Drilling Program AZSE-4 v.1.1 SIGNED

DRILLING PROGRAM DEVELOPMENT VERTICAL WELL AZRAFIL SOUTH EAST-4 AZSE-4

Document Number PS-2100-0549-003-E-00

Reggane Reggane Nord Development Proj ect

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Drilling Program Azrafil South East-4 Well

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APPROVAL SHEET

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Program Revision History Date 09/07/2017 13/08/2017

Revision 0 0

18/08/2017

1

20/08/2017 22/08/2017

1.1 1.1

Details Structure revised. Basis of Design included. Draft completed. Sent for revision Formation evaluation strategy reviewed and updated. Dispensation attachment attachment added. Issued for final revision. Final revision updated. Issued for signatures Program signed and distributed distribute d

Dispensations for AZSE-4 Well Design Document Requirement of ‘Wellhead and BOP Pressure Test’ as stated in the oil and gas industry standards such NORSOK D10 Requirement of ‘Casing Pressure Test’ as stated in the oil and gas industry standards such NORSOK D10

Description of Deviation

Justification Justificatio n

The proposed Policy Dispensation initiated for relaxation in requirement of ‘Casing, Wellhead and BOP Pressure Test’ as stated in the oil and gas industry standards. The 13 5/8", 10Kpsi Section B of the Wellhead and 13 5/8", 10Kpsi BOP stack can't be tested to the shut-in shut-in pressure (6,827psi) and design pressure (7,446 psi) respectively as per NORSOK standard D-010 because exceeds the 80% of the Burst Pressure (6,728 psi) of the 13 3/8" intermediate casing . This change will be permanent permanent during the life of the well.

Technical

The proposed Policy Dispensation initiated for relaxation in requirement of ‘Casing Pressure Test’ as stated in the oil and gas industry standards. standards. The pressure test of the 13 3/8" casing shall be limited to 5000psi due to equipment limitation i.e. 5K Cementing Head, which is lower than the maximum design pressure expected of 5850psi (Displacement to Gas with Fracture at Casing Shoe).

Technical

The Azrafil South East-4 well has been designed based on the statement of requirements indicated in the Pre-Drill-Data-Package document (PS-2000-0053-002-E-00_PDDP-AZSE-04.xls). This Drilling Program is based on the GRN Well Construction Process and has been prepared as a set, of well conditions and specific instructions to be followed during the drilling of the well, fifth development well to be drilled by the T-45 KCA Deutag Rig, working for GRN in the Reggane block. Open discussion about any elements of the program is encouraged and any perceived errors or contradictions should be brought to the attention of GRN Drilling and Completion Group. The quality of the drilling program will improve with constructive input from the operations personnel. personnel. Field input is therefore therefore strongly encouraged during the on-site planning and operations operations stages. It is imperative that any proposed deviations from the program are reviewed and agreed upon between the rig and office teams prior to implement following Management of Change process with corresponding approval .

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TABLE OF CONTENTS 1.

GENERAL INFORMATION INFORMATION.................................................................... ............................................................................................................. ......................................... 7 1.1. 1.2. 1.3. 1.4. 1.5. 1.6. 1.7.

2.

WELL ESTIMATED TIME ..................................................................................... ............................................................................................................. ........................ 21 2.1. 2.2.

3.

24” SECTION OBJECTIVE ......................................................................................... .......................................................................................................... ................. 25 24” SECTION H AZARDS & RISKS ......................................................................................... ............................................................................................... ...... 25 24” SECTION DRILLING OPERATIONS ........................................................................................ 25 24” SECTION DRILLING FLUIDS ................................................................................................. 29 24” CUTTING S AMPLING – MUD LOGGING PROGRAM ................................................................. 29 24” SECTION ELECTRIC LOGGING OPERATIONS ................................. ......................................................................... ........................................ 29 18 ⅝” SURFACE C ASING OPERATIONS ..................................................................................... 30

16” HOLE SECTION OBJECTIVES & OVERVIEW..................................................................... 38 6.1. 6.2. 6.3. 6.4. 6.5. 6.6. 6.7.

7.

RIG INSPECTION ........................................................................... ...................................................................................................................... ........................................... 24 GENERAL PREPARATION .......................................................................... .......................................................................................................... ................................ 24

24” HOLE SECTION. OBJECTIVES & OVERVIEW.................................................................... 25 5.1. 5.2. 5.3. 5.4. 5.5. 5.6. 5.7.

6.

S AFETY OPERATIONAL RESPONSIBILITIES ................................................................................. 23 MODIFICATIONS TO PROGRAM .................................................................................................. 23 PRE-JOB S AFETY MEETING ...................................................................................................... 23

PRE-SPUD PREPARATION............................................................................ ......................................................................................................... ............................. 24 4.1. 4.2.

5.

TIME BREAK DOWN BY PHASE .................................................................................................. 21 TIME BREAK DOWN BY PHASE .................................................................................................. 21

HSE .............................................................................. ............................................................................................................................................... ................................................................. 22 3.1. 3.2. 3.3.

4.

INTRODUCTION ...................................................................... .......................................................................................................................... .................................................... 7 ABBREVIATIONS ......................................................................................................... ....................................................................................................................... .............. 14 UNITS CONVENTION .................................................................................................. ................................................................................................................. ............... 15 B ASIC WELL D ATA ................................................................................................................... 16 DRILLING RIG................................................................................. ........................................................................................................................... .......................................... 17 WELL SCHEMATIC ...................................................................................................... .................................................................................................................... .............. 18 PRESSURE AND TEMPERATURE ................................................................................................ 19

16” SECTION KEY POINTS ........................................................................................................ 38 16” SECTION H AZARDS & RISKS ......................................................................................... ............................................................................................... ...... 38 16” SECTION DRILLING OPERATIONS ........................................................................................ 39 16” SECTION DRILLING FLUIDS ................................................................................................. 44 16” CUTTING S AMPLING – MUD LOGGING PROGRAM ................................................................. 44 16” SECTION ELECTRIC LOGGING OPERATIONS ................................. ......................................................................... ........................................ 45 13 ⅜” C ASING OPERATIONS ................................................................................................. ..................................................................................................... .... 45

12 ¼” HOLE SECTION OBJECTIVES & OVERVIEW................................................................. 54 7.1. 7.2. 7.3. 7.4. 7.5. 7.6. 7.7.

12 ¼” SECTION KEY POINTS ................................................................................. .................................................................................................... ................... 54 12 ¼” SECTION H AZARDS & RISKS ........................................................................................... 54 12 ¼” SECTION DRILLING OPERATIONS ..................................................................................... .................................................................................... 54 12 ¼” SECTION DRILLING FLUIDS ............................................................................................. 58 12 ¼” CUTTING S AMPLING – MUD LOGGING PROGRAM.............................................................. 58 12 ¼” SECTION WIRELINE LOGGING OPERATIONS ..................................................................... 58 9 ⅝” C ASING OPERATIONS .................................................................................................... ....................................................................................................... ... 59

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8 ½” HOLE SECTION OBJECTIVES & OVERVIEW................................................................... 67 8.1. 8.2. 8.3. 8.4. 8.5. 8.6. 8.7.

9.


8 ½” SECTION KEY POINTS .................................................................................................... ....................................................................................................... ... 67 8 ½” SECTION HAZARDS & RISKS ............................................. .............................................................................................. ................................................. 67 8 ½” SECTION DRILLING OPERATIONS ....................................................................................... ...................................................................................... 67 8 ½” SECTION DRILLING FLUIDS ............................................................................................... 71 8 ½” CUTTING S AMPLING – MUD LOGGING PROGRAM................................................................ 71 8 ½” SECTION ELECTRIC LOGGING OPERATIONS ........................................................... ....................................................................... ............ 71 7” LINER OPERATIONS ............................................................................................................. ............................................................................................................ 72

ANNEXES ........................................................................................................................ ..................................................................................................................................... ............. 74 9.1. 9.2. 9.3. 9.4. 9.5. 9.6. 9.7. 9.8. 9.9. 9.10. 9.11.

ANNEX I – C ASING SPECIFICATIONS ........................................................................................ 74 ANNEX II – II – 10K PSI W.P. WELLHEAD SPECIFICATIONS............................................................. 75 ANNEX III – III – BOP, WELLHEAD AND C ASING PRESSURE TEST ...... .................................................... .............................................. 76 ANNEX IV – IV – DRILLING BITS SPECIFICATION. ............................................................................ 77 ANNEX V – MUD PROGRAM SUMMARY ................................................................................... 100 ANNEX VI – VI – CEMENT PROGRAM SUMMARY ............................................................................ 101 ANNEX VII – VII – LCM DECISION TREE ........................................................................................ ....................................................................................... 102 ANNEX VIII - RISK ASSESSMENT ....................................................................................... ........................................................................................... .... 103 ANNEX IX – IX – WELL DIAGRAM (A3 FORMAT) ............................................................................ 111 ANNEX X – OFFSET WELLS ................................................................................... ................................................................................................... ................ 112 ANNEX XI – XI – DRILLING J AR CHANGE OUT RECOMMENDATIONS ................................................ 117

LIST OF FIGURES Figure 1 – Reggane Location Map ....................................................................................................................7 Figure 2 – AZSE-4 General Location ................................................................................................................8 Figure 3 – Reggane Nord Exploration Perimeter ............................................................................................ ............................................................................................9 9 Figure 4 – AZSE-4 Structural map ...................................................................................................................10 10 Figure 5 – Cross-Seismic Sections .................................................................................................................11 11 ......................................................................................................17 17 Figure 6 – Rig KCAD T45 Characteristics ...................................................................................................... Figure 7 – Well Schematic ................................................................................................................................18 18 Figure 8 – Pore Pressure, Fracture and Overburden Gradient Profiles ..................................................... .....................................................19 19 Figure 9 – AZSE Field Temperature Profile ................................................................................................... ...................................................................................................20 20 21 Figure 10 – Time vs. Depth Curve ...................................................................................................................21 Figure 11 – 30” Conductor Stack Up Diagram (24” Section) ....................................................................... .......................................................................28 28 Figure 12 – 30” Conductor & 18 ⅝” Casing Cut ............................................................................................ ............................................................................................33 33 Figure 13 – 18 ⅝ Casing Head Housing (Section A) .................................................................................... ....................................................................................35 35 Figure 14 – 30” Conductor Stack Up Diagram (16” Section) ....................................................................... .......................................................................37 37 Figure 15 –13 ⅜ Casing Cut and Casing Head Housing ............................................................................. .............................................................................50 50 Figure 16 – 13 ⅝ Casing Spool ........................................................................................................................51 51 Figure 17 – 12 ¼” Section BOP Stack Diagram ............................................................................................ ............................................................................................53 53 63 Figure 18 – 9 ⅝ Casing Cut ..............................................................................................................................63 Figure 19 – Casing Head Spool, Section C .................................................................................................... ....................................................................................................64 64 Figure 20 – 8 ½” Section BOP Stack Diagram .............................................................................................. ..............................................................................................66 66 Figure 21 – Cameron Wellhead System 10K ................................................................................................. .................................................................................................75 75

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LIST OF TABLES Table 1 – Formation estimated tops ................................................................................................................ ................................................................................................................12 12 Table 2 – Lithological sequences and corresponding pressure profile ...................................................... 13 Table 3 - Basic Well Data .................................................................................................................................. ..................................................................................................................................16 16 Table 4 – AZSE-4 Expected temperatures at formation tops ...................................................................... 20 Table 5 – AZSE-4 Time break down by phase .............................................................................................. ..............................................................................................21 21 Table 6 – 24” Recommended Bits ................................................................................................................... ...................................................................................................................25 25 Table 7 – 24” Recommended Drilling Parameters ........................................................................................ 26 Table 8 – 24” Rotary BHA Assembly ............................................................................................................... ...............................................................................................................26 26 Table 9 – 24” Recommended Drilling Fluids Properties ............................................................................... 29 Table 10 – 18 ⅝” Casing String ....................................................................................................................... .......................................................................................................................30 30 Table 11 – 16” Recommended Bits ................................................................................................................. .................................................................................................................39 39 Table 12 – 16” Recommended Drilling Parameters ...................................................................................... 39 Table 13 – 16” RSS BHA Assembly ................................................................................................................ ................................................................................................................40 40 Table 14 –16” Rotary BHA Assembly .............................................................................................................. ..............................................................................................................41 41 Table 15 – 16” Planned FIT .............................................................................................................................. ..............................................................................................................................42 42 Table 16 – 16” Recommended Drilling Fluids Properties ............................................................................. 44 Table 17 – 13 ⅜” Casing String ....................................................................................................................... .......................................................................................................................45 45 Table 18 – 12 ¼” Recommended Bits ............................................................................................................. .............................................................................................................54 54 Table 19 – 12 ¼” Recommended Drilling Parameters .................................................................................. 55 Table 20 – 12 ¼” RSS BHA Assembly ............................................................................................................ ............................................................................................................55 55 Table 21 – 12 ¼” FIT ......................................................................................................................................... .........................................................................................................................................56 56 Table 22 – 12 ¼” Recommended Drilling Fluids Parameters ..................................................................... 58 Table 23 – 9 ⅝” Casing String .......................................................................................................................... ..........................................................................................................................59 59 Table 24 – 8 ½” Recommended Bits ............................................................................................................... ...............................................................................................................67 67 Table 25 – 8 ½” Recommended Drilling Parameters .................................................................................... 68 Table 26 – 8 ½” RSS BHA ................................................................................................................................ ................................................................................................................................68 68 Table 27 – 8 ½” Packed BHA ........................................................................................................................... ...........................................................................................................................69 69 Table 28 – 8-1/2” Expected ExLOT ................................................................................................................. .................................................................................................................70 70 Table 29 – 8 ½” Recommended Drilling Fluids Parameters ........................................................................ 71 Table 30 – 7” Liner Specifications ................................................................................................................... ...................................................................................................................72 72 Table 31 – Casing Specifications ..................................................................................................................... .....................................................................................................................74 74 Table 32 - BOP, Wellhead and Casing Pressure Test Activity Outline. ..................................................... 76

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1. General Information 1.1. Introduction Groupement Reggane Nord Project (GRN) is planning to drill a development well AZSE-4 vertically in the Azrafil area, Algerian Sahara in the Wilaya of Adrar southwestern Algeria, in the development of first gas drilling campaign. This well will be the second development gas producer to be drilled by GRN in Azrafil SE Field with target of Lower Devonian reservoirs. This well will drain gas reservoirs in the central part area of the field and it will confirm the quality of Lower Devonian formations mainly Gedinnian A, Gedinnian B and Siegenian C. The location is selected on the basis on integrated evaluation of geophysics, geology and reservoir engineering. In order to reach the objective, AZSE-4 well will be drilled down to 3,914m TVDRT. The well is expected to encounter Siegenian-C at 3668m, before reaching its final-depth including roughly 50m of rat hole for logging operations and having enough length inside the 7” liner to avoid cement clean out operations. 1.1.1.

