Zidane BOV - Drilling and Completion Support Document Rev01

Zidane: BOV Drilling and Completion Support Document

PL435 Blocks, Zidane R-018832

Drilling and Completion Support Document PL435 Blocks Zidane

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DOCUMENT / REPORT TITLE AND APPROVAL PAGE

Title: Zidane: BOV Drilling and Completion Support Document Project: PL435 Zidane

Doc.ID/R.no.: R-018832

File No.:

Classification:

Subject:

Distribution:

Responsible Dept.: O Valid/Issue Date: 09.11.2012 Rev.No.: 01

Prepared by/ Self Check

Dept./Name: O / T. Theloy, B.O. Dahle

Rev.No.: 01

Date:

Sign.:

Verification

Dept./Name: O / . Aarflot

Rev.No.: 01

Date: Sign.:

Approval

Dept./Name: O / J.P. Rd

Rev.No.: 01

Date: Sign.:


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Contents

1 INTRODUCTION ....................................................................................................................................... 6

2 GENERAL INFORMATION ..................................................................................................................... 7

2.1 LOCATION AND LICENSE PARTNERS ...................................................................................................... 7 2.2 PROJECT ORGANIZATION ....................................................................................................................... 7 2.3 GOVERNING AND GUIDING DOCUMENTS ............................................................................................... 8

3 ZIDANE FIELD DEVELOPMENT ........................................................................................................... 9

3.1 FIELD DEVELOPMENT CONCEPT ............................................................................................................ 9 3.2 WELL OBJECTIVES ................................................................................................................................. 9 3.3 DRILLING SUMMARY ............................................................................................................................. 9 3.4 COMPLETION SUMMARY ........................................................................................................................ 9

4 HSE ............................................................................................................................................................. 11

4.1 INTRODUCTION .................................................................................................................................... 11 4.2 RISK AND EMERGENCY PREPAREDNESS ............................................................................................... 11 4.3 ENVIRONMENT AND DISCHARGES ........................................................................................................ 11 4.4 CHEMICAL MANAGEMENT .................................................................................................................... 11

5 GEOLOGICAL WELL DESIGN INPUT ............................................................................................... 12

5.1 STRATIGRAPHY .................................................................................................................................... 12 5.1.1 Stratigraphy of Zidane East, 6507/7-14 S ....................................................................................... 12 5.1.2 Stratigraphy of Zidane West, 6507/7-15 S ...................................................................................... 13

5.2 TEMPERATURE ..................................................................................................................................... 14 5.3 PORE PRESSURE AND FRACTURE GRADIENT ........................................................................................ 14

5.3.1 Pore Pressure and Fracture Gradient of Zidane East, 6507-7/14 S............................................... 15 5.3.2 Pore Pressure and Fracture Gradient of Zidane West, 6507-7/15 S .............................................. 16

6 SUBSEA TEMPLATE AND SITE SURVEY .......................................................................................... 17

6.1 TEMPLATE LOCATION .......................................................................................................................... 17 6.2 NUMBER OF SLOTS ............................................................................................................................... 18 6.3 SHALLOW HAZARD REVIEW ................................................................................................................. 18 6.4 COLD WATER CORALS .......................................................................................................................... 20

7 DIRECTIONAL DRILLING .................................................................................................................... 22

7.1 WELL PATH DESIGN ............................................................................................................................ 22 7.1.1 Wellbore stability ............................................................................................................................ 24 7.1.2 Structural faults below BCU ........................................................................................................... 24 7.1.3 Top Garn Pick ................................................................................................................................. 24 7.1.4 Horizontal well paths ...................................................................................................................... 24

7.2 DIRECTIONAL DRILLING AND SURVEYING ........................................................................................... 25 7.3 DRILL STRING DESIGN ......................................................................................................................... 26 7.4 RELIEF WELLS ..................................................................................................................................... 26 7.5 CHALLENGES AND RISKS ..................................................................................................................... 26

8 CASING DESIGN ...................................................................................................................................... 27

8.1 CASING SHOE DEPTHS ......................................................................................................................... 27 8.2 CASING TEST PRESSURES ..................................................................................................................... 28 8.3 CASING STRING SELECTION ................................................................................................................. 28 8.4 CONTINGENCY CASING PROGRAM ....................................................................................................... 28 8.5 DRILLING WELL SCHEMATIC ............................................................................................................... 29 8.6 BLOWOUT & KILL ANALYSIS............................................................................................................... 30 8.7 CHALLENGES & RISKS ......................................................................................................................... 31

9 DRILLING FLUIDS .................................................................................................................................. 32


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10 CEMENTING PROGRAM ...................................................................................................................... 33

11 GENERAL COMPLETION DESIGN ..................................................................................................... 34

11.1 INTRODUCTION .................................................................................................................................... 34 11.2 COMPLETION OBJECTIVES ................................................................................................................... 34 11.3 GENERAL WELL DESIGN ...................................................................................................................... 35 11.4 LOWER (SANDFACE) COMPLETION ...................................................................................................... 37

11.4.1 Lower Completion Scoping ........................................................................................................ 39 11.4.2 Zonal Isolation - Cement plug-back ........................................................................................... 42 11.4.3 Swell packers .............................................................................................................................. 42

11.5 MIDDLE COMPLETION DESIGN (BARRIER ASSEMBLY) ......................................................................... 43 11.6 UPPER COMPLETION DESIGN ................................................................................................................ 44

11.6.1 Introduction ................................................................................................................................ 44 11.6.2 Production tubing ....................................................................................................................... 45 11.6.3 Production packer ...................................................................................................................... 45 11.6.4 Flow control equipment .............................................................................................................. 46 11.6.5 Downhole chemical injection (DCI) ........................................................................................... 46 11.6.6 Downhole pressure and temperature monitoring ....................................................................... 46 11.6.7 Down hole safety valve (DHSV) ................................................................................................. 46

11.7 COMPLETION OPERATIONAL STEPS ..................................................................................................... 48 11.8 TUBING SELECTION AND DESIGN ......................................................................................................... 49

11.8.1 Pressure testing requirements .................................................................................................... 49 11.8.2 Design factors............................................................................................................................. 52 11.8.3 WellCat Stress calculation summary .......................................................................................... 52

11.9 CONTINGENCY COMPLETION DESIGN ................................................................................................... 53

12 COMPLETION MATERIAL SELECTION ........................................................................................... 54

13 COMPLETION FLUIDS .......................................................................................................................... 55

13.1 LOWER COMPLETION FLUID ................................................................................................................. 55 13.2 WELLBORE PREPARATIONS .................................................................................................................. 55 13.3 COMPLETION FLUIDS ........................................................................................................................... 56

14 X-MAS TREE AND WELL HEAD CONSIDERATIONS .................................................................... 57

14.1 WELL HEAD ......................................................................................................................................... 57 14.2 WELLHEAD GROWTH ........................................................................................................................... 57 14.3 CONDUCTOR AND CASING HANGERS .................................................................................................... 58 14.4 TUBING HANGER ................................................................................................................................. 58 14.5 X-MAS TREE ....................................................................................................................................... 59 14.6 WORKOVER SYSTEMS .......................................................................................................................... 62

15 WELL CLEAN-UP .................................................................................................................................... 64

15.1 WELL CLEAN-UP PHILOSOPHY .............................................................................................................. 64 15.2 EQUIPMENT DESCRIPTION .................................................................................................................... 64

16 WELL INTEGRITY .................................................................................................................................. 66

16.1 BARRIER ELEMENTS ............................................................................................................................ 66 16.2 WELL CONTROL ................................................................................................................................... 69 16.3 WELL MONITORING ............................................................................................................................. 69 16.4 ANNULUS MANAGEMENT .................................................................................................................... 69 16.5 ANNULAR FLUID EXPANSION (AFE) .................................................................................................... 70

17 WELL INTERVENTION ......................................................................................................................... 71

17.1 TYPES OF INTERVENTION ..................................................................................................................... 71 17.2 FAILURE FREQUENCY AND INTERVENTION PLAN ................................................................................. 71

18 RIG REQUIREMENTS AND LONG LEAD ITEMS ............................................................................ 73

18.1 RIG REQUIREMENTS ............................................................................................................................. 73


