform an evaluation of the

electrification alternative for the Yme new development, related to technical solution and cost

estimate.

Figure 1.1-1 Field layout, Yme new development

1.2 Objective

This evaluation shall at a high level evaluate the proposed technical solution and assess the cost

estimate provided by the client.

1.3 Changes in revision 2

Appdendix A4.1 (Cost setup for scenario 1-Power from shore ) is attached to this report.




2 Summary and Conclusions

This document contains the result from a high level assessment of the technical solutions

presented in the Unitec report, and Repsol Capex estimate.

The work evaluates power from shore in combination with the Maersk Inspirer Jack-up platform.

The proposed technical solutions seem to be feasible, and reflects the maturity of the design.

The cost estimate has been reviewed and subjected to a cost-risk assessment, and based on a

70% confidence level, the contingency is assumed to be approximately 25%




3 Technical evaluation

3.1 Electrical Calculations / Verifications

The YND network with power from shore has been evaluated at a high level. The verification is based on the proposed technical solutions presented in the Unitech report (YME04-25429-Z-RA-R001) without doing any additional calculations/analysis. The power transfer and 50/60Hz conversion from onshore to offshore seems to be feasible,

however there will be some challenges related to voltage control and reactive power flow.

Power source is onshore and large transient behavior offshore will not have an efficient local

source for rapid voltage recovering etc. This may require modifications to the starter arrangement

for installed 6,6 kV motors.

In steady state condition there will be large load variations from average to max. peak load.

However the transfer voltage is set high at 100kV that will contribute to limit voltage variation

offshore. The offshore step down transformers should anyway be equipped with load tap changers.

It is assumed that the transfer voltage level has been optimized in previous calculations.

The long transfer length from onshore to offshore at high voltage level will produce high amount of

capacitive/reactive power. Adjustable reactors are proposed in the Unitec study to be placed

onshore to compensate for the reactive power produced by the subsea cable. This will also help

stabilizing the voltage variation caused by load changes etc. and protect the 50/60Hz converters.

Detailed engineering may show that Harmonic filters are required, and these should be part of the

frequency converter packages onshore.

Due to the 50/60Hz conversion and use of two converters in in parallel the onshore station area will

be large including step down and step up transformers primary and secondary.




Figure 1 Electrical System configuration (from Unitech report)




3.2 Electrical Equipment Arrangement

The following equipment is identified in the Unitech report, and Aker Solutions has collected data

for sizes and weights as shown in the table below.

Equipment (ref. Unitec report)

Area Length (m)

With (m)

Height (m)

Weight (ton)

Comments

Step down Transformer 1 35 MVA

Onshore 6,0 4,6 4,5 68 In-house data

Step down Transformer 2 35 MVA


VSD 1 50/60 Hz converter 35 MVA

Onshore 15,8 2,4 2,8 20 Catalog info

VSD 2 50/60 Hz converter 35 MVA

Onshore 15,8 2,4 2,8 20 Catalog info

Step UP Transformer 1 35 MVA


Step UP Transformer 2 35 MVA


Reactor 1 20-40 MVAr Onshore 2,0 2,0 3,0 2 In-house data

Reactor 2 20-40 MVAr Onshore 2,0 2,0 3,0 2 In-house data

Switchgear Onshore 4,8 4,1 2,6 20 Catalog info

Landfall breaker Onshore 1,0 4,1 2,6 3 Catalog info

Onshore power cable Onshore 12 000

Subsea cable Offshore 114 000

Switchgear Offshore 3,2 4,1 2,6 12 Catalog info

Transformer 1 30 MVA Offshore 6,0 4,6 4,5 68 In-house data

Transformer 2 30 MVA Offshore 6,0 4,6 4,5 68 In-house data

Offshore module Offshore 14 15 6 400-500

Weight included equipment

Electrical Boiler Offshore 7,5 6 5 42 Lifting weight 26 ton

3.3 Onshore installation

The onshore VSD and switchgear needs to be installed in a building design for high voltage

equipment. The size of the building is estimated to be approximately 33x17x6 m (LxWxH)

Area for this need to be clarified and included in the design for the onshore facilities.




Figure 2 onshore building Example

In addition to the above mentioned building, space for two reactors, power cables, overhead lines

and landfall needs to be found. The acquisition of land can be an issue and needs to be further

addressed.