Location

AZSE-4 development well will be located at Latitude: 26°44'19.32029"N Longitude: 0°15'36.03728"E (Y-Northing: 2961409.100 m and X-Easting: 824300.928 m using Datum: North Sahara 1959 Zone 30 (Clarke1880). The well is located approximately at 1.95 Km from AZSE-3 ST and 4.28 km from AZSE21.

Figure 1 – Reggane Location Map Groupement Reggane



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Figure 2 – AZSE-4 General Location 1.1.2.

Drilling Objectives



Drill AZSE-4 with zero lost time accidents and zero environmental accidents.



Drill AZSE-4 through Sieg-C, Ged-B and Ged-A reservoir´s down to planned TD at 3914mTVDRT (~70m below bottom of reservoir as per Production department requirement), within 50m radius tolerance.



Facilitate the acquisition of a comprehensive wireline logging suite across the reservoir.



Case off hydrocarbon reservoirs to use the well as a future producer.



Drill within the proposed time and budget ensuring HSE standards.



Complete the well. 1.1.3.

Subsurface Objectives



Develop the Devonian Reservoirs (Sieg-C, Ged-A & Ged-B)



Prove the Lower Devonian reservoir (Sieg-C, Ged-A & Ged-B), petrophysical characteristics and the hydrocarbon potential.



Retain AZSE-4 as a producer.

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Background Information

As part of the third International Licensing Round called by the Algerian Ministry of Energy and Mines together with SONATRACH in 2002, GRN Exploration Algeria S.A. in Joint Venture with RWE Dea AG and Edison International were awarded the Reggane Nord license with a total perimeter area of 12,217.5 Km², and a contract signed with SONATRACH for the Exploration, Appraisal and Exploitation of Reggane Nord blocks 351c and 352c (referred to later as PSA). Prior to the award, SONATRACH had explored the blocks resulting in the discovery of Lower Devonian reservoirs in Reggane structure in Apr-64 (with well RG-102) and Azrafil structure (with well AZSE-1) in Sep-2000. SONATRACH also drilled wells RG-3 (weak gas, low WHP, in 1983) and RG-4 (weak gas, low WHP, in 1985) in Reggane and TIO-1 (dry, 1980) and TIO-2 (dry, 1981) in Tiouliline structure. Several exploration works at various fields within the perimeter of the “Reggane Nord” blocks were completed during the period 2002-2009 by GRN acting as operator of the JV formed by GRN (45%), RWE (30%) and Edison International (25%). Exploration works included 2D/3D seismic acquisition and the drilling of exploration wells with a positive result of dry gas flow in the Reggane (RG), Azrafil SE (AZSE), Kahlouche (KL), Kahlouche Sud (KLS), Sali (SLI) and Tiouliline (TIO) fields and negative results in the prospect areas of Djebel Heïrane (DJHN) and Anzeglouf (AZF). In all cases, the nature of the discovered hydrocarbons is dry gas with very low liquid content. A total of 15 wells were drilled (see Figure 3 below): 

Reggane: RG-5, RG-6 and RG-7



Sali: SLI-1 and SLI-2



Azrafil: AZSE-2 and AZSE-3.



Tiouliline: TIO-3



Kahlouche: KL-2, KL-3 and KL-4.



Djebel Hirane: DJHN-3



Kahlouche South: KLS-1 and KLS-2



Azenglouf: AZF-1

Figure 3 – Reggane Nord Exploration Perimeter Groupement Reggane


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Formation Tops / Reservoir Target

In general, the seismic time interpretation has a reasonable and reliable quality for structural interpretation in the flanks of Reggane and in most of Azrafil. The structural uncertainty increases in the structural crest of Reggane where seismic imaging deteriorates severely as a consequence of geological complexity caused by the Reggane Master Fault and associated faulting. Dolerites are seismically identifiable. However, since dolerites generates some degree of various seismic diffractions and multiples, the seismic interpretation become challenging and complicated in the areas below the dolerite intrusions, particularly where dyke intrusions occur sub-horizontally to the formation layering.

Figure 4 – AZSE-4 Structural map

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Figure 5 – Cross-Seismic Sections

The expected reservoir pressures are as follows: SIEG-C: 6,209psi, GED-B: 6,224 psi, GED-A: 6,250psi. And summary table of Formation tops is illustrated below:

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AZSE‐4 ESTIMATED TOPS SURFACE

TVDSS (mSS)

DEPTH (mMD)

HERC_UNC

‐96

385

NAMURIAN

‐96

385

VISEAN D

‐239

VISEAN C

GROSS (m)

DIP (deg)

AZIM (deg)

4

285

143

1

31

528

173

1

31

‐412

701

240

3

291

VISEAN B

‐652

941

380

3

265

VISEAN A

‐1032

1321

296

2

311

TOURNAISIAN

‐1327

1616

316

3

3

TOURN_DOLERITE

‐1469

1758

138

4

71

STRUNIAN

‐1643

1932

115

3

49

FAMENNIAN

‐1758

2047

1253

4

357

FAM_DOLERITE #1

‐1764

2053

30

11

360

FAM_DOLERITE #2

‐1863

2152

11

3

300

FRASNIAN

‐3011

3300

143

3

295

GIVETIAN

‐3154

3443

48

3

291

COUVINIAN

‐3202

3491

63

3

341

EMSIAN

‐3265

3554

65

3

341

MDECHINE

‐3330

3619

25

4

332

SIEGENIAN D

‐3355

3644

24

4

329

SIEGENIAN C

‐3379

3668

59

4

327

GEDINNIAN B

‐3438

3727

90

5

359

GEDINNIAN A

‐3529

3818

26

9

13

SILURIAN

‐3555

3844

70

9

14

TD

‐3625

3914

Table 1 – Formation estimated tops

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Interval Depth m (RT)

Description

HOLOCENE

280

Loose sand. Cenezoic and Mesozoic deposits are not present.

NAMURIAN

385

Upper section: interbedded sequence of Clayst one and Sandstone with occasional Anhydrite beds. Lower section:

VISEAN D

528

Limestone Interbedded with Clays tone and Anhydrite

VISEAN C

701

Upper part: interbedded Claystone and Sandstone. Lower part: mostly Limestone intercalated with claystones

VISEAN B

941

Upper part: mostly Claystone interbedded by Sandstone. Lower part: Clays tone interbedded with Sandstone with occasional Limestone stringers.

VISEAN A

1321

Mostly Claystone interbedded with Sandstone with occasional Limestone stringers.

TOURNAISIAN

1616

Massive, homogenous, dark grey to black Claystone with Sandstone and occasional Siltstone beds

TOURN_DOLERITE

1758

Dip Angle 4°

STRUNIAN

1932

Claystone with Sandstone beds, together with Siltstone.

FAMENNIAN

2047

Upper part: Claystone, Siltstone and Sandstone, possibly with indications of thermal alteration by the Dolerite intrusion. Middle part: Claystone grading to Siltstone interbedded with Sandstone. Lower part: Claystone grading to Siltstone with Limestone stringers.

FAM_DOLERITE #1

2053

Dip Angle 11°

FAM_DOLERITE #2

2152

Dip Angle 3°

FRASNIAN

3300

Claystone occasionally grading to Siltstone with common Limestone stringers.

GIVETIAN

3443

Interbedded Limestone and Claystone.

COUVINIAN

3491

Claystone grading to Argillaceous Siltstone with Limestone stringers and rare Sandstone.

EMSIAN

3554

Upper part: Sandstone interbedded Claystone. Lower part: Claystone interbedded with Limestone.

MURAILLE DE CHINE

3619

Intercalations of hard limestone and claystone. Possible traces of sandstones. At the bottom: Claystone, dark grey.

SIEG - D

3644

Upper part mostly Sandstones, lower part claystones interbedded with s andstones.

SIEG - C

3668

Upper part mostly Sandstones, lower part claystones interbedded with siltstone.

GED - B

3727

Upper part mostly tight Sandstones, middle consists of productive sandstone and the lower part contains of clay stones intercalated with sandstones.

GED - A

3818

Mostly sandstones intercalated with thin bed shally layers.

SILURIAN

3844

Mostly claystones with streaks of sandstones.

TD

3914

70m below top of Silurian formation

Table 2 – Lithological sequences and corresponding pressure profile Groupement Reggane


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1.2. Abbreviations API:

American Petroleum Institute

OD:

Outside Diameter

BBL:

Barrels

OEDP:

Open Ended Drill Pipe

BHA:

Bottom Hole Assembly

OLC:

Operations Liaison Coordinator

BOCP:

Blow Out Contingency Plan

OWC:

Oil Water Contact

BOP:

Blow Out Preventer

PDDP:

Pre Drilling Data Package

BPM:

Barrels Per Minute

Pg:

Probability of Geological Success

CHH:

Casing Head Housing

POB:

Personnel On Board

CHS:

Casing Head Spool

POOH:

Pull Out Of the Hole

CP:

Conductor Pipe

PP:

Pore Pressure

DEMOB:

Demobilization

ppm:

Parts per million

ECD:

Equivalent Circulating Density

PUW:

Pick Up Weight

EIA:

Environmental Impact Assessment

P/U:

Pick Up

ERP:

Emergency Response Plan

PV:

Plastic Viscosity

EMW:

Equivalent Mud Weight

RIH:

Run In Hole

FF:

Friction Factor

R/U:

Rig Up

FCP:

Final Circulating Pressure

R/D:

Rig Down

FIT:

Formation Integrity Test

ROP:

Rate of Penetration

FP:

Fracture Pressure

RPM:

Revolutions Per Minute

GOC:

Gas-Oil Contact

RT:

Rotary Table

GSA:

Geo-hazards Study Agreement

SCR:

Slow Control Rates

HC:

Hydrocarbon

SICP:

Shut In Casing Pressure

HWDP:

Heavy Weight Drill Pipe

SIDPP:

Shut In Drill Pipe Pressure

IB:

Integral Blade

SG:

Specific Gravity

ID:

Inside Diameter

SOW:

Slack-Off Weight

KT:

Kick Tolerance

SPP:

Stand Pipe Pressure

L/D:

Lay Down

STB:

Stabilizer

LOT:

Leak-Off Test

TCP:

Tubing Conveyed Perforating

LPM:

Liters Per Minute

TD:

Total Depth

LWD:

Logging While Drilling

TDS:

Top Drive System

md:

Milidarcies

THS:

Tubing Head Spool

MOB:

Mobilization

TVDRT:

True Vertical Depth below Rotary Table

MSL:

Mean Seal Level

TVDGL :

True Vertical Depth below Ground Level

MDRT:

Measure Depth below Rotary Table

UR:

Underreamer

MDGL :

Measure Depth below Ground Level

WH:

Well Head

M/U:

Make Up

WOB:

Weight On Bit

NB:

Near Bit

WOC:

Wait On Cement

N/A:

Not Applicable

WP:

Working Pressure

N/U:

Nipple Up

XO:

Cross-Over

N/D:

Nipple Down

YP:

Yield Point

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1.3. Units Convention Length/Height:

m

Depth:

m

Measure Depth below RT:

m MDRT

True Verti cal Depth below RT:

m TVDRT

Measure Depth below GL:

m MDGL

True Verti cal Depth below GL:

m TVDGL

Rotary Table Elevation:

m

Coordi nates N/S – E/W:

m

Rate of Penetration:

m/h

Mud Weight:

sg

Torque:

lb-ft

WOB:

Ton

Flow Rates:

liters per minute (lpm) bbl/min (only for pumping cement with cement unit; for displacements with Rig Pump to use lpm)

Temperature:

°C

Temperature Gradient:

°C/100 m

An gle:

(°)

Diameter (OD/ID):

Inches (”)

Linear Weight:

lb/ft

Pressure:

psi

Pore Pressur e:

psi

Pressure Gradient:

psi/ft

Fracture Pressure:

psi

Inclination/Azimuth:

deg (°)

ECD:

sg

Volume:

m

Linear Capacity/Displacement:

liters/meter (l/m)

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1.4. Basic Well Data Generic Name

Azrafil South East-4 (AZSE-4)

Area

Reggane

License / Block Number

351c

Classification

Development Vertical Well

Rig

T-45

Rotary Table Elevation (RT)

9.37 m

Ground Level (GL)

279.4 m (GL), 288.78 m (RTKB)

Planned Total Depth

3914 m TVDRT / 3914 m TMD RT

Surface Location

UTM

Northing

Easting

UTM30NNSahara1959:UTM zone 30N / Spheroid Clarke 1880_RGS

2961409.10 m

824300.928 m

Latitude

Longitude

26°44'19.32029" N

0°15'36.03728" E

Geodetic Datum

Nord Sahara 1959, Zone 30

Geological Target

Lower Devonian Reservoir (Ged-A, Ged-B & Sieg-C)

Tolerance

50 m radius

Bottom Hole Temperature

132° C (approx.)