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18.2 IDENTIFICATION OF LONG LEAD ITEMS ................................................................................................ 74

19 PERMANENT PLUG AND ABANDONMENT STRATEGY .............................................................. 75

20 RISK MANAGEMENT AND REGISTER ............................................................................................. 78

21 TIME ESTIMATES................................................................................................................................... 79

21.1 DRILLING AND COMPLETION TIME MODEL .......................................................................................... 79 21.1.1 Drilling ....................................................................................................................................... 79 21.1.2 Completion ................................................................................................................................. 80

21.2 DRILLING AND COMPLETION TIME ESTIMATE ..................................................................................... 81 21.3 BATCH DRILLING ................................................................................................................................. 82 21.4 PREDRILLING 9 7/8 PILOT HOLE AT TEMPLATE LOCATION ................................................................ 83 21.5 PERMANENT ABANDONMENT .............................................................................................................. 83

22 RECOMMENDATIONS FOR FUTURE WORK .................................................................................. 84

23 ABBREVIATIONS .................................................................................................................................... 85

24 REFERENCES ........................................................................................................................................... 88

25 APPENDIX ................................................................................................................................................. 89

25.1 CASING DESIGN IN WELLCAT .............................................................................................................. 89 25.1.1 Input for Load Cases .................................................................................................................. 89 25.1.2 Design Limit Plots ...................................................................................................................... 91

25.2 TUBING DESIGN IN WELLCAT .............................................................................................................. 93 25.2.1 Input for Load Cases .................................................................................................................. 93 25.2.2 Design Limit Plots ...................................................................................................................... 95 25.2.3 Results from WellCat simulations............................................................................................... 96

25.3 TUBING MATERIAL SELECTION ............................................................................................................ 97 25.3.1 Material Classification ............................................................................................................... 97 25.3.2 13%Cr Martensitic Stainless Steel - Corrosion Resistant Alloy ................................................. 99 25.3.3 Super 13%Cr Martensitic Stainless Steel (5Ni2Mo) - Corrosion Resistant Alloy .................... 100


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1 INTRODUCTION

This report is a support document for the PL435 Zidane BOV Report. The objective of the Zidane DG2 Drilling and Completion Support documentation is to describe:

Features with regards to drilling, completion and intervention of the wells

Goals, accept criterias, challenges and strategies

Time estimates

Activities which will be performed and followed up during the detailed planning The document summarizes Zidane Drilling and Completion Activities and results leading up to the DG2/BOV milestone. Focus has been on describing one selected base case, but alternative cases are included for comparison, also due to uncertainty in the reservoir and geological model. Sections 2 to 6 are general information, design input from other disciplines and assumptions used for the well design work. Sections 7 to 21 are results of the Drilling and Completion work performed in this phase, and description of work required achieving the PDO milestone. More detailed descriptions of casing and tubing design, as well as material selection for the production tubing is placed in the Appendix of the document.


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2 GENERAL INFORMATION

2.1 Location and License Partners

PL435 containing the Zidane discovery is located on the edge of the Halten and Donna Terraces, in the Norwegian Sea. The license was awarded through the APA 2006 licensing round, on 16th February 2007 for an initial period of 5 years + 2 years extension. The current licensees are RWE Dea Norge AS (40% and Operator), Edison International Norway Branch (20%), OMV Norge AS (20%) and Maersk Oil Norway AS (20%). The license area is 243km2 within the blocks 6507/7 and 6507/8 and is situated between the Victoria discovery and Heidrun Field.

2.2 Project Organization

The Zidane project organization is given below (Figure 2-1). The Drilling and Completion Team is shown in Figure 2-2.

Figure 2-1: Zidane project organisation

(c) = Consultant

Figure 2-2: Zidane Drilling and Completion Team


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2.3 Governing and Guiding Documents

Well Design is done according to NORSOK D-010. Internal Production Drilling and Completion specific work processes and procedures will be developed as part of the DG3 phase.


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3 ZIDANE FIELD DEVELOPMENT

3.1 Field Development Concept

The base case is a 4 slot template with tie-in to a production facility. Two producers are planned for each segment. The template will be located in between the NNE-SSW striking structures of Zidane East and West. This enables good accessibility of the individual structures at optimized well length. Two wells are regarded sufficient to drain each segment. Zidane East and West are both high temperature reservoirs. Zidane West also falls into the high pressure category. Both wells showed high CO2 content which has to be accounted for in all aspects of the drilling and completion design.

3.2 Well Objectives

The objective of this program is to describe main concepts for drilling and completing subsea wells on Zidane East and Zidane West. The wells shall be drilled and completed with a design life of 20 years in a corrosive environment at HPHT conditions. Each well shall be designed to allow flowing up to 3 MSm/day. The design focuses on obtaining minimum HSE, risk, time and cost exposure, as well as compliance with RWE Deas HSE performance goals. Zidane is a limited subsea development. Therefore focus will be on the use of proven technology.

3.3 Drilling Summary

The well design is based on experience of the two exploration wells drilled on the Zidane East (6507/7-14S) and West (6507/7-15S) structure. Additionally experience from the Conoco well 6507/7-1 is used. Experience from HPHT offset fields was gathered and analysed, with focus on the nearby Kristin and Morvin field developments. For DG2 purposes, a standard well design for this type of wells was selected and feasibility has been verified by casing load analysis.

3.4 Completion Summary

Pending on the sand control study, open hole completions either with predrilled liner or standalone screens, have been defined as base cases for DG2. This also involves solutions for zonal isolation of water bearing sands from the producing reservoir if required. Alternative lower completion methods have been defined and evaluated in this report. The base case completion involves a middle completion consisting of a barrier packer and barrier plug. For the upper completion, 5 1/2 monobore style completion comprising of tubing hanger, TRSCSSV, gauge mandrel and production packer is planned.


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A horizontal XMT system is recommended for the Zidane Field Development. Stress calculations have been performed to verify the feasibility of the Zidane completion design. Time and cost estimation has been carried out both for open hole completions and cased and perforated completions.


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4 HSE

4.1 Introduction

The HSE objectives, principles and requirements for the Zidane project shall comply with the relevant authority laws and regulations, international and national conventions, with Operators internal governing documents and the governing standard NORSOK. Main focus areas in the overall Zidane Project are:

Zero personnel injuries No serious well control incidents No serious marine activities incidents No increased risk level on tie-back host Minimum environmental impact

The project will be organised with a dedicated HSE lead position. This function will be handled by the HSE/QA lead in the contract and will be in addition to the HSE discipline lead. Implementing good HSE solutions in the design is a multidiscipline responsibility. The project will have a proactive approach to ensure good HSE solutions. The HSE focus shall both focus on the installation period and the installed product.

4.2 Risk and Emergency Preparedness

The Zidane project will be prepared to respond to hazards, accidents and major security related events in order to prevent or reduce loss, damage, injuries or other consequences to people, the environment and material assets, production and operation, information, financial assets and reputation of both RWE Dea Norge and Partners. The Emergency Preparedness Plan will be prepared prior to start-up of production drilling. Oil spill contingency will mainly be safeguarded by NOFO (Norsk Oljevernforening For Operatrselskap). Cooperation agreements with other operators/installations in the region regarding access to equipment/vessels in an emergency situation will be made as required.

4.3 Environment and Discharges

The overall goal is to minimize emissions to air and discharge to sea, implement zero harmful discharges, evaluate Best Available Techniques and ensure high efficiency throughout the lifecycle of the field.

4.4 Chemical management

According to the Product Control Act ( 3a) any product with chemicals that may cause damage to health or the environment, shall be replaced with another with less impact to humans or the environment. The substitution duty is applicable for all products, unless technically unreasonable.


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5 GEOLOGICAL WELL DESIGN INPUT

Geological input is taken from the final well reports of the exploration wells 6507/7-14 S and 15 S (ref. /2/ and /3/).

5.1 Stratigraphy

Casing setting depths for the producers are based on the respective stratigraphic descriptions of the exploration wells.