From the Unitech report (YME04-25429-Z-RA-R001) the following is stated:

Due to lack of space at Kjelland substation, acquisition of land will be required for the onshore equipment. The system topology shown will require even more space than the 2013 concept. Acquisition of land is in general disputed, and transformer stations are normally not a desired neighbour; this may impact the time schedule.

3.4 Offshore installation

The required offshore equipment related to electrification consists of 2 step down transformers and

4 off gas insulated switches.

For estimation purposes, the offshore concept is assumed to be installation of a new electrical

module to house all required electrical equipment, to be lifted onboard by heavy lift vessel (HLV)

offshore. Size of such module is indicated in figure 3 below.




Figure 3 Electrical module example

In addition to this module an electrical boiler is required to replace the Waste heating recovery

units placed on the Generator turbines. Space for this boiler sized 7,5x6x5 m (LxWxH) needs also

to be found on the platform. To install this equipment on the platform will use the most of the

weight reserves on the platform and is necessary to keep in mind. The necessary structural

reinforcement is not considered in this evaluation.

Figure 4 Electrical boiler example

4 off switchgear (GIS)

Total LxWxH 2,4 x 4,1, x 2,6m 10 t

2 off transformers

Each LxWxH 4 x 4,6 x, 4,9 m 116 t




4 Cost elements and risks evaluations

4.1 Cost estimate evaluation

The evaluation is based on CAPEX as estimated by Repsol Norge AS of Scenario 1, ref appendix

4.1. The following chapter headlines refer directly to the structure in the Capex estimate.

4.2 Onshore and Subsea cost elements

The review has not disclosed any elements omitted from the estimate. Main uncertainties are

related to validity of assumptions from previous estimates and general uplift of cost based on

public indices.

Cost for project management and project support has been included in other cost elements (ref.

e.g. “Power From Shore management and design including assistance with permits, etc.”) These

elements must account for all cost relating to the onshore process, such as involvement of

stakeholders, and entities from landowners to public political authorities. It is recommended that

this process need to be specifically addressed in future phases.

In the cost risk simulation model -20%/+40% is included as cost spread.

4.3 Maersk Inspirer modifications

The maturity of scope definition for the rig modification should be further developed in future

phases. Compared to inhouse experience, the estimated figures seem moderately low. In the risk

modelling, a general spread -10%/+40% is therefore applied.

Ref. the risk register, see section 4.8 below, for cost related to scope for anticipated structural

reinforcements of the platform deck and potential downstream cost for modifications related to

other disciplines.

The HLV market is fluctuating and the rates vary correspondingly. Best case/worst case are

assessed based on inhouse experience.

4.4 Secondary CAPEX

It is assumed that this element to cover Engineering and Management cost.

Based on in-house experience figures, it is considered that the engineering budget for design of

power module is adequate. Remaining offshore brownfield engineering seems to be under-

estimated. A general spread of -5%/+40% is therefore applied.




4.5 OPEX

The figures are mainly from Unitec and from internal Repsol calculations. It is assumed that these

figures are updated and not only uplift of previous estimates. AKSO has not evaluated these

numbers in any detail but on an overall level the estimates are considered reasonable.

4.6 ABEX

The estimate structure indicates that ABEX uncertainty shall not be reflected in the contingency

allocations. The ABEX estimates have not been evaluated by AKSO.

The cost of rig reinstatement is dependent on the magnitude of modifications and may therefore be

seen as a function of “Maersk Inspirer modifications”. AKSO experience indicates that the

complexity of reinstatement is frequently underrated hence the uncertainty is considered to be

high.

4.7 Quantitative cost risk assessment

A cost risk analysis has been run based on the cost estimate with associated risks and

uncertainties as described in this chapter. The results are shown in the table below and the figure

overleaf. Input values from the Repsol cost estimate is shown in the “Base” column.

Name Mean Stdev Variance Base P10 P50 P70 P90

Total Onshore & Subsea cost 1 318 288,92 294 443,31 86 696 862 461,07 1 240 020,29 970 849,43 1 284 226,22 1 443 740,14 1 706 771,15

Maersk Inspirer Modification Cost 717 787,93 135 054,16 18 239 626 952,30 651 553,85 556 153,26 704 325,76 776 357,24 896 219,44

Total Engineering Cost 119 102,35 15 190,97 230 765 459,98 113 302,80 100 412,65 118 090,63 126 154,49 139 031,66

CAPEX excl. Risk register Items 2 155 179,20 443 845,29 196 998 644 892,16 2 004 876,94 1 629 146,32 2 107 015,73 2 345 566,91 2 738 677,78