Hydrocarbon Gradient

Gas Gradient (0.1 psi/ft) for well design

H2S / CO2

Not Expected / +- 3.8%

Planned Final Well Status

Production

Key Offset Wells

AZSE-1, AZSE-2 ST1, AZSE-3 ST, AZSE-21

Total Estimated Cost

19.8 M USD (Mobilization and Completion included)

Total Estimated Time

132.2 days (Mobilization and Completion included) Table 3 - Basic Well Data

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1.5. Drilling Rig

Figure 6 – Rig KCAD T45 Characteristics

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1.6. Well Schematic

Figure 7 – Well Schematic Groupement Reggane



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1.7. Pressure and Temperature 1.7.1.

Pore Pressure and Fracture Gradient Estimate

Figure 8 shows the calculated Pore Pressure profiles for AZSE-4.

Figure 8 – Pore Pressure, Fracture and Overburden Gradient Profiles Groupement Reggane


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Temperature Profile

Figure 9 – AZSE Field Temperature Profile FORMATION EX P. TOP S NAMURIAN 385 VISEAN D 528 VISEAN C 701 VISEAN B 941 VISEAN A 1321 TOURNAISIAN 1616 TOURN_DOLERITE 1758 STRUNIAN 1932 FAMENNIAN 2047 FAM_DOLERITE #1 2053 FAM_DOLERITE #2 2152 FRASNIAN 3300 GIVETIAN 3443 COUVINIAN 3491 EMSIAN 3554 MURAILLE DE CHINE 3619 SIEG - D 3644 SIEG - C 3668 GED - B 3727 GED - A 3818 SILURIAN 3844 TD 3914

EX P. TEMP ºC (MI N)

23 27 32 39 50 59 63 68 72 72 74 108 112 113 115 117 118 118 120 123 123 125

EX P. TEM P º C (AV G)

EX P. TEMP ºC (MAX )

30 34 39 46 57 66 70 75 79 79 81 114 119 120 122 124 124 125 127 129 130 132

Table 4 – AZSE-4 Expected temperatures at formation tops

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37 41 46 53 64 72 77 82 86 86 88 121 125 127 129 131 131 132 134 136 137 139



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2. Well Estimated Time 2.1. Time Break Down by Phase Estimated time to drill the well is 102.3 days, without Mobilization and Completion. Figure below shows the time vs. depth curve, including 6.8 days to complete the well.

Figure 10 – Time vs. Depth Curve

2.2. Time Break Down by Phase The estimated duration of the well can be break down per phase and main activity as follows:

Planned AZSE-4 Base Case Mobilization

24" Hole Section / 18-5/8" Casing 16" Hole Section / 13 3/8" Casing 12-1/4" Hole Section / 9-5/8" Casing

8 1/2" Hole Section / 7" liner Completion and Suspension

TOTAL with mob TOTAL without mob

Table 5 – AZSE-4 Time break down by phase Groupement Reggane

P50 Time 23,10 day(s) 7,65 day(s) 45,3 day(s) 27,3 day(s) 22,1 day(s) 6,77 day(s) 132,22 day(s) 109,11 day(s)



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3. HSE All activities must be planned and executed taking into account the safety, health and environmental protection in line with OHSAS 18001, ISO 14001 and the best OGP practices. As a complementary document of this Drilling Program a specific HSE plan will be also available describing in details the different HSE activities to be performed during the drilling activities of the well. An Emergency Response Plan is developed taking into account operation local conditions and the different emergency levels. 

    

The Emergency Response that will be developed for this well will include GRN Emergency Response Plan (Emergencies Level II and Level III). HRA and Medevac Response Plan. Evacuation Plan for Security reasons. Blow Out Contingency Plan. Diesel and Chemical Spill Response Plan. KCAD T-45 ERP.

A combined document (Bridging document) is already approved and signed. This document has the purpose of establishing the interphase between GRN Policies and Rules with HSE Policies of the Drilling Contractor. The following are, but not limited, some safety guidelines to govern the operations:  















 





The safety of personal, environment and equipment is vital for GRN. It should exist in the Well site, an archive with all Safety, Health and Environment relevant documents (HSE Plan, Bridging Document, ERPs, etc.). The GRN Safety, Health and Environment policy should be available and arranged in such a way that is easy to view it. Health, Safety and Environmental issues should be part of the daily coordination meetings in the Drilling Site and HMD Drilling Offices. Weekly meetings should be undertaken with all staff including GRN Company Man to discuss HSE issues. Any incident and personnel or environmental accidents must be reported within the first 24 hours in accordance with current GRN normative. Safety cards (STOP) can be filled by personnel from any service company involved in the operations. Every critical activity during the drilling operation must be withstood with safety meetings before and after work. The use of Permit to Work (PTW) is mandatory which must be reviewed and approved by the service companies supervisors and ultimately by the Tool Pusher and Company Man. In every safety meeting, a personnel record should be signed by all participants. Periodic emergency drills (Well control, Medevac, others) should be undertaken according to the instructions of the GRN Company Man. The crew participation and response time will be recorded in the Daily Drilling Report. The Rig site personnel meeting areas should be clearly defined and be communicated directly by the Company Man to the entire crew. A control of personnel and vehicles entering and exiting the location should be adopted.

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Document Number PS-2100-0549-003-E-00 


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Clear procedures and rules should be followed for land transport including but not limited at journey management, speeds limits, defense driving course, vehicle standard and minimum vehicle equipment.

3.1. Safety Operational Responsibilities The Company Man has primary responsibility for ensuring safe implementation of the operations detailed in this program and will directly supervise all drilling operations.

3.2. Modifications to Program Due to unpredictable hole conditions and potential for equipment problems during drilling operations stated in this Program, Management of Change Procedure has been implemented. Prior to changing the program, an initial assessment of the impact of the proposed change should be undertaken to establish if there is any increase in safety and/or environment risk. If concluded that risks are increased due to a required change to the program and/or if the “pressure boundary” of the well will be materially changed from the planned status then the change must be reviewed, justified and agreed between Operational Supervisors and the Superintendent then confirmed in writing by a Management of Change document that should be signed by the parties. According with the nature and magnitude of the change, MOC document could require the signature and approval of the Drilling Manager and GRN Co-Administrators.

3.3. Pre-job Safety Meeting Prior of the commencement of each operation, a pre job safety meeting, based on the Risk Assessment, will be held with all personnel involved in the operation. A technical briefing will be given on the operation to be carried out, and any hazards and precautions to be taken will be reviewed. If required, additional pre job meetings will be held either due to crew changes occurring or because of additional personnel or services becoming involved in the operations. As the drilling operations will continue to change focus through the various stages of the well, personnel must be kept fully briefed and continually updated as the various work tasks change. At the pre job safety meetings, all aspects of the particular operation to be performed should be discussed, including any contingency plans. Suggested topics to be included in the meeting agenda:   



 

Work permit required for the site. Non-essential personnel to be restricted from the work site. Allocation of personnel responsible for opening, closing of all valves and depressurizing equipment. Review the pertinent risk assessment documents for each individual stage of the operations, Securing, handling and operation of lines under pressure, Handling of fluids and pressure testing.

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4. Pre-spud Preparation 4.1. Rig Inspection The rig inspection will be performed by Drilling Superintendent and Company Man, according to the last GRN Land Rig Checklist. HSE pre-spud inspection shall be performed by the GRN HSE representatives. Prior to the start of operations, the rig must be in good working order with all essential equipment, including critical spare parts, present and functioning properly.

4.2. General Preparation 

Ensure the planned quantity of crossover subs, their size, material grade and inspection certificates, are available according with operation as planned in the present Drilling Program. The service suppliers shall provide to the GRN Company Man their tools specifications (i.e. dimensions, thread, material grade and copy the last inspection certificates) and supply the appropriate crossover subs to fit the drill string as required.



Ensure the planned quantity, type, size of fishing tools and the required accessories are available on site and thoroughly inspected.



Ensure the required equipment and materials (main and backup) from both GRN and appointed Service Suppliers are available on site prior to spud the well, such as bits and nozzles, casing, mud chemicals, cementing unit and float equipment (i.e. floats, plugs, centralizers, stop collars, cementing heads, downhole tools, etc.).



Carry out the cementing unit hydrostatic testing. The hydrostatic test should be performed with water as clean as possible and recorded with a calibrated chart recorder. The hydrostatic testing acceptance criteria is ‘zero’ (0 psi) pressure drop over 15 minutes after the stabilization period.



Ensure the length of the DP’s, HWDP’s and DC’s, is taken in ‘meters’ by using a ‘metallic’ measuring tape (plastic measuring tape, and units conversion are NOT ACCEPTABLE).



Continuous water supply haulage from Reggane area (adjacent water well of RG-06) or from 3 Moulay Nadjem water well, so the location water pit (2500 m usable volume) have to be full 3 before spud-in date. A minimum safety stock of 100 m of diesel has also to be onsite in order to ensure operations continuity.



Perform training on surface hole emergency response.



Heavy mud and LCM must be available on-site: o

50m3 of Heavy mud, 1.5 sg MW to be available in tanks prior to spud for displacement of the entire hole volume.

o

Have ready LCM batches to pump in case of losses (an approximate volume of 10 m 3 3 LCM pills at 150 kg/m & 300 kg/m concentration will be prepared for the 24” phase).

o

For 16”, 12 ¼” and 8 ½” phases LCM products will be ready at site just in case but no batch will be pre mixed.



Pick up only enough 5” DP to get to 450 m and rack back in derrick.



Measure and report on DDR the Rig Rotary Table (RT) to Ground-Level (GL) distance.

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5. 24” Hole Section. Objectives & Overview 5.1. 24” Section Objective 1. The objective of this interval is to safely drill a 24” vertical hole throughout the Cretaceous / Namurian formation to a section TD of +-450 m (to be adjusted accordingly with casing tally). 2.

Maintain good hole cleaning and wellbore stability.

3.

Run and cement 18 ⅝” casing safely to isolate possible aquifers and achieve adequate formation integrity test to drill the next 16” phase.

5.2. 24” Section Hazards & Risks 

Possible mud losses and washouts below 30” conductor.



Possible bit and stabilizer balling while drilling throughout the claystones.



Claystones reactivity can affect the wellbore stability issues due to plastic shale and or unconsolidated sands.



Refer to Annex VIII Risk Assessment to see all the preventive and mitigation actions for this phase.



Refer to Annex X Offset wells information for more details about field experience.

5.3. 24” Section Drilling Operations 5.3.1.

Recommended Bit & Hydraulics

A tricone bit (IADC 515) with center jet will be used to drill in rotary mode with expected average ROP of 7 m/h once full parameters are applied. Bit

Primary (IADC)

Back Up (IADC)

24”

Varel TCI - ETR24JMRS (515)

Varel MT - ETR1GJMRS (115)

Table 6 – 24” Recommended Bits 5.3.2.

Recommended Drilling Parameters

The section will be drilled with 100-140 rpm, flow will be increased as the section is drilled. To avoid washing out the cellar flow rate will be limited to 1500lpm for first 5-10m at least, then it will be increased progressively up to 3200 lpm if no losses are present. ROP will be controlled and Hi-Vis pills will be pumped as required avoiding cuttings overloading in the annulus.

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Section

Mode

Bit

WOB (Ton)

RPM Rotary

Flow Rate (lpm)

SPP (psi)

TFA (in2)

HSI (HP/in2)

24"

Rotary

TCI

5‐20

60‐140

2700‐3300

900‐1500

0.941 3x18" +1x16" CJ

1,2

Table 7 – 24” Recommended Drilling Parameters

5.3.3.

Recommended BHA

Objective of this interval is to keep the wellbore as near to vertical as possible while maintaining an optimum ROP. In order to do so a pendulum BHA will be run. A shock Sub will be used/located near the bit in order to isolate axial vibration from the bit to drill string. The dimensions of all tools and BHA components must be checked prior to RIH.