5.1.1 Stratigraphy of Zidane East, 6507/7-14 S

Formation Tops MD RKB TVD RKB TVDSS TWT (ms) Thickness

m TVD

Nordland Gp/Seabed 369 369 344 465 1540.3

Naust Fm 369 369 344 465 1109.4

Base Quaternary 590 590 565 673 -

Top Kai Fm 1478.5 1478.4 1453.4 1451 430.9

Hordaland Gp 1910 1909.3 1884.3 1837 123.7

Top Brygge Fm 1910 1909.3 1884.3 1837 123.7

Rogaland Gp 2034.5 2033 2008 1953 111.8

Top Tare Fm 2034.5 2033 2008 1953 51.3

Top Tang Fm 2086.5 2084.3 2059.3 1998 60.5

Shetland Gp 2148 2144.8 2119.8 2053 796.5

Springar 2148 2144.8 2119.8 2053 315.9

Nise 2470.5 2460.7 2435.7 2335 480.6

Cromer Knoll Gp 2972 2941.3 2916.3 2699 770.8

Lysing Fm 2972 2941.3 2916.3 2699 59.7

Lange Fm 3036 3001.0 2976.0 2740 512.1

Lange sandstone 3568 3513.1 3488.1 3090 199.0

Viking Gp/Base Cretaceous Unc. (BCU)

3767 3712.1 3687.1 3210 451.6

Spekk Fm 3767 3712.1 3687.1 3210 23.0

Melke Fm 3790 3735.1 3710.1 3225 428.6

Fangst Gp 4219 4163.7 4138.7 3490 158.4

Garn Fm 4219 4163.7 4138.7 3490 86.8

Not Fm 4306 4250.5 4225.5 3531 6.9

Ile Fm 4313 4257.4 4232.4 3534 64.7

Bt Gp 4378 4322.1 4297.1 3562 > 155.4

Ror Fm 4378 4322.1 4297.1 3562 99.4

Tilje Fm 4478 4421.5 4396.5 3610 > 56

TD 4534.5 4477.5 4452.5 3637

Table 5-1: Stratigraphic welltops 6507/7-14 S


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5.1.2 Stratigraphy of Zidane West, 6507/7-15 S

Formation Tops MD RKB TVD RKB TVDSS TWT (ms)

Thickness m TVD

Nordland Gp undiff / Seabed 417 417 399 1489

Naust Fm 417 417 399 1063

Base Quaternary 600 600 582

Kai Fm 1481 1480 1462 426

Hordaland Gp 1906 1906 1888 96

Brygge 1906 1906 1888 96

Rogaland Gp 2002 2002 1984 120

Tare Fm 2002 2002 1984 57

Tang Fm 2059 2059 2041 63

Shetland Gp 2122 2122 2104 2042 832.9

Cromer Knoll Gp 2955 2954.9 2936.9 2751 895.1

Lysing Fm 2955 2954.9 2936.9 2751 74.5

Lange Fm 3029.5 3029.4 3011.4 2801 556

Top Lange Fm Sst 3586.5 3585.4 3567.4 3178 210.6

Base Lange Fm Sst 3796 3796.0 3778.0 3303

BCU/Viking Gp 3853.5 3850.0 3832.0 3341 13.8

Spekk Fm 3853.5 3850.0 3832.0 3341 12.3

Melke Fm 3866 3862.3 3844.3 3349 393.2

Fangst Gp 4266.5 4255.5 4237.5 3590 140.8

Garn Fm 4266.5 4255.5 4237.5 3590 82.2

Not Fm 4350 4337.7 4319.7 3626 5.9

Ile Fm 4356 4343.6 4325.6 3628 52.7

Bt Gp 4409.5 4396.3 4378.3 3652 >155.3

Ror Fm 4409.5 4396.3 4378.3 3652 88.2

Tilje Fm 4499 4484.5 4466.5 3694 >67.1

TD 4567 4551.6 4533.6 3728

Table 5-2: Stratigraphic welltops 6507/7-15 S


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5.2 Temperature

Reservoir temperature for Zidane East is estimated to 157,4C at 4207 mTVD MSL and for Zidane West to 160,2C at 4277 mTVD MSL (ref /1/). Seabed temperature is estimated to 4C.

5.3 Pore Pressure and Fracture Gradient

The calculations in this document are based on the discovery pore pressure and fracture gradient of the Zidane West exploration well. In DG3 pore pressure, shear failure gradient, fracture gradient and minimum horizontal stress will be analysed for each wellbore individually.


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5.3.1 Pore Pressure and Fracture Gradient of Zidane East, 6507-7/14 S

Formation pressure in the jurassic reservoir is based on pore pressure measurements.

Figure 5-1: Pore pressure, fracture and overburden gradients of 6507-7/14 S


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5.3.2 Pore Pressure and Fracture Gradient of Zidane West, 6507-7/15 S

Formation pressure in Lysing and Lange sand as well as in the jurassic reservoir is based on pore pressure measurements.

Figure 5-2: Pore pressure, fracture and overburden gradients of 6507-7/15 S


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6 SUBSEA TEMPLATE AND SITE SURVEY

This is a summary of the central template location used for DG2, a final template location will be selected based on seabed conditions, shallow gas, corals, well path optimisation, pipeline routing and anchor pattern for the drilling rig.

6.1 Template location

A geographically central template location was selected to drill two producers into each Zidane reservoir.

Structure Approximate water

depth [m MSL] UTM Northing [mN] UTM Easting [mE]

Zidane Central Location

380 7257607 413864

Table 6-1: UTM coordinates of central template location

Figure 6-1: Site survey map with reservoir outline showing proposed central template location


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6.2 Number of slots

A 4 slot template is seen as sufficient to drill the 4 required producers. However, the design of the subsea equipment also allows for a single slot tie-back. Experience from other subsea fields show an overall low probability of losing a template slot (ref /9/). The operations with the highest risk are the top hole sections (36 and 26). The following exemplary causes of losing a slot have been found:

Top hole drilling with excessive inclination Running conductor Cementing conductor Wash outs around the template Subsea XMT operation Casing got stuck in the wellhead during emergency hang-off

6.3 Shallow hazard review

A geohazard review by NGI (ref /5/) was made based on 2D site survey data and well information from the Zidane area. A probable sand layer near the base of the Quaternary /Top Tertiary layers contained gas in well 6707/7-15S and can be found at about 533 m to 605 m +/- 10 m below sea level at the Zidane Template site. It may also contain gas at this location. Gas cannot be excluded from a layer showing relatively high amplitudes at 1390 m to 1440 40 m below sea level. Boulders may occur in the Quaternary layers between 380 m to 598 m 10 m below sea level. Based on the findings NGI will suggest a new template location. Since shallow gas cannot be completely excluded, predrilling a pilot hole on the selected template location is planned. Two options are available:

Drilling a pilot hole with a geotechnical drilling vessel into Unit IV. Using a dynamically positioned drilling rig to drill a pilot hole down to the 20 setting

depth.


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Figure 6-2: Stratigraphical prognosis for Zidane central template location


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6.4 Cold water corals

A habitat investigation was conducted as part of the site survey for the exploration wells in the year 2009 (ref. /12/). Low densities of two Norwegian Red List coral species, the reef-building stony coral (Lophelia pertusa) and gorgonian bubble gum coral (Paragorgia arborea) were found across the survey area generally associated with coarser material on the flanks of bathymetric highs and ploughmarks. Based on the seabed feature map (Figure 6-3) only a small number of potential coral areas are marked near the proposed central template location (near CPT 08). A survey of potential corals within a 500m radius of the final template location and along the anchor chain corridors will be part of a site investigation.


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Figure 6-3: Seabed feature map showing potential and proven corals


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7 DIRECTIONAL DRILLING

An S-shape well path is selected as a base case for the 4 Zidane producers. Due to possible compartmentalization of the reservoir, horizontal well paths are also considered. An RKB elevation of 25 m is assumed for well design.