Sum Risk Register Items 154 250,07 58 174,30 3 384 248 715,93 170 000,00 82 440,81 150 617,66 178 930,66 227 336,77

CAPEX incl. Risk register Items 2 309 429,28 448 011,98 200 714 735 756,04 2 004 876,94 1 774 311,40 2 263 255,72 2 505 058,15 2 901 705,65

ABEX 49 611,78 0 0 49 611,78 49 611,78 49 611,78 49 611,78 49 611,78

OPEX 598 388,30 0 0 598 388,30 598 388,30 598 388,30 598 388,30 598 388,30

Total Cost YME PfS 2 957 429,35 448 011,98 200 714 735 755,94 2 652 877,01 2 422 311,47 2 911 255,80 3 153 058,22 3 549 705,72




Based on a 70% confidence level, the estimated contingency is approx. 501MNOK (25%).




4.8 Risk Register

Risk ID Risk Title Cause Consequence Current Risk Level Low case Likely High case

7713Fluctuating pow er supply at Maersk

inspirer

Pow er requirements at start-up of heavy equipment (e.g. big motors)

combined w ith long pow er transfer distance

Potentially additional cost due to requirements to reduce

f luctuationsHigh: 21 20 000 000 30 000 000 50 000 000

7714 Challenges related to land aquisition

Aquisition of land/rights to cross properties is normally controversial.

Validity of previous agreements is uncertain.

Ref. also Unitech Report ch. 8.2.

Potential for additional cost and long lasting processes

impacting proect scheduleMedium: 14

7715Lead time for equipment and subsea

cable

Equipment and cable far from standard. Lead time for compressors

estimated to 18-24 monthsPotentially long lead times affecting project schedule Medium: 13

7716Requirements for structural

reinforcements of Maersk Inspirer

Current CoG is unfavourable and the capacity to accommodate

additional w eight is limited. A new electro module w eighing approx.

500t w ill probably require topside structural reinforcements.

Due to reinstatement clause, removal of equipment to reduce w eight is

very costly

Additional cost Medium: 12 20 000 000 40 000 000 60 000 000

7717Additional requirements for

modif ications of Maersk Inspirer

Limited w eight- and space reserves available at Maersk Inspirer

Dow nstream consequences of a new electro module on e.g. safety

systems and HVAC has not been evaluated

Additional modif ications/upgrade potentially having cost

or/and schedule impact. Consequences may be

exacerbated by limited availability of w eight- and space

reserves

Medium: 17 50 000 000 100 000 000 150 000 000

7718Requirement to remove generators

(GTG)

Requirement for topside w eight reduction due to fatigue calculations

or/and new equipment leading to insuff icient topside w eight capacity

Increased cost. Contractual obligation related to rig

reinstatement condition implies that generators must be

stored, preserved/maintained, tested and re-installed.

Medium: 10 5 000 000 10 000 000 20 000 000

7719 HLV operations subject to riskCost of HLV operations is exposed to market rate f luctuations,

w eather conditions and other factors affecting the duration

Cost or/and schedule impact (may be positive or negative

depending on estimate/planning assumptions)NIL: 0

7720 Changes to onshore grid

New ow ners of Kjelland substation.

Statnett has decided to establish a new 300kV sub-station in

Bjerkreim. Kjelland substation may lose 300kV connection

A connection to the new Bjerkreim substation w ill most

likely require a full new process incl. application for

consession. Increased distance for onshore cable hence

increased cost. Potentially additional challenges related to

land aquisition

Medium: 11

7733 Estimate uncertainty

The estimate has been compiled based on previous estimates and

quotes. No thorough review and update of estimates and verif ication

of the validity of assumptions has been undertaken

Considerable uncertainty related to the cost estimate High: 20

7734 Reduced field life

The new 500t electro module may - due to w eight and space

constraints - lead to reduced possibilities for tie-back of future

prospects

Economically disadvantageous for Company and for future

prospectsNIL: 0

covered by estimate uncertainties

not evaluated

covered by estimate uncertainties

Yme Power From Shore Simplified Risk Register for Project 08.12.2017Multi-currency report

This report w ill by default convert and show all values in NOK although your project might have been set up w ith another default currency. To convert all values to another currency, use

the "Report currency" parameter at the top.

10 Risk(s)

Covered under schedule uncerainty and

cost uncertainty

Schedule

This register contains risks identified by Aker Solutions, on the basis of the capex estimate and described technical solution during this assessment.