24" Rotary BHA #1 Item

Name

OD (in)/ ID (in)

1

TCI Bit

24

2

Bit Sub (with Float Valve + Totco ring)

3

Shock Sub

4

1 x 9 ½” DC

5

String Stab - SLB

6

1 x 9 ½” DC

7

String Stab - SLB

8

2 x 9 ½” DC

9

XO

10

6 x 8 ¼" DC

11

Jar

12

2 x 8 ¼" DC

13

XO

14

15 x 5" HWDP

15

5" DP S135, 24.21 lb/ft, Premium

9½ 3 9½ 2 4/5 9½ 3 9½ 3 9½ 3 9½ 3 9½ 3 9⅜ 2¼ 8¼ 2⅞ 8 3 8¼ 2⅞ 8¼ 2⅞ 5 3 5

Max OD (in)

9½ 9½ 9½ 23 ⅞ 9½ 23 ⅞ 9½ 9⅜ 8¼ 8 8¼ 8¼ 5 5

Bottom/ Top Connection

Length (m)

Cum. Length (m)

7 ⅝" Reg Pin

0,6

0,6

0,9

1,5

3,52

5,02

9,3

14,32

2,43

16,75

9,3

26,05

2,43

28,48

18,6

47,08

0,45

47,53

54,86

102,39

10,2

112,59

18,92

131,51

0,9

132,41

139,5

271,91

7 ⅝" Reg Box 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 7 ⅝” Reg Box 7 ⅝” Reg Pin 6 ⅝" Reg Box 6 ⅝" Reg Pin 6 ⅝" Reg Box 6 ⅝" Reg Pin 6 ⅝" Reg Box 6 ⅝" Reg Pin 6 ⅝" Reg Box 6 ⅝" Reg Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin

Table 8 – 24” Rotary BHA Assembly

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Note: Estimated lengths only, final lengths to be checked on location. 5.3.4.

Recommended Drilling Procedure

1.

A flow riser will be installed in order to have returns through the bell nipple. A centrifugal pump has to be kept as backup in case returns will be taken through the cellar (see figure 11).

2.

Make up the 24” rotary BHA. Include a float valve and Totco ring. Record weight below jar. RIH to tag cement.

3.

Drill 24” hole to  30m using a lower flow rate (max. 1500 lpm) when around the 30” conductor shoe area, until the upper 24” stabilizer is 5 m below the shoe. 

If any sign of losses stop drilling and decrease pump rate. Inform Drilling Superintendent to define the way forward.



Keep Mud Weight Out 

1.10 SG by continuously:

Checking Mud Weight-out before Shale Shakers. Record every 15 min.



Bring up pumps gradually to avoid surge.



Hard reaming drilled hole twice before each connection.



Monitoring cuttings volume to track any sign of big washout with ROP trend.



Monitor hole fill up behavior on connections.

4.

Once 24” top stabilizer is 5 m below shoe (+/- 30 m), increase flow rate to 2300 lpm to drill the next 30m and to 3200 lpm for the rest of the section.

5.

Continue drilling ahead 24” hole to section TD +/- 450m m MDRT. TD to be adjusted to suit Casing tally and minimize landing joint stick up on rotary table.

6.

Monitor closely drilling parameters in order to minimize BHA vibrations and bit bouncing effect.

7.

Detergent will be added if required for bit and stabilizers balling prevention.

8.

At TD, pump high viscosity sweep and circulate one bottoms up or until well is clean. Before POOH, spot Hi-Vis pill and drop Totco.

9.

POOH to surface, rack back BHA and break out 24” bit. 

If overpull/tight spots observed work out string first and then back reaming with low parameters not more than 30rpm and minimum flow rate 1000 to 1500 lpm.



If bit and stabs come out balled up, clean BHA and discuss with town the following plan:

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a.

RIH back to TD and monitor hole fill.

b.

Circulate out bottoms up and spot 8 m of Hi-Vis sweep.

c.

POOH, rack back BHA and break out 24” bit.

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Conductor Stack Up Diagram

Figure 11 – 30” Conductor Stack Up Diagram (24” Section)

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5.4. 24” Section Drilling Fluids Amine Polymer mud will be used to drill this section with mud weight vary from 1.05 to 1.10 s.g. to enhance the hole condition especially thru the Namurian formation. High viscosity sweeps & Detergent will be pumped as necessary while drilling this section to avoid bit balling.

Interval Depth Mud Type

Units

24” Hole Section

meters

+/‐450

Mud Weight

Amine Polymer mud sg

1.05‐1.10

pH

9.5 ‐ 10

Plastic Viscosity Yield Point

cP

ALAP

lb/100sqft

35‐40

18/20/25

Gels 10 sec / 10min / 30min API Fluid Loss

Section TD Static Temperature

cc/30min °C

≤ 10

cc in Namurian 45

Table 9 – 24” Recommended Drilling Fluids Properties

5.5. 24” Cutting Sampling – Mud Logging Program Set of samples will be collected from surface to section TD. Two types of samples will be collected every 10 meters: 

Set-1 GRN: Washed & Dried / Unwashed / Geochemical as per requirement



Set-2 SONATRACH: Washed & Dried / Unwashed / Geochemical as per requirement

Mud Sampling: 

At the beginning of this section



Every mud change



Before every wireline job

5.6. 24” Section Electric Logging Operations No electrical logging planned for this section. 18-5/8” cased logs will be compiled with the 16” hole logging program.

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5.7. 18 ⅝” Surface Casing Operations 5.7.1.

18 ⅝” Casing String

Item

Qty

1

1

2

1

3

+‐35

Description

Size

Weight (lb/ft)

Gr ade

C onne ct ion

Centralization (To be confirmed)

Stab‐in Float Shoe

18

⅝”

87.5

K‐55

BTC

Float Shoe Casing Joint

18

⅝”

87.5

K‐55

BTC

1 NW Flexible Centralizer

Casing Joint

18

⅝”

87.5

K‐55

BTC

1 NW Flexible Centralizer ea. 3 Joints

‐

Table 10 – 18 ⅝” Casing String 5.7.2. 1.

18 ⅝” Casing Preparations

All personnel and equipment for casing run is on location: 

+-50 joints to be received at location (At least 10% contingency to be available)



Pre-assembled Stab-in float Shoe Track



Halliburton Cement Stinger with spare of O-rings.



Flexible Centralizer (5” x 18- ⅝”) for Cement Stinger.



False rotary table and C-plate (KCA provided).



Running compound and thread lock.



18-5/8” BTC circulating swedge. Casing running equipment from Weatherford TRS: Power units, Power tongs 20K,



Side door elevator 150 T and single joint elevator, 18 ⅝” casing cutter. Equipment to be checked on location by the TRS supervisors 3 days before the job starts. 2.

All casing joints should be measured and tallied. The tally should be approved by the drilling superintendent.

3.

All casing joints must be drifted. Ensure proper drift is on location (ID of casing 17.75in)

4.

Clean and visually inspect all casing threads. 5.7.3.

18 5/8” Running Procedure:

1.

Hold pre job safety meeting.

2.

Rig up Casing running equipment. 132” 350T rig bails to be used.

3.

Pickup stab in float shoe, 1 joint, and M/Up the shoe (Thread lock), fill-up with mud and test that the floating device is working ok.

4.

Install 2 Bow spring Centralizers in float shoe and 1 per each 3 stands (Final Centralizer program to be proposed by Schlumberger Cementing and reviewed and approved by CM and drilling superintendent). Company man should confirm the proper installation of the stop collars and centralizers.

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Centralization must be assured close to surface using rigid centralizers inside 30” preinstalled conductor pipe.

6.

Continue running 18 ⅝” joints filling up the string every 5 joints. Refer to Annex I for MUT requirements.

7.

+/- 2 meter of Rat Hole to be considered.

8.

Space out the Casing Landing Joint at Rig Floor level to have the minimum possible stick up.

9.

Count number of Casing remaining on the rack versus Casing Tally.

10. If hole fill is observed space out 18 ⅝” Casing according to pipe tally and availability of pup joints at the site. 11. Condition mud to required properties as per Mud Program. 5.7.4.

18 ⅝” Casing Cementing Procedure

A detailed cement procedure will be prepared and issued prior to the casing operations based on drilling conditions observed and according to the following guidelines. Objectives: 

Bring cement to surface to provide adequate structural support for the next well sections and to provide isolation to the shallow aquifers.



Minimize wait on cement (WOC) time.



Avoid losses but if losses are encountered while cementing the 18 ⅝” Casing. CBL-VDL-GR log could be run before drilling ahead the next section.

All the slurry properties have to be defined by Schlumberger cementing company and to be included in wellsite procedures. All the properties are to be confirmed through lab tests using rig samples at least 3 days before the job. Procedure: Cementing for this section will be done with a stinger (Stab –in). 1.

Perform a pre-job safety meeting.

2.

Install a false rotary table on top of 18 ⅝” LJ in preparation for running the inner string.

3.

Make up and run in hole to 5m above shoe with cement stinger (check O-rings) string (5” DP) using two DP Centralizers for 18 ⅝” casing. Check with drilling superintendent if running some HWDP is required.

4.

Break circulation prior to stab in.

5.

Stab in gently without circulation and set 5K onto shoe.

6.

R/U TIW-SES-TIW and lock 500psi above top TIW.

7.

Sting into the casing shoe and confirm circulation up the annulus.

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If full returns are seen, check if the inner annulus (between 5” DP & 18 ⅝” casing) is

filled to enable detection of leak around drill pipe stinger and proceed with the cement job. b.

If total or severe partial losses are noted while circulating, record the pressure at the

planned pumping rate. 8.

Circulate while rigging down casing running tools. Try to use the same annular velocity than during drilling.

9.

Hold a safety meeting prior to pressure testing cement lines and starting the cement job.

10. There should be enough cement on location to permit pumping 300% excess of the primary job, plus top up slurries. 11. Pump +/- 15 m3 of spacer (Fresh water 1.00sg), Mix & pump on fly +/- 130 m3 of 1.58 SG lead slurry. When the cement reach surface pump +/- 37 m3 of 1.90 SG tail slurry, under displace the inner volume of the 5” DP by 1 m3 and taken into account the follows: 

Consider to use CemNet in the slurry at 5.0 Kg/m3 in order to minimize losses. To be confirmed in the final cementing program.



All the volumes to be verified with the Cementing Program .



An excess of 200% for open hole volume is considered on the above figures (300% for Lead Slurry and 100% for Tail Slurry). TOC lead: Surface. TOC tail: 300m.



Measure slurries density with pressurized balance at the Batch Mixer.



Collect mix water and cement slurry samples

12. Check for backflow by releasing pressure and observing volume of flow-back, allowing for aeration: 

If float valve is holding, clear the drill floor and cellar area and sting out, circulate the excess of slurry. Then POOH one joint above the shoe and circulate one volume if possible.



If float does not hold, do not sting out, re-pump 4 bbls plus amount flowed back to cement tanks, leaving 1bbl inside drillpipe and bleed off again.



If Back flow still exists, pump back the same volume and over displace 0.5bbls to ensure DP is clear of cement and shut in at surface until surface sample is hard.

13. Wait on cement until surface samples are set. 14. If no cement at surface or cement drops a remedial top job will be performed with a 2” hose / spaghetti pipe (check availability at rig site during the preparation for cementing operations).

Note: Refer to Annex VI for more details about cementing job.

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5.7.1.Wellhead Operation Sequence 1.

Perform safety meeting for Wellhead operations.

2.

Cameron rep. and GRN representative to ensure all required material is in place (Wellhead section “A”, running tools and required spares).

3.

While waiting on cement, drain the 30” x 18 ⅝” annular from the cement through the drain Valve.

4.

After cement is set up, cut window on 30'' Casing above final cut depth to allow access to cut the 18 ⅝” Casing.

5.

Rough cut the 18 ⅝” Casing at 762 ± 3mm above conductor pipe and L/D the cut joint.

6.

Final cut the 30” Conductor by having 0.40 m stick up above the bottom of the Cellar and L/D the 30” Riser. Final stick up to be confirmed by Company Man. Note: The Cellar Height should be confirmed/reported to office ahead of time prior to carry out the cut. (AZSE-4 Cellar depth is 2.4 m, to be confirmed by CM on new location)

7.

Final cut and bevel the 18 ⅝” Casing by using Weatherford Cold Cutter by having 587.5±1.5 mm elevation above conductor in order to the set the detachable Base Plate on top of the 30” Casing

Figure 12 – 30” Conductor & 18 ⅝” Casing Cut

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Install the detachable Base Plate (PN 255133-32, OD 45”) over the 18- ⅝” casing and land it on the conductor ensuring it is leveled.

9.

Install Cameron 21-1/4" Casing Head Housing, (P/N 2263490-48-01) section “A” over the 18 ⅝”

stub and land it on landing base. Verify that the Sliplock connection is down.

10. If required fill up the cellar with cement up to the base plate (+/- 30 cm). 11. Split and remove the Landing Base assembly. 12. Locate the four ports on the bottom flange of the casing spool for injecting plastic packing into the P-seals. Inject Cameron Seal packing. 13. Locate the test port labeled as 9/16” AE – TEST PORT and remove the fitting. Attach test pump and inject fluid to 500psi (80 % of the 18 ⅝” Collapse pressure) 14. Once the Casing Head is properly tested, remove the four slip retaining screws from the OD of the slip bowl. This will allow the slips to drop and settle around the casing stub. 15. Tighten the (16) sixteen, 1-3/8" nuts on the bottom of the Casing Head flange in an alternating cross fashion to 740 ft/lbs. 16. Reinstall the split landing base. Tighten same.

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Figure 13 – 18 ⅝ Casing Head Housing (Section A) Note: For more detail the Cameron document included within the appendix available at Rig in hard and soft copy.

5.7.2.

20 ¾” BOP Stack Installation and Testing Procedure

1.

Held pre-job safety meeting.

2.

Using BX-165 ring gasket, make up 21 ¼” x 20 ¾” 5K psi W.P. Double stud adapter on the wellhead housing.

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3. Install spacer spool 20 ¾” 3K psi W.P x 20 ¾” 5K psi W.P.. 4. N/U 20 ¾” 5K psi W.P. BOP stack (single blind rams, single pipe rams and annular preventer). 5. Function test BOP. 6.