7.1 Well Path Design

Based on a central template location the selected well paths describes an S-shape, becoming near vertical above Lange reservoir to ensure a good cement job of the 9 7/8 casing. Further benefits of an S-shape well path are:

Better to intersect main structural faults near BCU in shale (see chapter 7.1.2) Better angle to drill hard stringers in Melke Formation Less meters to drill in Garn with less risk of differential sticking and reduced well

control exposure Less complex BHA in HPHT reservoir Overburden movement due to reservoir compaction in case of predrilled liner

completion becomes less critical The following points describe a general well path for the production wells (RKB at 25m):

Vertical until 650 m MD TVD RKB to drill through potential boulder zone Kick off to 6 inclination to separate 20 casings in direction of target Hold until 1350 m TVD RKB, until the 17 BHA is out of the 20 shoe Build to < 30(3/30 m build) to Top Hordaland group due to WBM Hold through reactive Hordaland and Rogaland group When BHA out of 13 3/8 build to final inclination < 50 (3/30 m build) Tangent section followed by drop to < 10 deg inclination above top Lange sandstone No build in Lysing and Lange sands Hold inclination to target and drill to TD

In comparison to slanted wells the increased inclination in the 12 1/4 section is seen main challenge, but the above named benefits of the S-shape solution outweigh this disadvantage.


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Figure 7-1: Examplary well path of Producer 1 in Zidane West


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7.1.1 Wellbore stability

Experience provided by Subsurface AS (ref /8/ and /9/) shows that in the 17 section angles up to 30 are feasible with water based mud. Higher angles have seen wellbore stability problems. In the 12 1/4 section no major wellbore stability problems were encountered in comparable fields like Kristin, Morvin, Kvitebjrn, Ula or Gyda. Kristin and Morvin drilled 12 1/4 section with up to 65 inclination, whereas Kvitebjrn achieved inclinations of up to 56. Essential are good hydraulics and hole cleaning. A wellbore stability study is planned as part of the DG3 scope.

7.1.2 Structural faults below BCU

Well paths from a central template location will cross the main structural faults of the Jurassic reservoirs. This is due to optimal reservoir target placement to minimize the risk of water break through and optimize production. The faults are assumed to be sealing and are not expected to create major drilling problems. During reservoir depletion the faults in the overburden should follow the overall compaction (ref /11/). No major shear forces are expected. Nevertheless, placing the 9 7/8 production casing across the fault is seen as essential, to prevent damage to the production tubing in case of occurring stresses along the fault planes.

7.1.3 Top Garn Pick

It is planned to set the 9 7/8 casing as close as safely possible above Garn reservoir. In order not to risk drilling with the 12 bit into the reservoir a minimum of two geological indicators will be used to determine the setting depth:

Drilling Top Melke will give a good indication of seismic accuracy and section TD can be a certain amount of meters into this formation.

Resistivity log markers in Melke Formation will be further evaluated, as they show similar patterns between Zidane West and East exploration wells. In case these markers come in shallower the section TD can be set earlier.

7.1.4 Horizontal well paths

Horizontal wells are challenging to drill under HPHT conditions. The following main challenges were encountered in highly deviated HPHT wells (ref /9/ and /15/):

Drilling highly abrasive Garn formation is challenging for bits. PDCs tend to wear out after a short period. Turbine drilling with impregnated bits achieves only a low ROP.

The horizontal wellbore is exposed to a high temperature environment. This is damaging to LWD tools. The failure rate is seen as high.


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The long horizontal reservoir section increases the well control exposure. Round trips are time consuming due to HPHT procedures and LWD staging

procedures. The central template increases the complexity, as it is not recommended to drill from the central Graben across the main faults directly into the reservoir. Compaction of the sandstone reservoir versus shale could fatally damage the casing and tubing. Therefore high focus has to be on well placement.

Figure 7-2: Example of horizontal well paths for Zidane East and West

7.2 Directional Drilling and Surveying

For all wells, steering is planned from below the 30" conductor shoe. Depending on the complexity of the planned well paths, PDM and/or 3-D RSS will be selected. Thorough equipment planning / optimization will be performed as part of DG3 preparations. In the preliminary stages of well path planning a maximum of 3/30 m DLS and 50 sail angle have been selected. However, optimum well paths will be planned in more detail during the DG3 phase.


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Maximum survey spacing is 100 meters, as per NPD regulations.

7.3 Drill String Design

The drill string will be designed with respect to optimized hydraulics and torque & drag. Hydraulics and Torque & Drag simulations will be performed as part of optimized well path, casing and drill string design, and mud program in DG3.

7.4 Relief Wells

The exact location will be selected and planned such that all wells can be reached from two relief surface locations during DG3. The relief well locations will be chosen based on 4 main considerations:

Negligible potential for shallow gas

No observed seabed obstructions

Allowance for an anchor pattern

Prevailing wind and current directions

7.5 Challenges and Risks

Main risks related to directional drilling are:

Achieving required DLS in 17 1/2" section (large bore, reactive clays)

Achieving required DLS in 12-1/4" section for landing on target correctly

Well separation in 36" and 26" sections


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8 CASING DESIGN

Focus is on a robust casing design to fulfil a design life of 20 years. As the standard casing design of the exploration wells was close to the required minimum design factors, stronger casings have to be selected to account for corrosion and wear.

8.1 Casing Shoe Depths

Producer 1 in Zidane West (ZWGPR1):

Table 8-1: Casing shoe depths

Casing Size

Hole Size

Planned Shoe Depth M TVD RKB

Tolerance / Setting Criteria

Setting Criteria

30 or 36 36/42 502 12 m Shoe in a competent shale.

Structural load carrying capacity for BOP / casing strings and XMT. Seal off any potential boulders and other troublesome formations. Enable circulation of the anticipated mud density /ECD for the next hole section.

20 26 1320 Not below the depth of the Pilot Hole. To be set in a normally pressured shale.

To seal off potential zones with low fracture gradient and allow further drilling and maintain a minimum drilling margin of 0.06 s.g. between the expected fracture pressure and maximum anticipated ECD / mud density in the next section without exceeding the estimated LOT pressure at shoe.

13 3/8 (x 14)

17 2162 To be set minimum 50 m into the Shetland formation.

Seal off the initial pore pressure build up and ensure a minimum fracture pressure at the shoe depth to enable further drilling. To maintain a minimum drilling margin of 0.06 s.g. between the expected fracture pressure and maximum anticipated ECD / mud density and to be able to circulate out a 8 m

3 gas kick from reservoir formation

without exceeding estimated formation LOT pressure at shoe.

10 3/4 x 9 7/8

12

4210 Ca. 30 m above Top Garn in a competent formation.

Seal off the Lange and Lysing sandstones. Maintain a minimum drilling margin of 0.06 s.g. between the expected fracture pressure and maximum anticipated ECD / mud density and to be able to circulate out an 8 m

3 gas kick from reservoir formation

without exceeding estimated formation LOT pressure at shoe. Important to case-off main Zidane faults to prevent damage to production tubing.

Completion 8 ~4315 TD dependent on completion method.


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8.2 Casing Test Pressures

Producer 1 in Zidane West (ZWGPR1):

Table 8-2: Zidane West Producer 1 test pressures

8.3 Casing String Selection

Casing String Properties Comments

30 or 36 Conductor

Weight, grade and OD dependent on wellhead and conductor analysis.

20 Surface Casing

133# X-56 E-60/MT Based on exploration wells

13 3/8 x 14

72# P110 Vam Top 93# P110 Vam Top

Final casing string dependent on wear analysis and wellhead configuration

9 7/8 x 10 3/4

66,4# P110 Vam Top 65,7# Q125 Vam Top

Final casing string dependent on wear analysis (horizontal wells) and corrosion study.

Table 8-3: Selected casing strings

Final weight, grade and material will be evaluated in detail as part of the DG3 process.

8.4 Contingency Casing Program

A 16 Liner can be used in case of shallow gas or wellbore problems. In case the required setting depth of the 9 7/8x 10 3/4 casing is not achieved, a 7 contingency liner with a 4 completion string can be used (see also chapter 11.9). A detailed contingency program is planned as part of the DG3 process.

Casing Size Surface Test

Pressure Fluid Criterion

30 or 36 N/A N/A No pressure test of conductor

20 150 bar Seawater Frac at shoe with gas above

13 3/8 (x 14)

280 bar 1.58 s.g. WBM

Frac at shoe with gas above

10 x 9 7/8

550 bar 682 bar

1,69 s.g. OBM 1,08 s.g. Brine

Pressure test of 550 bar is required to drill the 8 section Casing test pressure


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8.5 Drilling Well Schematic

Figure 8-1: ZWGPR1 Drilling Well Schematic

RKB: 25 m vertical

36"

or 42"

Seabed 424m

Kickoff of 650 mRKB

30" or 36"Conductor @ 502 m TVD/MD in case of boulders

1 /30 m

max incl. 6

26"

20" Surface Csg. @ 1320m TVD / 1323 m MD

Kickoff below 20" shoe

3 /30 m

TOC @ 1898 m TVD / 1934 m MD 17 1/2" max incl.