Transformers




5 Project schedule – schedule risk evaluations

The schedule driver for the Yme PfS alternative will probably be the onshore process. The likely

durations are described and assessed in the Unitech report. It should be noted that risks related to

the onshore grid connection (ref. risk register) will add significantly to the project duration.

Cost consequences of exposure to schedule risk have not been evaluated




6 Appendices

Appendix A4.1:

CASE: Power Solutions Scenario 1

Power From Shore

Yme New Developement Base Assumptions:

-Average electrical power consumption YND is 16.7

MW

-Average Heat load is 8MW

- Average electrical power and heat load 25.7 MW.

- Peak load 54 MW

- Electrical system on Maersk Inspirer is 60Hz

-Electrical system onshore is 50Hz

- Expected operations is 10 years commencing in 2020

-Onshore tie-in for power at Kjelland

-Transmission voltage = 100Kv (Optimal)

- 50kv breakers are already installed in substation

Electrical power provided via

subsea cable via transformers

located at Kjelland. Required

electrical & utility equipment

installed on MI. Expected

completion date 2021. Offshore

modification and installation

campaign.

Fuel gas used until PfS ready, and

injected afterwards.

Production start-up as planned.

Sum Total Cost (CAPEX + OPEX + ABEX) 3 035 852 402

CAPEX Cost Total 2 387 852 327

Onshore & Subsea 1 240 020 287

Transformer 35 MVA 50/?? kV x 4 36 650 943

Transformer connection / transport / traffic cell 6 108 491

123 kV cable 4 886 792

123 kV mounting 1 832 547

2 x 35MVA frequency converters (VSDs) 24 000 000

Housing unit for onshore equipment. Approx. 200m2 5 000 000

123kv Onshore switchboard x 5 ea 40 000 000,00

Installation and connecting to main power grid at Kjelland 16 500 000,00

2 x38 MVAr Reactors 18 000 000

Onshore Cable & Installation 82 223 902

Procuremente Subsea Cable 554 508 682

Seabed survey 10 000 000

Installation and trenching of subea cable 403 288 662

Flexible Cable connection from Caisson to MI. 7 500 000

Landfall joint and switch for subsea cable 6 000 000 Design and management of onshore activities including

vendor followup 23 520 268

Maersk Inspirer modifications 651 553 852

Costs for GTGs (2 ea.) 13 726 628

Costs for WHRUs 7 249 493

Installation costs for WHRU 4 800 000

Structural steel for modularization of power module Eq: 300 000 000

123kV SF6 switchboard including installation 9 418 182

2 ea 123kV/6.6kV-30MVA transfomers 24 868 233

13mW Eletrical boiler including installation 16 402 451

Heavy lift vessel for installation of offshore power module 90 000 000

Offshore installation of equipment 25 344 433

Offshoreremoval of equipment 25 344 433

Installation and removal of lifiting aids 16 000 000

Bulk items (instrument, piping, etc.) ~56 tonne 112 000 000

Structural reinforcements for packages

Yard stay costs applicable for PfS work 6 400 000

Secondary Capex costs 496 278 188

Engineering re-work during Detailed Design:

Area classification 158 400

Single line item diagrams & Distribution drawings 1 713 600

MEL 27 000

Utility layout and diagrams 91 800

Layout 495 000

P&ID 990 000

Trip specifictions 252 000

HAZOP and HAZID for PfS equipment and deisgn 1 350 000

Revised Weight report 225 000

Design of power module 90 000 000 Power From Shore management and design including

assistance with permits, etc. 18 000 000

CAPEX Contingency 382 975 388

OPEX Cost 598 388 298

Cost for Diesel 10 000 000

Purchase of electricty for PfS 425 894 304

Maintenance of PfS Equipment 16 000 000

Maintenance of GTG & utilities 3 660 000

Diesel Taxes 1 900 000

Fuel gas taxes 77 000 000

Increase in rates for extension of production contract for 2 years. -

ABEX Costs 49 611 777

Removal of PfS Equipment from Maersk Inspirer 12 672 217

Removal of Onshore Equipment 1 650 000

Removal of Onshore Cable 32 889 561

Removal of generators and WHRU's from MI 2 400 000

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Yme new development high level evaluation of … High level evaluation of electrification alternative 21.12.2017 Confidential © 2017 Aker Solutions inspirer-Yme ,new ,development,