Make up and RIH following assembly: 18 ⅝” tester cup, 1 x 5” DP joint, pup joint, side entry valve and safety valve.

7.

Set 18 ⅝” tester cup below wellhead. Connect test pump to choke manifold 2” outlet. Align valves to pump through side outlet of drilling spool.

8.

Close upper pipe rams and test wellhead and wellhead valve to 200 / 1,100 psi (5/10 min) against upper pipe rams.

9. Remove test cup. 10. Open the housing’s annulus valve. 11. Run 20” BOP combination tool / test plug (P/N 238875-16-01-01). Orientate the tool with the “LS” seal toward the bottom. Ensure test port of tester plug is clear and open. Lower the tool down through the BOP/Riser until it lands on the load shoulder in the casing head housing. 12. Connect test pump to side entry of test assembly. 13. Pressure test BOP (as per Annex III indications): a.

Test Annular preventer to 200 psi for 5 min, and at high pressure (1,400 psi) for 10 min

b.

Test kill line check valve, choke hose connections, valve #1 of choke manifold and upper pipe rams to 200 psi for 5 min, and at high pressure (2,400 psi) for 10 min. Ensure kill line is disconnected from check valve, to verify any leaking. Downstream valve from valve #1 of choke manifold should be open, so leaking can be verified.

c.

With upper pipe rams closed. Test Outside kill line valve, outside choke line valve to 200 psi for 5 min, and 2,400 psi for 10 min.

d.

With upper pipe rams closed. Test Inside kill line valve , Inside choke line valve to 200 psi for 5 min, and at high pressure (2,400 psi).

e.

Back out test assy from test plug. Remove test assy from BOP.

f.

Connect test pump to choke manifold and pump through drilling spool. Test Blind rams to 200 psi for 5 min, and 2,400 psi for 10 min.

g.

Note: Record all tests on a chart recorder, the Daily Drilling Report and the IADC Report and need to be signed by GRN Company man.

h.

Close annulus valve, release pressure and open the rams. Retrieve combination tool.

i.

Install Wear bushing in section “A” as per Cameron procedure.

14. Close annulus valve, release pressure and open the rams. Retrieve combination tool. 15. Install 18 ⅝” wear bushing in section “A” as per Cameron procedures.

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20 ¾” BOP Stack Up Diagram

Figure 14 – 30” Conductor Stack Up Diagram (16” Section)

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6. 16” Hole Section Objectives & Overview 6.1. 16” Section Key Points 1. The objective of this interval is to safely drill a 16” vertical hole throughout the Namurian, Visean D, Visean C, Visean B, Visean A, Tournaisian, Strunian and the Famennian formation to a section TD of +/- 2,300m. The 13 3/8” casing should cover the overpressure formation expected from 2200m to 2250m. 

2.

Maximum Expected Pore Pressure at section TD is 3320psi.

Maintain good Wellbore Stability maintaining the proper mud properties while drilling the entire section. Mud engineer to check and report MW in/out every 30 min and mud viscosity every hour.

3.

Maintain good hole cleaning. Pump hi-vis pills if needed.

4.

Run and cement 13 ⅜” Casing safely to isolate possible aquifers and achieve an adequate formation integrity test to drill the next 12 ¼” phase.

6.2. 16” Section Hazards & Risks -

High probability to have partial to total losses in Tournasian formation around the Dolerite layers. Partial & total losses encountered in AZSE-21 where LCM Pills and Thixotropic Cement plug were required to cure losses. Whereas losses have been reported on Visean D in AZSE-1. Find LCM decision tree on the ANNEX VII.

-

Possible bit and stabilizer balling while drilling throughout the claystones.

-

Claystones reactivity can affect the wellbore stability due to plastic shale and or unconsolidated sands.

-

Building tendency is expected, especially in Dolerites, Strunian and Famennian formations.

-

Cavings while drilling and while performing POOH prior to Casing running operations.

-

Several tight hole, pack off tendency and stuck pipe incidents were reported in RG-5 ,RG6 AZSE-2. Especially in Dolerites. Whereas in AZSE-21; tight spots & pack off tendency observed in many intervals.

-

Low ROP also expected while drilling Dolerite layers.

-

Potential Gas migration while cementing from Visean package. (600 psi – Annulus B has been reported on AZSE-3)

Note: Refer to Risk Assessment Annex VIII to see all the preventive and mitigation actions for this phase. Refer to Annex X Offset wells for more details about field experience.

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6.3. 16” Section Drilling Operations 6.3.1.


This section is expected to be drilled in seven runs due to presence of three Dolerite layers with different thickness. So Packed BHA & Autotrak BHA will be utilized accordingly by deploying TCI bits along with packed BHA to drill dolerite layers and Autotrak V BHA for the rest of intervals.

Bit Run#

Size

1st

16"

nd

16"

2

3rd

16"

4th

16"

Model

Type

Remarks

Main - NOV PDC TUHI916S Backup - Varel R719SPDGHX

PDC

Drill from 450 to 1200m

Main - RR - NOV PDC TUHI916S Backup - Smith MDSI619HBPX PDC

PDC

Drill from 1200 to 1758m ( top of 1st Dolerite)

TCI

Drill 1st dolerite layer from 1758m to +-1827m

TCI

Continue Drill 1st dolerite layer from 1827m to 1896m

PDC

Drill from Through Strunian and Famenian untill top of 2nd Dolerite at 2053m

Main - NOV TCI T52 Back up - Varel TCI HR34DJMRS Backup - Smith TCI GF30YBODV Main - NOV TCI T52 Back up - Varel TCI HR34DJMRS Backup - Smith TCI GF30YBODV

16"

Main - Smith Si913 PDC Backup - NOV TUHI916S Backup - S mith MDSI619HBPX

6th

16"

Main - NOV TCI T52 Back up - Varel TCI HR34DJMRS Backup - NOV PDC TUHI916S

7th

16"

Main - MDSI619HBPX PDC Backup - Varel R719SPDGHX

5th

Drill 2nd dolerite layer & Famenian from 2053m to +- 2100m Drill Famenian from 2100m to 2300m Section

TCI

PDC

TD (including 3rd Dolerite)

Table 11 – 16” Recommended Bits

6.3.2.


The section will be drilled according with recommended parameters as per Table 12. WOB (Ton)

RPM

16" Packed BHA

15 – 25

90‐100

16"

10 – 15

Section

Mode

Bit

T52 or equivalent TUHI916S or RSS BHA equivalent

Flow Rate (lpm)

TFA (in2)

HSI (HP/in2)

2800‐3200 3700‐4700

0.746

2.0

100‐145 2800‐3200 3750‐4500

1,325

1.9

SPP (psi)

Table 12 – 16” Recommended Drilling Parameters

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Recommended RSS BHA

Objective of this interval is to keep the wellbore as near to vertical as possible while maintaining an optimum ROP.

16" RSS BHA #2 Item

Name

1

PDC bit

2

AutoTrak V

3

Stab ‐Mod

OD (in)/

Max OD

Bottom/

Length

Cum, Length

ID (in)

(in)

Top Connection

(m)

(m)

7 5/8" Reg Pin

0,43

0,43

2,53

2,96

3,63

6,59

3,87

10,46

0,74

11,2

1,53

12,73

0,91

13,64

1,87

15,51

5,5

21,01

28,05

49,06

1,13

50,19

137,24

187,43

10,22

197,65

18,95

216,6

1,4

218

140,4

358,4

1941,6

2300

16 9 1/2 2,48 9.524

15,65

15 7/8

3.118 4

BCPM

5

BCPM NM Sub

6

Stab String

9½ 3.118 9½ 3 7/16 9½

Sub Float

9 5/16

9½

9½

15 7/8

NM Sub ‐ Filter

9 1/2

9 5/16

Multi Activating Circulation Sub ( if available)

9 5/16

10

3 x 9‐1/2” DC

11

XO

9 1/2 3 9 1/2

15 x 8‐1/4" DC

8 1/4

09/01/2002

9 1/2

JAR

8 1/4

8 1/4

2 x 8‐1/4" DC

8 1/4

8 1/4

XO

8 1/4

8 1/4

15 x 5" HWDP

17

5" DP S‐135, 19,5 lb/ft, Premium

5 3 5 4.276

7 5/8" Reg Pin

7 5/8” Reg Box 7 5/8” Reg Pin 7 5/8” Reg Box 7 5/8" Reg Pin

6 5/8" Reg Pin

6 5/8" Reg Pin

6 5/8" Reg Pin 6 5/8" Reg Box

8 1/4

3 16

7 5/8” Reg Pin

6 5/8" Reg Box

2 ‐13/16 15

7 5/8” Reg Pin

6 5/8" Reg Box

3 14

7 5/8” Reg Box

6 5/8" Reg Box

2 ‐13/16 13

7 5/8” Reg Box

7 5/8” Reg Pin 9½

3 12

7 5/8” Reg Box

7 5/8" Reg Box

9,5 3 1/16

T2 Pin

7 5/8” Reg Box

3 9

T2 Pin

7 5/8” Reg Box

3 8

T2 Box

T2 Box

3 7

7 5/8" Reg Box

6 5/8" Reg Pin NC‐50 Box

5

5

NC‐50 Pin NC‐50 Box NC‐50 Pin NC ‐50 Box

Table 13 – 16” RSS BHA Assembly

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6.3.4. Recommended Rotary Packed BHA 16" Packed BHA #3 Item

Name

1

PDC bit

2

NBS w/float & Totco Ring

3

Shock Sub

4

9 ‐1/2 Short DC

5

Stab String

6

9 ‐1/2 DC

7

Stab String

8

9 ‐1/2 DC

9

X ‐Over

10

15 x 8 ‐1/4" DC

11

JAR

12

2 x 8 ‐1/4" DC

13

XO

14

15 x 5" HWDP

15

OD (in)/

Max OD

Bottom/

Length

Cum, Length

ID (in)

(in)

Top Connection

(m)

(m)

7 5/8" Reg Pin

0,43

0,43

2,17

2,6

4,44

7,04

4,57

11,61

1,53

13,14

9,23

22,37

1,53

23,9

9,23

33,13

1,13

34,26

137,24

171,5

10,22

181,72

18,95

200,67

1,4

202,07

140,4

342,47

1957,53

2300

16 9½ 3 9½ 3 9½ 3 9½ 3 9½ 3 9½ 3 9½ 3 9 1/2 3 8 1/4 2‐13/16 8 1/4 3 8 1/4 2‐13/16 8 1/4 3

15 7/8

9½

9½

15 7/8

9½

15 7/8

9½

9 1/2

8 1/4

8 1/4

8 1/4

8 1/4

5 3

5" DP S‐135,

5

19,5 lb/ft, Premium

4.276

5

5

7 5/8" Reg Box 7 5/8" Reg Box 7 5/8" Reg Pin 7 5/8" Reg Box 7 5/8" Reg Box 7 5/8” Reg Box 7 5/8” Reg Pin 7 5/8” Reg Box 7 5/8" Reg Box 7 5/8” Reg Box 7 5/8” Reg Pin 7 5/8” Reg Box 7 5/8" Reg Box 7 5/8” Reg Box 7 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC ‐50 Box

Table 14 –16” Rotary BHA Assembly WBJ: 35 Ton 1

Note : Actual Hydraulic Simulation will be carried out during the operations. 2

Note : The dimensions of all tools and BHA components must be checked prior to RIH.

6.3.5.


1.

Pick up enough 5” DP (+/-1700m .) to drill down to section TD.

2.

P/U, M/U and RIH 16” NOV TUHI916S PDC Bit with 9 ½” AutoTrak V. 

Pay especial attention to BHA handling. Incident occurred in KL-27 when Rig tong damaged Baker AutoTrak sub.

3.

Perform surface function test on the AutoTrak V system. Record and report on DDR parameters and weight below jar.

4.

Continued to RIH to 18 ⅝” float shoe.

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5.

Drill out shoe with low parameters and clean out rat hole and drill 3 meters of new formation.

6.

Circulate hole clean until MW in/out is equal and verify shakers are clean of any shoe track debris. 



Verify shakers are clean of any shoe track debris. Confirm MW in/out is equal.

Pull back into the Casing Shoe and conduct the FIT at 18- ⅝” Casing shoe according to GRN procedures using the previous MW of 1.10 sg. Do not excess the FIT gradient of 1.86 sg.

Open hole / Shoe Depth (m) Casing size (in) 16” ‐ 18‐⅝”

450

FIT value (sg)

Mud Weight (ppg)

Surface pressure (psi)

Kick Tolerance (bbls)

1.86

1,1

+/‐490 psi

93 bbls

Table 15 – 16” Planned FIT 7.

Record pressures versus pumped/returned volumes and inform Drilling Superintendent and Senior Drilling Engineer. Report values on DDR.

8.

Displace the hole with 1.35 sg (Avapolyoil mud) and condition mud to ensure consistent density and properties.

9.

Continue drilling ahead with AutoTrak BHA to section through Namurian, Visean D, Visean C, and Visean B to +- 1200mMD, by this depth the maximum working hours of the drilling Jar (see Annex XI) and AutoTrak will be exceeded. However in case of the +/- 150 circulation hours on the drilling Jar reached before this depth, plan to perform the trip accordingly. 

Limit drilling parameters (40-60rpm) until last stabilizer is below Casing Shoe.



Pump 5m3 of Supersweep pill every 2 stands. If needed pump every stand.