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8.6 Blowout & Kill Analysis

Add wellflow AS performed a blowout and kill simulation (ref. /6/) based on the Zidane West discovery results. The well drilled Lange reservoir in an optimal position to prove maximum hydrocarbon volumes, therefore the discovery input parameters are seen as representative to simulate a worst case scenario. The study confirms, that open hole blow-outs from Lange and Garn reservoirs can be killed with a single relief well. In case the production wells cross Lange Sand at a potentially bigger gas accumulation than the one encountered in Zidane West, the blowout risk will be reevaluated or the well paths adjusted.


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8.7 Challenges & Risks

The major identified risks and challenges related to casing/well design are:

Long and heavy 9 7/8 x 10 3/4 casing which has to be run as a single string (tie-back solution not desired due to high production temperature and the resulting expansion and/or contraction of the casing.)

Running the 9 7/8 x 10 3/4 casing across the main structural faults of the Zidane reservoir and set it as close as possible above the Garn formation.

Material selection for production casing.


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9 DRILLING FLUIDS

Mud weights in the table below reflect approximate mud weights for a Zidane West producer. In Zidane East lower mud weights will be used in the 12 and 8 section. Hydraulics calculations are planned as part of DG3 process. Mud weights are calculated for S-shape wells.

Section

Mud weight Mud type Comment

36 Sea water & pills Sea water

1,50 s.g. displacement mud

26 Sea water & pills Sea water

1,25 s.g. displacement mud

17 1.55 s.g. Water based or oil based mud

Mud Weight and type dependent on well inclination, direction and results from well bore stability study.

12 1.69 s.g. Oil based mud Mud Weight and type dependent on well inclination, direction and results from well bore stability study.

8 1.83 s.g. Oil based mud Mud type dependent on formation damage and fluid selection study. For details in completion fluids see chapter 13.1

Table 9-1: Mud selection (mud weights for Zidane West)


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10 CEMENTING PROGRAM

Casing Size

Cement type Lead/tail

slurry density

Top of Cement Comments

30 Standard G-cement 1,56 s.g./ 1,95 s.g.

Sea bed 200 % OH Excess.

20 Slurry type to be evaluated

1,60 s.g./ 1,92 s.g.

Sea bed 100 % OH Excess. Potential low weight cement to reduce hydrostatic head during cement job (e.g. foam cement).

13 5/8 Standard G-cement 1,92 s.g. Minimum 200 m above shoe

30 % OH Excess.

9 7/8 x 10 3/4

Gas tight cement, slurry type to be evaluated

1,92 s.g. Minimum 200m over Lange sand

30 % OH Excess on caliper volume, cementing Lysing Sand will be evaluated in DG3.

Table 10-1: Cement program


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11 GENERAL COMPLETION DESIGN

11.1 Introduction

The main factors affecting the completion design in HPHT wells are the extreme pressures combined with very high temperature and corrosive environment. Some of the main risks associated with HPHT well completions are:

Well integrity High stress environment in combination with high operating temperatures Formation damage Fluid selection Equipment reliability

The strategy for the Zidane well completion design will be focusing on:

1. Simple, robust, and proven subsea completion design 2. Completion equipment, fluid selection, experience transfer and best practices from

Norwegian HPHT fields.

11.2 Completion Objectives

The primary objective of the Zidane completion design is to design wells with a design life of 20 years in a corrosive environment at HPHT conditions. Each well shall be capable of flowing up to 3 million Sm3/day, and with the ability to maintain the desired Zidane plateau production. This requires wells well with high PI and low skin. The completion design shall offer sand-free and water-free production and shall be optimized to use the most gentle lower sandface completion with respect to formation damage. Another primary level objective in the completion design is selecting of compatible fluids which gives minimum negative effect on productivity. Obtaining a robust completion design is crucial with regards to well integrity, CAPEX and OPEX. The completion design will be based on well-known qualified components from Norwegian HPHT wells.


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11.3 General Well Design

A general completion drawing is shown in Figure 11-1 below. The base case for the lower completion design on Zidane is 5 predrilled liner. However, the possibility of using standalone screens (SAS) or cased and perforated liner is optional dependant on update of the reservoir model and potential for horizontal wells in case of reservoir compartments. The base case for the middle completion (barrier assembly) is a production packer type in combination with a temporary downhole barrier plug. Upper completion base case is 5 production tubing, downhole pressure and temperature gauge, retrievable production packer, 5 downhole safety valve and 5 tubing hanger. The table below summarizes the general completion design: Field/Structure Zidane East/ Zidane West

Well trajectory in reservoir Vertical Multilateral NO Smart well completion NO Downhole PT gauge YES Downhole chemical injection NO Lower Sandface completion Predrilled liner Zonal isolation OH partly plugged back with cement (if

required) Swell packers (if required)

Tubing 5 1/2 26 ppf Super 13%Cr-110 DHSV 5 DHSV with insert valve feature Production packer 9 x 5 production packer Middle completion (barrier) packer 9 x 5 packer Tubing hanger 18 x 5 XMT Horizontal XMT

Table 11-1: Zidane Completion Design


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Figure 11-1: General Zidane Base Case Completion Design (RKB = 25 m)

Lower Completion

Barrier assembly

(Middle completion)

30" Casing Shoe

502 m MD/ 502 m TVD

Wellhead Datum 424 m MD

PMV

MIVPT

Flow-line connector

WOV

XOV

AMVAWVPT

PWV

All depths are preliminaryDrawing is not in scale

5 1/2" 26# S13Cr110 Production Tubing

Production

Methanol

PCV

BMV

VXT

PBT

Annulus bleed

20" Casing Shoe

1323 m MD/ 1320 m TVD

14" x 13 3/8" Casing Shoe

2232 m MD/ 2164 m TVD

10 x 9 7/8" Casing Shoe

4835 m MD/ 4210 m TVD

5 " Gauge Carrier

5 " Predrilled Pup Joint

5 " x 9 7/8" Production Packer

5 " x 9 7/8" Barrier Packer w/ 20 ft PBR

5 " Nipple Profile

5 " Predrilled Pup Joint

5 " PBR Stinger w/o seals

5 " PBR Stinger w/o seals

5 1/2" x 9 7/8" Liner Hanger w/ 20 ft PBR

5 1/2" Predrilled liner

5 DHSV

460 m MD/460 m TVD

Reamer Shoe

TD 5042 m MD/ 4415 m TVD

Top Lange Fm 4209 m MD/ 3590 m TVD

Top Lysing Fm 3407 m MD/ 2961 m TVD

Top Garn Reservoir 4870 m MD/ 4245 m TVD

DHSV setting depth > 50 m from base seabed

10 casing to below DHSV setting depth

Shallowest Production packer setting depth = 3500 m TVD Requirement for setting depth: Ppore = Pfrac

Completion Design Parameters

Rupture discs in 20" casing to accomodate AFE

Rupture discs in 13 3/8" casing to accomodate AFE. B-annulus displaced to CaCl2/CaBr2 clear brine

TOC > 50 m above production packer setting depth AND TOC > 200 m above reservoir AND

TOC > Top Lange Formation Preferably TOC > 100 m above Lange Fm to ease future P&A

Include space above nipple for contingency punching

Gas Production Well Z2GPR1

Field: Zidane

Status: DG2 Base Case

Prep. by: Bjrn Olav Dahle

Estimated LOT: 2.15 sg

Estimated LOT: 1.82 sg

LOT - min 1,69 sg

Max Well Design Pressure: 655 bar

A-annulus fluid: MEG/Freswater mix ca 1.08sg added O2 scavenger,biocide and Na2CO3

Production tubing: 5 26# Vam Top HC S13%Cr

Predrilled liner: 5 1/2" 26# Vam Top HC S13%Cr

Lower Completion fluid: 1.83 sg LSOBM

Middle- and Upper Completion fluid: 1.82 sg Cs/K COOH

Upper Completion

Date: 14.08.2012


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11.4 Lower (Sandface) Completion

Lower completion is a critical interface between the productive formation and the wellbore. An effective completion must maintain the mechanical integrity of the borehole without creating significant restrictions on the flow capacity of the well. Some of the general considerations for the lower completion scoping are:

Limit formation damage Simple and HPHT field proven solution Avoid exposure of reservoir during long term temporary P&A No corrosive fluid left in hole (>1 month) Allow for future well intervention operations Life of the well design

The cores from Zidanes Garn formation appear to be well consolidated. Rock mechanical testing is currently in progress. Preliminary results do not allow final conclusion on sanding but do not indicate a strong sanding tendency, either. However, the samples might not be fully representative for the entire reservoir, i.e. for the Garn high permeability zone.

The base case lower completion sandface solution for Zidane is pre-drilled liner (PDL). The assumptions for this choosing this solution are:

No need for sand control

Shallow placement of well in Garn reservoir

No or very limited water production potential

The base case PDL can be combined with swell packers to accommodate shut off unstable silt or shale intervals. The PDL represents the simplest and fastest lower completion installation alternative. With current technology for HPHT wells, a subsea 5 TH/XMT will limit liner size to 5 , in order to allow for access to the well for prospective interventions (plugs, straddles, etc). Alternative lower completion configurations will be evaluated in the DG3 phase based updated data for reservoir model (compartments), sand production predications, water production potential and rock mechanical study.

In the table below the feasibility of several lower completion alternatives for the Zidane are evaluated based on well trajectory (reservoir model), requirement for zonal isolation and sand control, respectively.


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Lower completion selection

Predrilled Liner

Stand Alone

Screens

Cased and Perforated

Liner

Cased & WL Perforated

liner

Vertical well (No or limited compartments) NO zonal isolation

No sand control

Yes Yes Possible Possible

Vertical well (No or limited compartments) WITH zonal isolation

No sand control


Vertical well (No or limited compartments) NO zonal isolation

Sand control

No Yes No No

Vertical well (No or limited compartments) WITH zonal isolation

Sand control

No Yes No No

Horizontal well WITHOUT zonal isolation (reservoir compartments)

No sand control


Horizontal well WITH zonal isolation (reservoir compartments)

Sand control

No Yes Yes No

Table 11-2: Simplified Lower Completion selection for Zidane

The cells marked Possible suggests that the lower completion alternative is technically feasible, but is a poor alternative with respect to HSE, time and cost. Cells marked in red are not regarded as lower completion options for Zidane. Therefore it should be noted, although a cased and perforated solution is feasible for a horizontal producer, perforation and clean-up will be challenging. The combination of high density completion fluid, long horizontal wellbores and high permeability zones will lead to the situation, that the heel section will be the main contributor in during clean-up and as a worst case the toe will not be cleaned-up at all. A permanent skin can be induced to the toe due to long exposure of completion fluid and poor clean-up rates. If possible, an open hole completion should be used. The following sand control techniques will not be evaluated:

Open hole gravel packs (OHGP) are not considered feasible for Zidane based on the

complexity of the gravel pack operations and the fact that OHGPs are not field

proven for HPHT conditions.

Expandable sand screen (ESS) completions for open hole are not recommended for

the Zidane development. The main reason is that the current ESS technology does

not meet the CRA metallurgy requirements for Zidane.

Frac pack (FP) sand control is not considered as an alternative on Zidane due the

well consolidated Zidane reservoir with high permeable streaks in the Garn

formation. FP would not give increased productivity and would imply undesired risks

and costs compared to the much simpler and cheaper installation of standalone

screens (SAS) or PDL.


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11.4.1 Lower Completion Scoping

A simplified method evaluation exercise has been performed in order to document the advantages and disadvantages with the different lower completion options. For determination of the best suited lower completion, for Zidane, the following value drivers have been defined and weighted according to criticality 1(low) to 10 (high):

Table 11-3: Value Drivers for Method Evaluation

Main Issue Keywords Value Driver

HSE and operational performance

Noise, chemicals, weather induced

movements, rig-up complexity, heavy lifts,

manual handling, less pressure build-up, less

logistics, dropped objects, pressure testing,

well control issues, damage to reputation,

APBU, WH growth, barriers, interventions.

10

Production and recovery

Low DP, expose all sands, avoid damage from

fluids, exposure time, ECD, lost circulation,

Sweep all reservoirs, delay WBT, early

production start-up, short term NPV

optimization, allow data gathering, allow MPD

for in-fill drilling, allow optimal drilling

sequence, reservoir stimulation.

8

Schedule

100% Well Availability at start-up date,

reduced operations time, reduced operations

risk and complexity, reduced weather

dependency, proven operations, low risk of

"wrecks".

5

Capex

Quick operations, few sub-ops, minimize risk /

NPT / WoW. Allow batch ops. Low upfront

investment. Efficient rigs/ well trained and

experienced crews. Low cost.

8

Regularity/ Opex

Ensure sand control, avoid erosion and

equipment failure, barrier problems, APBU

problems, debris problems, temp problems,

deviations. Minimize time spent on problem

and mobilization time. Avoid water and scale

problems. Allow Well intervention when

required to repair and analyze problems to

ensure uptime. Reduce interventions from

WBT, equipment failures, sand, debris, scale,

collapse, formation damage, damage to

equipment. Allow for interventions (access, ID,

doglegs). "Dry" or "wet" trees. Water depth,

use of LWI.

5

HPHT Concept Experience

Organization well acquainted to the concept,

procedures available, risks well known and

defined, no or little new steering

documentation need to be developed, little or

limited training of offshore personnel required.

8

Total 44


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With reference to Table 11-3, an evaluation has been made for following lower completion options:

Predrilled Liner

Stand Alone Screens

Cased and Perforated Liner

Cased & WL Perforated liner

Each of these completion options are regarded as Feasible for its purpose, i.e. assumed green or yellow as reference to Table 11-3. Each completion option is considered based on the different issues and given a score from 1-10. The sum of the individual (Score x Value Driver) enables a quantitative comparison of the different completion options.

ISSUE Value Driver

Score CONCEPT: Predrilled Liner (PDL)


10/44 9 Simple and quick installation and handling of equipment. Low well control potential.


8/44 9

No negative effect on skin during installation. No plugging issues during start-up and production. Zonal isolation and plugging can be accomplished by use of swell packers. No sand control, sand control predictions needs to be definitive before

choosing this solution.

Schedule 5/44 9 Simple and low risk operation means well can be finished and started up according to schedule.

Capex 8/44 9 Short and simple installation.

Regularity/ Opex 5/44 6

If sand predictions show no sand production potential, regularity is expected to be high. Interventions/plug setting is feasible if swell packers are installed. Solution does not introduce negative fluid interfaces or restrictions which may prevent complete clean-up or prevent interventions through entire wellbore.


8/44 9 Good experience from Kristin and Morvin fields.

Total Weighted Average Score

(1-10) 8,66


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ISSUE Value Driver

Score CONCEPT: Cased and Perforated

Liner (C&PL)


10/44 3 Many sub operations. Complex cementation operation. Handling of TCP explosives. High probability of failure during cementation or perforation.


8/44 3

Negative effects on PI are expected due to overbalanced perforation. Poor production performance on C&PL wells on Kvitebjrn and Kristin compared to open hole completions. Sand control predictions indicates NO sand production potential OR dictates use of oriented perforation guns (horizontal wells) Zonal control or water shut-off methods can be integrated. Can be used in comparted reservoir drilled with horizontal wells.

Schedule 5/44 3 High risk of delays due to slow operation.

Capex 8/44 3 Expensive and slow solution. Several additional sub operations: cementation, perforation, clean-up run. logging of cement quality.

Regularity/ Opex 5/44 8 IF good cementation is verified: Regularity can be good for a horizontal well. Interventions can be effective.


8/44 5

Poor experience from Kvitebjrn and Kristin fields. Very demanding cement operation. Low probability of good cement jobs. High risk for TCP misfire/stop fire based on Kristin experiences.

Total Weighted Average Score (1-10)

3,93

ISSUE Value Driver

Score CONCEPT: Standalone Screens

(SAS)


10/44 8 Simple and quick installation and handling of equipment. Low well control potential during installation. Plugged screen during clean-up might induce well control challenges.