10. Pump +/- 6m3 of Supersweep Pill, circulated hole clean and POOH to change out the drilling Jar & AutoTrak. 11. P/U, M/U and RIH re-runnable 16” NOV TUHI916S PDC Bit with 9 ½” AutoTrak BHA. Record weight below jar. Perform surface function test on the Auto Track system and report the results on the DDR. 3

12. At TD, pump Super Sweep pill (+/- 10 m ) and circulate one bottoms up or until well is clean. Flow check well. 13. Continue RIH to bottom and resume drilling 16” hole to section with AutoTrak BHA through Visean B and Tournasian formations until reach the top of the first Dolerite layer (estimated +/-138 m thick): 

Monitor and control vibrations while drilling.



Optimize the drilling parameters between WOB and RPM to achieve reasonable ROP.



3

Hi Vis Pills and SuperSweep Pills (+/- 5 m each) to be pumped whenever it is necessary.

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

Flow rate to be 2800-3200lpm.



Slow the drilling parameters while approaching the top of the dolerite to avoid damaging the PDC Cutters and once the Top of Dolerite is confirmed optimize the drilling parameters again.



In case of any indication of caving the mud weight will be increased accordingly and to be advised by the office.



In case of losses; which might be come across +- 50 m above the dolerite; follow the LCM decision Tree.

14. Once the dolerite is encountered, reduce bit RPM to 80-90 and continue drilling ahead. Monitor parameters and minimize vibrations as much as possible. If very low ROP is observed, consult with Drilling superintendent or the Operation drilling engineer for a possible Bit trip. 15. If Bit trip is required at the Dolerite, POOH to surface, change out the Bit and RIH back to bottom. New Bit to be used: NOV T52. 

Alternative bit is MZ616BPX (Stingerblade). To be confirmed on due time from the Operation Drilling Engineer. The intention of this bit is to drill thru +/-138 m of the Dolerite and Strunian formation.

16. Continue drilling ahead to bottom of dolerite (1,896m TVD RT.). Confirm completely out of the Dolerite with WSG. If necessary, drill ahead 10 to 20m below Dolerite. 

Note: in RG-08; 124 m of Dolerite has been drilled with one Bit (T52) with an average ROP on bottom of 1.56 m/hrs. However two TCI bits were required to drill 104 m of Dolerite in AZSE-21.



Losses has encountered in AZSE-21 started at 1,770 m.

17. POOH to surface, change out the Bit and RIH back to bottom. New Bit to be used: Smith PDC MDSI619HBPX or Smith Si913 PDC, with the RSS BHA. 5.

Continue drilling ahead thru Strunian and Famenian formation (+/- 30/40 m of Dolerite) to section TD at +-2,300m. A criterion is to set the 13 3/8” casing below the overpressure formation expected from 2200m to 2250m. 

Note: If losses encountered while drilling this section. Refer to Annex VII Losses decision Tree.



Try to optimize the trips to surface to test the BOP´s every 21 days maximum. nd

18. If a Bit trip is required at the 2 layer of Dolerite, POOH to change out the Bit and RIH back to bottom. New Bit to be used is NOV T52, with Packed BHA. 

Once confirm completely out of the Dolerite with WSG. If necessary, drill ahead 10 to 20m below Dolerite, POOH to Pick up a PDC bit and RSS BHA to drill across rd

Famenian, including a 3 layer of Dolerite until section TD

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19. Detergent will be added if required for Bit / Stabilizers Balling. 20. At TD, pump high viscosity Pill, Supersweep pill and circulate one bottoms up or until well is clean. Flow check well. Depending on hole conditions perform a wiper trip to shoe before POOH to surface and rack back BHA. 21. If overpull/tight spots observed work out string first and then back reaming with low parameters not more than 30rpm and minimum flow rate 1,000 to 1,500 lpm. 22. Rig up wire line equipment and perform Wireline logs run as per GRN well site geologist indications 23. Rig down wire line equipment. 24. Prepare to run 13 3/8” Casing.

6.4. 16” Section Drilling Fluids 6.4.1.

Recommended Drilling Fluids Rheology Parameters

Consider starting the section with a 1.35 sg mud weight (Avapolyoil system) based on fluid formulation. The centrifuges have to maintain the drilled solids below 5%. Shall it become necessary to adjust the mud weight upwards due to hole problems, circulate the new weightier mud around prior to drilling ahead.

Interval Depth

Units

16” Hole Section

meters

=+‐1850

Mud Type Mud Weight

AVAPOLYOIL / SOLTEX / POLYMER sg

1.35

pH

9.5 ‐ 10

Plastic Viscosity Yield Point Gels 10 sec / 10min / 30min API Fluid Loss


cP

ALAP

lb/100sqft

30‐35

12/15/20

cc/30min °C

≤3

cc

90

Table 16 – 16” Recommended Drilling Fluids Properties

6.5. 16” Cutting Sampling – Mud Logging Program Set of samples will be collected from the beginning of 16” drilling phase down to top section TD at 2300 m. Two sets of two types of samples will be collected every 10 meters. 

Set-1 GRN: Washed and dried (Dry) / Unwashed (Wet)



Set-2 SONATRACH: Washed and dried (Dry) / Unwashed (Wet)

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Mud Sampling: Refer to GEOLOGICAL OPS PROGRAM.



6.6. 16” Section Electric Logging Operations Open Hole The following log will be run after reaching 16” section TD. Run 1A. SGT-DSLTBHC-EMS (Optional: GPIT)



Cased Hole The following logs will be run in 18 ⅝” casing: Run 1B: CBL-VDL-CCL- SGT



6.7. 13 ⅜” Casing Operations 6.7.1.

13 ⅜” Casing String

Item

Qty

1

1

2

1

3

Description

Size

Weight (lb/ft)

Grade

Connection

Centralization (To be confirmed)

Float Shoe

13 ‐⅜”

72

Q ‐125

Vam Top

‐


13 ‐⅜”

72

Q ‐125

Vam Top


1

Casing Intermediate Joint

13 ‐⅜”

72

Q ‐125

Vam Top


4

1

Float Collar

13 ‐⅜”

72

Q ‐125

Vam Top

5

1

Float Collar Casing Joint

13 ‐⅜”

72

Q ‐125

Vam Top


Vam Top

1 NW Flexible Centralizer ea. 3 Joints

6

+‐167

Casi ng Joint

13 ‐⅜”

72

Q ‐125

Table 17 – 13 ⅜” Casing String 6.7.2. 1.

13 ⅜” Casing Preparations

All personnel and equipment for casing run is on location: 

+/- 185 joints of 13 ⅜” Vam Top casing to be sent to location (10% contingency).



Pre-assembled Float shoe & Float Collar joints.



Verify connection is Vam Top



Bow spring centralizers and stop collars.



Rigid centralizers and stop collars.



12 ¼” special drift bar (API 5CT) provided by Weatherford.



13 ⅜ circulating head “swedge” with quick connection or Vam Top connection to NC50 (provided by Schlumberger COPS).

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The cementing head has a BTC connection on the bottom. Ensure the proper crossover is on location (provided by Schlumberger). Min 5K psi is acceptable



Running compound (API Modified or BESTOLIFE dopes) and thread lock



All Casing running equipment: Power units, Power tongs 16K, Side door elevator 350 T, JAM units, single joint elevator, Spider elevator 350T, 18 ⅝” & 13 ⅜” Casing cutters.



“La Fleur” circulating tool and required Bails (180” – 350 T).



Cement products availability. There should be enough cement/blend/additives on location to pump a 50% excess over the theoretical hole volume.

2.

All casing joints should be measured and tallied prior reaching section TD. The tally should be approved by the Drilling Superintendent.

3.

All casing joints must be drifted (special drift to be used).

4.

Clean and visually inspect all casing threads. Confirm with Drilling Office if an inspection company is required.

5.

Make sure that the 18 ⅝” wear bushing is retrieved. Install 2 centralizers in float shoe and intermediate joints and 1 every three casing joints (Final Centralizer Program to be proposed by Cementing Company, reviewed and approved by Company Man, Drilling Operation Engineer and Drilling Superintendent). 

Two stop collar per centralizer should be installed, above and below of the centralizer and never one in the middle with enough space to allow the bow centralizer expand with full compression. Company man should confirm the proper installation of the stop collars and centralizers.



Centralization must be assured close to surface using rigid centralizers inside 18 5/8” casing. Stop collar to be installed just above and below rigid centralizer avoiding any movement.

6.7.3.

13 ⅜” Casing Running Procedure

1.

Hold pre job safety meeting.

2.

Rig up casing running equipment. Bails to be used: 132” 350T rig bails.

3.

P/U float shoe joint, 2 intermediate joints and collar joint (thread lock); fill-up with mud and test that the floating device is working properly.

4.

Continue RIH 13 ⅜” casing and tag bottom (if it is feasible). Pick up +/- 1 m of bottom. 

+/- 1 meters of rat hole to be considered.



Count number of casing joints remaining on the rack versus casing tally.



Space out the casing landing joint at rig floor level to have minimum stick up.



Make sure that coupling of the last joint to be placed below the Casing Head Housing (if it is feasible). Otherwise the coupling should be above the cut level.

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If hole fill is observed, space out the 13 ⅜” casing according to casing tally and availability of pup joints at the site.

5.

Condition mud to required properties as per Mud / Cementing Program. 6.7.4.

13 ⅜” Casing Cementing Procedure


Bring cement 100 m inside 18 ⅝” casing to provide to ensure proper annulus isolation.



Avoid losses. Note: 13 ⅜ ” casing cement job will be logged (CBL-VDL-CCL) after drilling 12 ¼” section. If losses are encountered, this log could be run immediately after cement job.



All the slurry properties have to be defined by Cementing Company and have to be included in wellsite procedures.



All the properties should be confirmed through lab tests using Rig samples at least 3 days before the job.

Procedure: 1.

Hold a safety meeting prior to pressure test cementing lines and start the cement job.

2.

Check cementing head connection, pressure rating and certification once it is received on location.

3.

Calculate cement volume requirement from caliper log with 25% excess in open hole (to be confirmed). There should be enough cement on location to allow pumping 25% excess of the open hole. Agree on final volume figures with HMD Drilling Office.

4.

3

The 13 ⅜” casing will be cemented in one stage with +/- 60m of 1.60sg Litecrete lead slurry 3

followed by +/- 42 m of 1.90 sg gas tight Flexstone tail slurry, Top of Tail: +/- 1,516m , 100m above Tournasian formation, (25% excess included in OH over theoretical volume just as a reference) 

Spacer and slurries designed in plug flow pattern at 800 lpm. Continue to reciprocate while pumping/displacement cement.



Highest ECD (estimated to be 1.74 sg) will be observed at end of displacement and should be checked against the he FIT/LOT obtained.



Monitor returns during the job.



Critical periods of both slurries must be misaligned. To be verified by the cement lab test.



In case of surface holding pressure is required while WOC; it will be officially conveyed from HMD to the Rig site.

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5.

Displace cement with mud and bump plug.

6.

If plug is not bumped inform Superintendent immediately. Do not over displace more than half shoe track volume. Compare total strokes versus calculated strokes after the efficiency test.

Note that in case of a 3 joints shoe track the volume of the same is 20.40 bbl. 7.

If plug was bumped, pressure test Casing (with green cement) with maximum pressure of 5000psi. (As per indicated in Annex III). If plug was not bumped the Casing will be tested at a later stage. Note: Pressure test is limited to 5000psi due to the limitation of 13 3/8” cement head of 5Kpsi W.P..

8.

Check for backflow by releasing pressure and observing volume of flow-back, allowing for aeration.

9.

Wait on cement 500 lbf/100 sq.ft SGS is achieved to compensate for hydrostatic loss and prevent gas migration. Time to be confirmed from HMD. And Cement sample to be put in oven at downhole temperature. Note: Refer to Annex VI for more details about cementing job. 6.7.5.

Wellhead Operation Sequence

1.

Perform pre-job safety meeting for wellhead installation operation.

2.

Drain the BOP and Well Head Housing through its side outlet.

3.

Lift 20 ¾” BOP.

4.

Clean the Casing Head Housing. Make sure it is free from cement.

5.

Remove both latch screws, one on each side of hanger .

6.

Remove one Screw on EACH handle.

7.

Place hanger around casing. Set it on boards overhead.

8.

Reposition

handles

and

install

screws.

TIGHTEN

SECURELY (tapered screw heads installed in the handles will pull the halves to proper position at top). 9.

Replace both latch screws. Tighten until the gap is closed at the bottom. NEVER set this hanger without BOTH LATCHES in place securely.

10. Verify that packing is not compressed (i.e., does not extend beyond O.D. of both top and retainer rings). Note: It is very important that the large caps crews that retain packoff assembly only be tightened enough to remove the slack. PACKING MUST NOT be compressed prior to slacking off casing weight onto hanger. Groupement Reggane



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11. Remove the four slip retainer screws on OD of slip bowl. These screws hold slips in retracted position in bowl. Slips WILL NOT set unless screws are removed BEFORE hanger is placed in head. 12. Pull tension on the casing to the desired hanging weight (minimum 15,000 lbs to energize the pack-off). 13. Remove the support boards and install the hanger into the Casing Head/Spool bowl. A cat line may be necessary to center casing with respect to bowl preparation. 14. Slack off on the casing. A sharp decrease on the weight indicator will signify that the Hanger has taken weight and is supporting the casing. 15. Remove handles from hanger. 16. Check cap-screws in top of hanger and tighten if possible (100 ft/lb recommended). 17. Close well head housing side outlet. 18. Rough cut the 13 ⅜” casing approximately 24" above the top of the casing head. 19. Move the excess casing and BOP out of the way. 20. Final cut the casing at 6.75" ± ⅛" [171.5 mm ±3] above the top of the casing head. Place a 3/8" x 3/16" bevel on the Casing stub and remove all burrs and sharp edges. 21. Fill the void above the Casing Hanger with clean oil to the top of the Casing Head.