8/44 7

Fluid compatibility is crucial for successful clean-up and to avoid plugging of screens. Zonal isolation and plugging can be accomplished by use of swell packers. No sand control, sand control predictions needs to be definitive before choosing this solution. Risks for hot-spotting or high velocities eroding screens.

Schedule 5/44 8 Simple and low risk operation means well can be finished and started up according to schedule.

Capex 8/44 8 Short and simple installation.


Plugging of screens might be an issue. Fluid compatibility analysis and sieve analysis/sand screen scoping needs to be carefully evaluated. Interventions/plug setting is feasible if swell packers are installed.


8/44 9 Good experience from Kvitebjrn, Kristin and Morvin fields.


8,00


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ISSUE Value Driver

Score

CONCEPT: Cased and WL Perforated Liner (in

underbalance)


10/44 3

Many sub operations. Complex cementation operation. Handling of TCP explosives. High probability of failure during cementation of liner. Several WL runs in live well. Non-perforated well during installation of top completion. If horizontal length becomes long in combination with long required perforation interval, C&P liner might be a better option.


8/44 7

Underbalance perforation is positive wrt. productivity. To use this method: Sand control predictions indicate NO sand production potential OR dictate use of oriented perforation guns (if horizontal wells are drilled). Zonal control or water shut-off can be integrated. Can be used in comparted reservoir drilled with horizontal wells but will require use of WL tractor.

Schedule 5/44 4 High risk of delays due to slow operation.

Capex 8/44 5 Expensive and slow solution. Several additional sub operations: cementation, logging of cement quality, live well perforations.


IF good cementation is verified: Regularity can be good for a

horizontal well. Interventions can be effective. No need for running barrier assembly in middle completion as well is un-perforated during top completion.


8/44 7 Very demanding cement operation. Low probability of good cement jobs. WL perforation experiences from Kvitebjrn are

mainly good.


5,50

Table 11-4: Quantitative method evaluation for Zidane Lower Completions

Based on the analysis, the predrilled liner option gives the highest score = 8.66 out of 10, and is recommended based on current design criterias. Time and estimates for the different completion options is described in chapter 21.

11.4.2 Zonal Isolation - Cement plug-back

In case Not or Ile formations are penetrated a method for isolating is to cement back the well to bottom Garn formation (assumed vertical well). This method will represent the most reliable zonal isolation method. The cement will have to be verified by mechanical tagging.

11.4.3 Swell packers

Open hole swelling packers can be a part of open hole lower completion to provide zonal isolation in conjunction with predrilled liner or open hole screens. The swelling packer is an annular packer that expands and seals by elastomers swelling when in contact with hydrocarbons (diffusion process). Swelling packers has successfully been installed on Morvin, Kristin and Kvitebjrn HPHT wells. However, the challenge for Zidane will be the low content of heavy hydrocarbon components (C5+) which normally induces the elastomeric swelling process. Running swell packers in LSOBM drill-in fluid can be considered to ensure proper rubber swelling, provided that the diffusion barrier ensures no premature swelling during running in hole.


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The expected maximum differential pressure across a swell packer potentially installed in Zidane wells, is about 600 bar. The swelling time shall be engineered to ensure that the system can successfully run to depth. A swell test against the selected OBM for Zidane will be performed to design the rubber compound and delay system (diffusion barrier).

11.5 Middle Completion Design (Barrier Assembly)

The barrier assembly will isolate the well from the reservoir section when running upper completion and displacing the well from completion fluid to underbalanced packer fluid. The barrier assembly simplifies the upper completion operations and protects the open reservoir below the barrier assembly from excessive pressure. The middle completion is independent of well trajectory as long as angle at barrier packer depth is less than 65o. A middle completion is required for all completion alternatives which involve a lower completion with open reservoir section. The only exception is a cemented and un-perforated liner. In this case, the cemented liner has full pressure integrity during upper completion and is wireline perforated through the workover stack after the upper completion has been installed. Two different barrier assembly designs are available:

1. Barrier assembly run as Middle Completion. A packer and tailpipe with pre-installed plug installed and tested on a separate run.

2. Liner hanger packer and plug as barrier packer. A plug is pre-installed below the liner hanger and is run integrated with the liner. The liner hanger packer together with the plug constitutes the downhole barrier assembly.

The base case for Zidane is barrier assembly installed on a separate run. Obviously, it is more time consuming compared to adopting it into the liner hanger system. However, designing and upgrading the liner hanger from just handling hanger loads into taking both upward loads at plugged/underbalanced conditions combined with gas tight requirements (ISO 14310 V0), has proved to be difficult. On four Morvin wells, the installation of ZXP Ultra liner hanger packer run as barrier assembly failed, and conventional barrier assemblies had to be installed (ref /14/). Both the packer and pre-installed tailpipe plug needs to meet ISO 14310 V0 certification. Further, the barrier assembly will have to handle large bi-directional loads during pressure testing from above and displacement to light fluid. The barrier packer can either be a hydraulic set production packer style or a mechanical set packer type, both drill pipe conveyed. There are several varieties of barrier plugs used in HPHT wells. The selection of barrier plug is crucial, as failure of removing the plug can cause large operational downtime and heavy and complicated interventions. Successful removal of barrier plugs is directly related to the cleanliness of the well, as fluid deposits or settlement historically in HPHT wells can result in large challenges of opening or removing barrier plugs.


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The following barrier plugs will be considered for Zidane:

Barrier plug Feasible Comment

Nipple plug or bridge plug YES Simple and field proven. Need WL to remove plug.

Glass plug YES New to HPHT wells. Need to monitor success rate upcoming HPHT installations. Primary opening mechanism is pressure cycling.

Drop Sub Assembly (DSA) Possible Limited to vertical wells. Simple design. Need WL to activate DSA for dropping

FIV/CIV (Formation Isolation Valve/ Completion Isolation Valve)

NO Primary opening mechanism is pressure cycling. Poor record from Kristin. Complicated contingency opening. Large restriction in completion.

Table 11-5: Zidane barrier plug selection

Base case design for Zidane is to integrate nipple plug below the barrier packer Contingency, if plug cannot be pulled out, is to punch the tubing above the plug, allowing annular flow on the outside of the plug. The mule shoe on the tail of the barrier assembly is stung into the lower completion PBR. A perforated pup joint is incorporated in order to avoid trapped annulus between barrier packer and liner hanger packer. Centralizers are recommended on the tubing between the barrier packer and barrier plug in order to avoid potential buckling when displacing well above barrier assembly to light-weight completion fluid. The PBR on top of the barrier packer should be minimum 20 ft in order to allow for safe- sting in of upper completion. Using a long PBR will cover minor tally errors due to length measurement inaccuracies and thermal movement of production tailpipe. This will eventually secure easy access through the completion during interventions.

11.6 Upper completion Design

11.6.1 Introduction

For upper completion and sizing of production tubing, both 7 and a 5 tubing sizes are under evaluation. The main construction issues related to upper completion design are:

Open hole zone isolation (cement, swell packers, etc.) Downhole Chemical injection Casing design wear tolerances Cementing of production casing vs. well integrity Production packer type Well intervention interface Well control during installation Equipment reliability and HPHT run record Formation compaction / well deformations


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In addition to technical well construction issues above, simulations are being analysed by subsurface to determine the production profiles for the two relevant tubing sizes. The upper completion design is independent of well trajectory. Maximum inclination at production packer depth is 60.

11.6.2 Production tubing

The tubing design is conducted mainly based on:

Suitable grade and material selection to handle downhole HPHT conditions Tubing size to optimize gas production Stress analysis during life of well

The proposed tubing configuration and connection for Zidane is:

Tubing Connection OD (in) Weight (lb/ft) Grade Name Grade

5.5 26 Super 13%Cr-110 VAM TOP HC Super 13%Cr-110

VAM TOP HC (High Compression) is a metal-to-metal connection which offers gas tight sealing under severe combined loads. This connection is recommended based on good experience form Norwegian HPHT wells. Further reference is made to chapter 11.8.