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Figure 15 –13 ⅜ Casing Cut and Casing Head Housing

22. Install BX-165 ring gasket into the ring groove of the casing head housing. 23. Lift and suspend the spool over the casing head housing, ensuring it is level. 24. Carefully lower the spool until it lands on the ring gasket. Install and tighten the studs and nuts of the flange. 25. Injected Cameron seal packing and pressure test the P-seals to 500 / 2,300psi (80 % of the 13 ⅜” collapse pressure). 26. Install a test pump to the port for testing the wellhead body/connection (test port #6 refer to Cameron Manual) and inject test fluid to 2,300 psi (80 % of the 13 ⅜” collapse pressure).

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Figure 16 – 13 ⅝ Casing Spool Note: For Note: For more detail the Cameron document included within the appendix available at Rig in hard and soft copy. 6.7.6.

13 ⅝” BOP Stack Installation and Testing Procedure

Note: Follow the pressure values presented in the table 31. Refer to GRN BOP´s testing procedures: PS-0000-0583-002-E-00 1.


2.

Install spare BX-159 Ring gasket.

3.

N/U 13 ⅝” 10k psi w.p BOP Stack (Single Rams, double Rams, and Annular Preventer) and Bell Nipple. And perform fully function test.

4. M/U: 13 ⅜” Cup Tester, 1x 5” DP joint with port, pup joint, side entry sub and safety valve. 5.

RIH and Set 13 ⅜” Test Cup below Well Head with test assy. Connect test pump to choke manifold 2” outlet.

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Close upper Pipe Rams, open 9/16” AE autoclave tests port #5 and test wellhead body, pseals (from above) and wellhead SOV to 200 / 6700psi (5/10 min) against upper Pipe Rams. Monitor for signs of leakage at port #5. Re-install fitting on port #5 after test.

7.

Test Annular Preventer to 200 / 3500psi (5/10min).

8.

Remove Test Cup

9.

Run 13 ⅝” BOP Combination Tool / Test plug (P/N 238875-17-01-01). Orientate the Tool with the “LS” seal toward the bottom. Lower the Tool down through the BOP/Riser until it lands on the load shoulder in the Casing Head Spool. Ensure test port of Tester Plug / drill pipe is clear and open. Open the SOV to observe any potential leaks.

10. Connect test pump to side side entry of test assy. 11. Pressure Pr essure Test BOP (as per Annex III indications): indicati ons): a.

Test kill line check valve, choke choke hose connections, connections, valve valve #1 of choke choke manifold manifold and upper Pipe Rams to 200 psi for 5 min, and at high pressure (6700psi) for 10 min. Ensure kill line is disconnected from check valve, to verify any leaking. Downstream valve from valve #1 of choke manifold should be open, so leaking can be verified.

b.

With upper Pipe Rams closed. closed. Test Outside Outside kill line valve, valve, outside choke choke line valve to 200 psi for 5 min, and 6700psi for 10 min.

c.

With upper upper Pipe Rams Rams closed. Test Inside kill line valve, valve, inside choke line valve to 200 psi for 5 min, and at high pressure (6700psi).

d.

Test lower Pipe Rams to 200 psi for 5 min and 6700psi for 10 min.

e.

Back out test assy from Test Test Plug. Remove test assy from BOP. BOP.

f.

Connect test pump to choke manifold and pump through Drilling Spool. Test Blind rams to 200 psi for 5 min, and 6700psi for 10 min. *Record all tests on a chart recorder, Daily Drilling Report and IADC Report. Note: 6700psi based on a “displacement to gas scenario” plus a kill margin)

12. Close annulus valve, release pressure and open the rams. Retrieve combination tool. 13. Install Wear bushing in section “B” as per Cameron procedure.

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13 ⅝”BOP Stack Up Diagram

Figure 17 – 12 ¼” Section BOP Stack Diagram

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7. 12 ¼” Hole Section Objectives & Overview 7.1.

12 ¼” Section Key Points

1.

The objective of the 12 ¼” section is to drill through the Famenian, Frasnian, Givetian, Couvinian, Emsian formation and to set the 9-5/8” Casing inside a competent formation in Muraille de Chine formation. Planned Section TD is +/- 3,630 mMD.

2.

Control shocks and vibrations.

3.

TD section target tolerance is 50m

4.

The Early Kick Detection system (EKD) must be rigged up/tested prior to drill out the 13-3/8” Shoe and to be activated by +/-3100 mMD.

5.

Maintain the required MW to prevent hole instability.

6.

Properly condition the hole for Wireline and Casing run.

7.2. 12 ¼” Section Hazards & Risks 1.

Wellbore stability is an issue during the drilling of this interval, (up to 70-80% of cavings reported on offset wells), and t his could be aggravated by using insufficient mud weight.

2.

Well control can be an issue, due to an abnormal the pore pressure gradient on the Couvinian and Emsian. It is imperative to mention that a Kick has encountered in AZSE-3 in Emsian formation.

3.

Vibrations and bit bouncing.

4.

Refer to Annex VIII Risk Assessment to see all the preventive and mitigation actions for this phase.

5.

Refer to Annex IX Offset wells information for more details about field experience.

7.3. 12 ¼” Section Drilling Operations 7.3.1.


The section will be drilled using a PDC Bit including the drill-out of the cement, Casing shoe and 3 meters of new formation to perform the FIT. st

Bit

1 run Primary

12‐¼”

SMITH PDC MDSIZ619

Back‐up #1

Back‐up #2

Back‐up #3

NOV PDC SKH816M

Smith PDC MDSiZ716LBPX

Varel PDC R716PDGXU

Table 18 – 12 ¼” Recommended Bits

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Section

Mode

12 1/4"

RSS BHA

WOB (Ton)

Bit

PDC MDSIZ619 10 – 20

RPM

Flow Rate (lpm)

SPP (psi)

100‐170 2100‐2700 3750‐5300

TFA (in2)

HSI (HP/in2)

2,227 (6x22/32")

0.5

Table 19 – 12 ¼” Recommended Drilling Parameters 7.3.3.

Recommended BHA

12 1/4" RSS BHA #4 Item

Name

1

PDC bit

2

AutoTrak V

3

MWD‐Stab ‐Mod

4

BCPM

5

BCPM NM Sub

7

Stab String

8

Sub Float

9

NM Sub ‐ Filter

11

XO

12

15 x 8 ‐1/4" DC

13

JAR

14

2 x 8 ‐1/4" DC

15

XO

16

15 x 5" HWDP

17

" DP S‐135, 19,5 lb/ft, Premiu

OD (in)/

Max OD

Bottom/

Length

Cum, Length

ID (in)

(in)

Top Connection

(m)

(m)

6 5/8" Reg Pin

0,28

0,28

2,53

2,81

1,81

4,62

3,67

8,29

0,75

9,04

1,77

10,81

0,91

11,72

1,87

13,59

0,99

14,58

137,24

151,82

10,2

162,02

18,65

180,67

1,1

181,77

141,3

323,07

3306,93

3630

12 1/4 9 1/2 2 1/2 9 1/2 3 1/8 9½ 3 9½ 3 7/16 9 1/2 3 9 1/2 3 9 1/2 3 8 1/4 2 3/4 8 1/4 2 7/8 8 2 7/8 8 1/4 2 7/8 8 1/4 2 7/8 5 3 5 4 1/4

11.867

12 1/8

9½

9½

12 1/8

9 5/16

9 5/16

8 1/4

8 1/4

8

8 1/4

8 1/4

5

5

6 5/8" Reg Box T2 Box T2 Pin T2 Box T2 Pin T2 Box T2 Pin T2 Box 7 5/8" Reg Pin 7 5/8" Reg Box 7 5/8" Reg Pin 7 5/8" Reg Box 7 5/8" Reg Pin 7 5/8" Reg Box 7 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin 6 5/8" Reg Box 6 5/8" Reg Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box

Table 20 – 12 ¼” RSS BHA Assembly WBJ: 31 Ton. 1

Note : Actual Hydraulic Simulation will be carried out during the operations with actual Mud properties/rheology. 2


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1.

Pick up enough 5” DP to drill down to section TD (3630m TVD RT).

2.

P/U, M/U and RIH NOV SKH816M PDC Bit with 9 ½” AutoTrak V BHA. Record weight below jar. Be extremely careful when handling smart tools at the Rig floor.

3.

Perform surface function test on the Auto Track system and report the results on the DDR.

4.

RIH w/ BHA and tag cement. Record the depth where cement was tagged on IADC report and DDR

5.

Drill out shoe track, clean rat hole and Circulated hole clean. (2 < WOB < 6 during drill out).

6.

Performed Shoe Bond Test.

7.

Drill 3 meters of new formation, circulated hole clean and until having homogeneous MW 1.40sg in/out.

8.

Pull back into the Casing Shoe and conduct FIT to 2.0sg at 13-3/8” Casing shoe using 1.40 s mud. according to GRN procedures.( Detailed procedure will be sent on due date)

9.

Record pressures versus pumped/returned volume and inform Drilling Superintendent and Senior Engineer. Report values on DDR.

Open hole / Expected FIT Shoe Depth (m) Casing size (in) value (sg) 12‐1/4” ‐ 13‐3/8”

2300

Mud Weight (ppg)


Kick Tolerance (bbls)

1,40

1970

110 bbls using 1.8 s.g

2.0

Table 21 – 12 ¼” FIT 1

Note : Kick Tolerance has been calculated based on assumed FIT with EMW of 2.0 sg and MW of 1.80s.g. Therefore the KT will be re-calculated in case FIT of 2.0sg is not achieved. 2

Note : In case the FIT of 2.0sg EMW is not achieved the contingency plan (set 9 5/8” Casing before entering Emsian formation and finish the well in 6” hole) should be triggered and a separate program or an amendment of this document should be issued and delivered.

10. Drill ahead with AutoTrak V BHA to +/- 2,800 mMD thru the Famenian formation. a.

By this depth +/- 2,800 mMD; the maximum working hours of the drilling Jar (+/- 200 hours) and AutoTrak will be exceeded. However in case of the +/- 200 circulation hours on the drilling Jar reached before this depth. Plan to perform the trip accordingly.

b.

Mud weight at 2700m should be 1.45sg.

11. Pump +/- 6m of Supersweep Pill, circulated hole clean and POOH to change out the drilling Jar & AutoTrak.

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12. P/U, M/U and Re-run 12 ¼” NOV SKH816M PDC Bit with 9 ½” AutoTrak V BHA. Record weight below jar. Perform surface function test on the AutoTrak system and report the results on the DDR. 13. Continue RIH to bottom and resume drilling thru the Famenian and Frasnian formations a.

By this depth +/- 3,400 mMD; the maximum working hours of the drilling Jar (+/- 200 hours) and AutoTrak will be exceeded. However in case of the +/- 200 circulation hours on the drilling Jar reached before this depth. Plan to perform the trip accordingly.

b.


c.


d.


e.


14. Continue RIH to bottom and resume drilling 12.¼” hole to section TD at +/-3,630m MD. This depth is based on (+/-10 to 20m) into the Muraille de Chine formation (Competent Shale). Geologist to immediately communicate to DSV once entered in M. de Chine.

Drilling notes:  

Increase drilling parameters when the stabilizer is below Casing Shoe. Monitor and control vibrations while drilling. The Drillers display must have the proper alarms, and Mud Logger will communicate to Driller and Company Man if vibration appears.






When POOH: If more than 10t drag is observed for more than 10m, immediately M/U the TDS and pump out of the hole the full stand, then try to test on elevators. If back reaming is required low rpm to be used. Flow rate to be used: between 2200-2700 lpm.



Try to optimize the trips to surface to test the BOP´s every 21 days maximum.



In AZSE-21; had to pump out the hole in all the trips.



15. At TD, pump high viscosity Pill, SuperSweep Pill and circulate hole clean. 16. POOH and rack back BHA.

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7.4. 12 ¼” Section Drilling Fluids 7.4.1.




This section will be drilled with a range of MW from 1.4sg to 1.8sg MW to section T.D.



Shall it become necessary to adjust the mud weight due to hole problems, circulate the new mud weight around prior to drilling ahead.

Interval Depth

Units

12 1/4” Hole Section

meters

+/‐1330

Mud Type

AVAPOLYOIL / SOLTEX / POLYMER

Mud Weight

sg

1,40 ‐ 1,80

pH

9.5 ‐ 10

Plastic Viscosity Yield Point

cP

ALAP

lb/100sqft

20‐25

15/20/30

Gels 10 sec / 10min / 30min API Fluid Loss

cc/30min


°C

≤3

cc

135

Table 22 – 12 ¼” Recommended Drilling Fluids Parameters

7.5. 12 ¼” Cutting Sampling – Mud Logging Program Set of samples will be collected from the beginning of 12 ¼” drilling phase down to section TD. Two sets of two types of samples will be collected every 10 meters. 