11.6.3 Production packer

The following design criterias are important for correct selection of production packer for Zidane:

Performance envelope beyond production tubing Hydraulic set to create an initial stretch in the tubing, reducing effects from

compressive production loads and buckling. ISO 14310 V0 qualified Qualified for use in un-cemented casing Robust with regards to premature setting while running in hole Retrievable

According to HPHT requirements, the production casing cement quality needs to be verified prior to running top completion. The packer should, as far as possible, be set in a cemented interval at an impermeable formation. Further, a casing wear log (multifinger calliper) must be run prior to completion in order to verify that the casing integrity is acceptable due to potential casing wear caused by reservoir drilling. The minimum setting depth of the production packer is given by gas pressure minimum formation horizontal stress at packer setting depth. For Zidane West, this gives an approximate minimum production packer setting depth equal to 3500 m TVD. A hydraulic set production packer is used as base case for Zidane. The production packer is hydraulically set against a plug and prong or bridge plug below the packer. No expansion joint will be integrated above the production packer to avoid additional leak paths above the primary barrier.


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The Kristin completions suffered three premature settings of the permanent production packer during running in hole, mainly due to small clearances combined with dirty wells (ref /14/). Removal of permanent packers involves cutting tubing, milling packer and several clean-out runs. A new HPHT retrievable packer has been recently developed and successfully used in the Morvin completions. This packer incorporates a cut-to-release sub below the packer. Hence, the packer can be released by WL conveyed cutting. Further, this packer has a smaller diameter and offers a higher stress performance envelope.

11.6.4 Flow control equipment

A no-go nipple profile will be installed just below the production packer. The blanking plug that seats on it is used to hold the pressure from above during the setting of production packer. It can also be used to pressurize the tubing for leak detection and production string integrity. A self-orienting muleshoe without seals will be used to integrate upper and middle completion. A positive sting-in into the middle completion PBR ensures easy wireline access during interventions. A perforated pup joint is included above the muleshoe to allow a circulating path for displacing the well to completion fluid.

11.6.5 Downhole chemical injection (DCI)

Salt, scale and asphaltene precipitations are not expected on Zidane. Hence, downhole treatment is not part of the base case design. There are no field proven HPHT DCI downhole systems qualified in the market today.

11.6.6 Downhole pressure and temperature monitoring

The Zidane completions will all be planned with electrical downhole gauges for pressure and temperature monitoring. No control line penetration is recommended through the production packer as this will result in a weaker non-HPHT style production packer. Hence, the gauges will be placed as close as possible above the production packer. The reliability of downhole gauges under HPHT conditions is generally poor as gauges tend to fail after relatively short time after production. Based on recent field record, roughly 50% of the downhole gauges can be expected to fail two years after installation. Both electrical and fibre optic gauges have been used on the continental shelf, with similar behaviour. Zidane will be limited to electrical gauges due to the subsea XMT interface.

11.6.7 Down hole safety valve (DHSV)

A single, 5 tubing retrievable surface controlled subsea safety valve is planned for Zidane. A 10 k design would cover the Zidane pressure requirements. A single valve DHSV recommended over a dual valve as keeping completion design as simple as possible and minimizing potential leak paths. The most probable cause of a DHSV failure is hydrate or scaling precipitation.


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Using two independent DHSVs does not result in spacing out dual valve in different scaling environments. Maximum fail safe DHSV setting depth is limited to approximately 600 mTVD to avoid premature opening of DHSV in case of a control line leak. Safety valves have shown good reliability from Norwegian HPHT fields Morvin, Kristin, Kvitebjrn and Huldra fields, all installed with single safety valves. The following input is recommended for correct selection of DHSV for Zidane:

Performance envelope higher than the production tubing Single control line Non-equalising WRSCSSV insert valve contingency Setting depth minimum 50 m below seabed Water based control line fluid Control line pressure approximately 850 bar (Zidane West)

As the 5 DHSV will have an outer diameter > 9.0, the production casing will have to include a top section of 10 casing from wellhead to below DHSV setting depth, to accommodate room for the downhole gauge control lines. If some conductors are to be installed after start-up of production, DHSV setting depth should be moved down to below conductor shoe depth in order to avoid need for plugging production wells with bridge plugs while drilling top hole. A water based control line fluid, Transaqua HT2 has been used for the subsea HPHT on Kirstin and Morvin. During production, a maximum surface control line pressure of 850 bars is expected on Zidane West, based on a shut-in wellhead pressure of 630 bar. The downhole safety valves on Zidane will have to be installed at a depth where hydrates can potentially be formed. Equalizing and opening of the DHSV should be done with a MeOH or MEG/ freshwater mix which prevent potential hydrate formation. Expected maximum DHSV control line test pressures are described in Table 11-7.


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11.7 Completion Operational Steps

Based on the previous descriptions of assumptions, completion categorization and completion components, the following steps will be performed during Zidane completion operations: Well status; Horizontal XMT installed, 8 hole drilled to TD with +/- 1.82 s.g. OBM

1. Run bit, brush, scrapers and magnets. Wash down to TD and scrape all packer setting intervals. Displace to LSOBM completion mud.

2. Run pre-drilled liner (or standalone screens). Set liner hanger and packer. 3. Run multifinger caliper log in order to determine production casing wear down to

above liner hanger. 4. Run BOP cleaning BHA and clean BOP in LSOBM. 5. Run cleaning BHA (brush, scrapers, magnets) to above liner hanger. Scrape packer

setting areas and clean (with soap pills) and displace well from LSOBM to Cs/K formate brine.

6. Run BOP cleaning BHA and clean and wash riser and BOP. Clean all pits and surface lines.

7. Run middle completion (barrier assembly consisting of packer and tailpipe plug) and sting into liner hanger PBR. Test barrier assembly from above.

8. Retrieve HXT bore protector. 9. Rack THRT and prepare for upper completion. 10. Run upper completion (mule shoe, nipple, production packer and tubing). 11. Make up DHSV and tubing hanger and land upper completion. 12. Lock TH and pressure test from above. 13. Displace to packer fluid by reverse circulating out Cs/K formate mud against choke at

constant bottom hole pressure. 14. Test TH from below. Inflow test barrier assembly by bleeding down choke pressure. 15. RU wireline. RIH with and install standing valve (valve holding pressure only from

above) in production packer tailpipe on mechanical WL cable. 16. Pressure up well and set production packer and test tubing. 17. Inflow test DHSV. 18. Pull WL standing valve in production packer tailpipe. 19. Retrieve THRT w/isolation sleeve and drill pipe landing string. 20. RU WL and set lower tubing hanger plug as temporary P&A plug. 21. Pull BOP, marine riser and UDF. 22. Run LRP/EQDP and WOR incl. SFT and WL PCE. 23. Land and test same. 24. Displace WOR to MEG/FW. 25. Pull TH plug and install TH protection sleeve on WL. 26. Pull WL plug in barrier assembly and TH protection sleeve on WL. 27. Perform clean-up well through the rigs testing equipment. Perform build-up test. 28. Bleed off pressure and displace to WOR to MEG/FW. Inflow test DHSV. 29. Install 2 ea TH plugs on mechanical cable. 30. Retrieve WOR and LRP/EQDP. 31. Install and test high pressure (HP) cap. 32. Hand over well to Production Dept.


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11.8 Tubing Selection and Design

The tubing design is conducted mainly based on:

Suitable grade and material selection considering the metallurgy evaluation and expected loads (see chapter 12 and 11.8.3)

Optimum tubing size to support the expected gas production rates Stress analysis to evaluate the selected tubing and packer resistance against the

anticipated pressure, temperature, and loads during life of the well. With current technology for HPHT wells, a subsea TH/XMT will limit tubing size to 5 , unless a bottleneck completion is utilized. Access to the well for prospective interventions (plugs, straddles, etc.) will be limited by the 5 restriction.

11.8.1 Pressure testing requirements

The maximum shut in wellhead pressure (SIWHP) for Zidane West is 620 bar. The completion is designed according to NORSOK by defining the maximum work load (combined forces from pressure, tension and torque) at actual working temperature, times a safety factor of 1.1. The following input is given from subsurface:

Input

Zidane East Zidane West

Top reservoir [m TVD MSL] 4106 4165

Max reservoir temp (bottom reservoir) [C] 161 165

Reservoir pressure [bar] 631 722

Max SIWHP [bar] 540 620

Pressure gradient [bar/m] 0,022 0,024

Tab