Set-1 GRN: Washed and dried (Dry) / Unwashed (Wet)




Mud Sampling: 

REFER TO GEOLOGICAL OPS PROGRAM

7.6. 12 ¼” Section Wireline Logging Operations Open Hole The following logs will be run after reaching 12 ¼” section TD 

Run 1A: SGT-DSLTBHC-EMS (Optional: GPIT)

Cased Hole The following logs will be run in 13 ⅜” Casing: 

Run 2B: SGT-CBL-VDL-CCL

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9 ⅝” Casing Operations

7.7. Item

Qty

1

1

Description Float Shoe

Size 9

Weight (lb/ft)

Grade

Connection

53.5

P‐110 HC

Vam Top

⅝”

Centralization ‐


9

⅝”

53.5

P‐110 HC

Vam Top


2

1

3

1


9 ⅝”

53.5

P‐110 HC

Vam Top


4

1


9 ⅝”

53.5

P‐110 HC

Vam Top


5

1

Float Collar

9

⅝”

53.5

P‐110 HC

Vam Top

6

1


9

⅝”

53.5

P‐110 HC

Vam Top


7

+/‐50

8

+/‐215

Casing Joint HC

9

⅝”

Cas ing Joint

9

⅝”

Made up on pin

53.5

P‐110 HC

Vam Top

1 NW Flexible Centralizer every. 3 Joints.

5 3.5

P‐110

Vam Top

1 Rigid Positive Centralizer for the last 2 Joints

Table 23 – 9 ⅝” Casing String

NB 1:9-5/8” Casing High Collapse will be used from 3630 m to 2900 m. NB 2: The centralizing position shall be verified based on the caliper log. NB 3: 9 ⅝ ” centralizer to be installed close to surface to enhance the casing centralization in line with Wellhead and Rotary Table. NB 4: 9-5/8” ,53.5#, P-110, New Vam connection might be used subject to availability of Vam Top connection in due date of the job

7.7.1.

9 ⅝” Casing Preparation

Prior to run 9 ⅝” casing; ensure all required equipment and accessories are available on site and ready to be used: 

+55 HC plus +-240 joints to be received at location (at least 10% contingency to be received)



Different length of 9 ⅝” Pup joints..



Float Collar, float shoe. Verify connection is Vam Top if not sent to the Rig preassembled.

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

Bow spring Centralizers and stop collars.



9-5/8” Reamer Shoe & rotating Centralizers as back-up plan.



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9 ⅝ Circulating Head “Swedge” with Quick Connection or Vam top connection to NC50 or 2” Weco (provided by Schlumberger).



The cementing head has a BTC connection on the bottom. Ensure the proper crossover is on location (provided by Schlumberger).



Running compound and thread lock. Ensure running compound is compatible with Vam Top connections (API modified as an example).



All Casing running equipment: Jam Unit, Power units, Power tongs 16K, Side door elevator 350 T, single joint elevator, Spider elevator 350T, 13 ⅜” & 9 ⅝ Casing cutter.



“La Fleur” circulating tool and required Bails (180” – 350 T).



All cementing products required. There should be enough cement/blend/additives on location to pump a 25% excess over the theoretical hole volume.

1.

Clean and visually inspect all Casing threads.

2.

All Casing must be drifted, measured, tallied and approved by the drilling superintendent. Note: Consider all the different possibilities available to reach a convenient stick up at the rotary table (XOs, landing joints, pup joints and XOs landing joint).

3.

Shoe track joints shall be thread locked.

4.

Pump mud through Shoe track to make sure it is not plugged before continuing to run the Casing.

5.

Verify the Mud Pump efficiency and Cementing pumping unit need to be pressure tested offline and ready for the cementing Job.

6.

Make sure that the 13 5/8” Wear bushing is retrieved.

7.

Install 9-5/8” Casing rams in BOP. Pressure test same as per GRN procedure.

7.7.2.

9 ⅝” Casing Running Procedure

1.

Hold pre job safety meeting

2.

Rig up Casing running equipment, including 180” Bails and circulating tool.

3.

P/U Float Shoe Joint, two intermediate joints, and Collar Joint (Thread lock), fill-up with mud and test that the Floating device is working properly (Three joints between shoe and float collar)

4.

Centralization must be assured close to surface using Rigid Centralizers inside 13 ⅜” Casing.

5.

Continue RIH 9 ⅝” casing with controlled speed, avoiding losses induction, and tag bottom (if it is feasible). 

+/- 1 meters of rat hole to be considered.



All connections to be recorded in JAM unit.

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

Use fill up tool to fill up the casing while running in hole.



Count number of casing remaining on the rack versus casing tally.



Space out the casing landing joint at rig floor level to have minimum stick up.



Make sure that no casing coupling is across the casing head housing.

If hole fill is observed, space out 9 ⅝” casing according to pipe tally and availability of pup joints at the site will be considered.

7.

Condition mud to required properties as per Cementing Program. 7.7.3.

9 ⅝” Casing Cementing Preparation


Bring cement to +/- 100 m above 13 ⅜” shoe (estimated TOC: 2200m mMD) to ensure proper annulus isolation.



Minimize wait on cement (WOC) time.



Avoid losses. Note: 9 ⅝ ” cement job will be logged (CBL-VDL-GR) after drilling 8 ½” section. If losses are encountered, this log could be run immediately after cement job.



All the slurry properties have to be defined by Cementing Company and to be included in wellsite procedures.



Ensure that final batch tests have been received from Cementing Company confirming thickening times and slurry properties by the assigned GRN representative.

7.7.4.

9 ⅝” Casing Cementing Procedure

1.

Hold a safety meeting prior to pressure test cementing lines and start the cement job.

2.

Check Cementing head connection, pressure rating and certification once it is received on location. 7.5Kpsi Cementing head is required.

3.

Re-Calculate cement volume requirement from caliper (volume to be confirmed by the total fluids engineer and/or operations engineer).

4.

The Casing will be cemented with two slurries. Lead 1.95sg IsoBlok G+S slurry and 2.10sg Flexstone Cement tail slurry. Tail slurry TOC: +/- 2900m. 3



+/- 12 m of 1.90sg Mudpush (spacer) to be pumped.



Estimated volume of Lead: 25 m3



Estimated volume of Tail: 28 m3.



25% excess included over theoretical OH volume only as a reference.



Spacer and slurries designed in plug flow pattern at 3 to 5 bpm. Continue to reciprocate while pumping/displacement cement.

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Highest ECD will be observed at end of displacement and should be checked against the FIT/LOT obtained.



5.

Monitor returns during the job.

Displace cement and bump plug with 500psi over FCP. 

If plug is not bumped inform Superintendent immediately. Do not over displace more than half shoe track volume. Compare total strokes versus calculated strokes after the efficiency test.


Check for backflow by releasing pressure and observing volume of flow-back, allowing for aeration.

7.

Switch back to the cementing unit and perform green casing pressure test to 5200psi.

8.

Wait on cement 500 lbf/100 sq.ft SGS is achieved to compensate for hydrostatic loss and prevent gas migration. Time to be confirmed from HMD. Two cement samples to be put in the oven at downhole temperature (WL log temp).

Note: Refer to Annex VI for more details about cementing job.

7.7.5.

Wellhead Operations Sequence

1.

Hold pre-job safety meeting for well head operations.

2.

Drain flow line and BOP.

3.

Remove flow line to enable picking up stack and spacer spool.

4.

Lift BOPs.

5.

Clean the Casing head Housing. Make sure it is free from cement.

6.

Place hanger around Casing. Remove the four slip retainer screws on the OD of slip bowl. These screws hold slips in retracted position in bowl. Align and install the Casing Hanger according to Cameron procedures. Minimum set weight is 15 Klbs in order to energize the slips Pack-off seal. Otherwise use the Cap Screws to manually energize the Pack-off seal.

7.

Slack off on the casing. Sharp decrease on weight indicator must be seen.

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Rough cut the 9 ⅝” Casing approximately 24" above the top of the Casing Head. Move the excess Casing and BOP out of the way.

9.

Final cut the Casing at 6.75" ±1/8" [171.5mm ±3] above the top of the Casing Head. Place a 3/8" x 3/16" bevel on the Casing stub and remove all burrs and sharp edges.

10. Install BX-159 ring gasket into the ring groove of the casing head spool. 11. Lift and suspend the 13 ⅝" 10K x 11" 10K tubing spool over the casing head spool, ensuring it is level.

Figure 18 – 9 ⅝ Casing Cut 12. Carefully lower the spool until it lands on the ring gasket. Install and tighten the studs and nuts of the flange in alternating cross manner to the torque reference in the charts in the back of this manual.

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Figure 19 – Casing Head Spool, Section C 13. Inject Cameron seal packing. Energize and pressure test the two “P” seals to 500/5200 psi (maximum section design pressure), refer to Annex III. 14. Test the connection at the ring gasket to 500/5200 psi as per Cameron procedures. Note: For more details the Cameron document is included within the appendix available at Rig in hard and soft copy.

7.7.6.

13 ⅝” BOP Stack Installation and Testing Procedure

Refer to GRN BOP´s testing procedures: PS-0000-0583-002-E-00 1.


2.

Install13-5/8" 10k x 13-5/8" 10k DSA.

3.

Nipple up B.O.P. stack on 11”API 10K, BX-158 Ring gasket, Casing/Tubing Head Spool flange.

4.

Function test all BOP Rams

5.

Make up and RIH following assembly: 9 ⅝” tester cup, 1 x 5” DP joint, pup joint, side entry valve and safety valve.

6.

Set 9 ⅝” test cup below well head with test assembly. Connect test pump to choke manifold 2” outlet. Align valves to pump through side outlet of drilling spool.

7.

Close upper pipe rams and test wellhead and wellhead valve to 200 / 5200 psi (5/15 min) against upper pipe rams.

8.

Remove test cup.

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Run 11” BOP combination tool/test plug. Orientate the tool with the “LS” seal toward the bottom. Lower the tool down through the BOP/Riser until it lands on the load shoulder in the casing head spool. Ensure test port of tester plug is clear and open.

10. Connect test pump to side entry of test assembly. 11. Pressure test BOP (as per Annex III indications): a.

Test kill line check valve, choke hose connections, valve #1 of choke manifold and upper pipe rams to 200 psi for 5 min and at high pressure (5200 psi) for 10 min. Ensure kill line is disconnected from check valve and downstream valve from valve #1 of choke manifold should be open, so leaking can be verified.

b.

With upper pipe rams closed, test annular preventer to 200 / 3,500 psi (5/15min).

c.

With upper pipe rams closed, test outside kill line valve, outside choke line valve to 200 psi for 5 min, and 5200 psi for 10 min.

d.

With upper pipe rams closed, test inside kill line valve, inside choke line valve to 200 psi for 5 min, and at high pressure (5200 psi).

e.

Test lower pipe rams to 200 psi for 5 min and 5200 psi for 15 min.

f.

Back out test assembly from test plug. Remove test assembly from BOP.

g.

Connect test pump to choke manifold and pump through drilling spool. Test blind rams to 200 psi for 5 min, and 5200 psi for 15 min.

h.

Record all tests on a chart recorder, the DDR and the IADC Report.

12. Close annulus valve, release pressure and open the rams. Retrieve combination tool. 13. Close blind rams and pressure test casing string to maximum pressure of 5200 psi (as per indicated in Annex III). 14. Install wear bushing in section “C” as per Cameron procedures.

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13 ⅝” BOP Stack Up Diagram

Figure 20 – 8 ½” Section BOP Stack Diagram

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8. 8 ½” Hole Section Objectives & Overview 8.1.

8 ½” Section Key points

1.

Manage to have a stable and in gauge hole for wireline operations.

2.

Keep the well within 50m radius at the geological targets: Sieg-C Ged-B and Ged-A.

3.

Drill primary well targets down to planned TD at 3,914 mMD (70m below top of Silurian formation).

4.

8.2. 1.

Run and cement 7” Liner.

8 ½” Section hazards & Risks The Siegenian and Gedinnian reservoirs are gas bearing and will present the risk associated to the productive intervals.

2.

Formation dips in the formations may lead to hole deviation.

3.

Excessive bit wear while drilling very hard formations for the entire hole section.

4.

Shocks and vibrations associated with hard formations

5.

Tight hole and stuck pipe.

Refer to Annex VIII Risk Assessment to see all the preventive and mitigation actions for this phase. Refer to Annex X Offset wells information for more details about field experience.

8.3.

8 ½” Section Drilling Operations 8.3.1.


Rolling Cutter (ONYX360) R813 PDC with 13-16mm cutters will be used to drill out cement, shoe track and continue drilling rathole for XLOT. The same PDC bit is planned to drill down to TD through Siegenian, Gedinian and Silurian formations. No Dolerite expected in this section. In case of the 1st bit got over before section TD; the 2nd bit will be advised on due time. Drilling parameters have to be optimized maximizing a constant torque, adjusting RPM to avoid vibration and with enough flow to proper cool the bit. Bit

Primary

8 1/2" MITH PDC (ONYX 360) R81

Backup #1

Backup #2

Utility

Smith PDC MSZI716LWUEBPX

NOV PDC DSH813M

SMITH MT SVH215

Table 24 – 8 ½” Recommended Bits

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Section

Mode

Bit

WOB (Ton)

RPM Rotary

Flow Rate (lpm)

8 1/2"

RSS BHA

PDC SMITH R813

9 – 16

120‐160 1500‐2200 2700‐4100

TFA (in2)

HSI (HP/in2)

0,893 (3x14+4x12/32")

2.4

SPP (psi)

Table 25 – 8 ½” Recommended Drilling Parameters Note: the above values are based on 6” mud pump liners. 8.3.3.

Recommended BHAs

The primary BHA will be Vertical RSS assembly. The possibility of using a rotary BHA or PDM BHA for drilling part or the entire 8 ½” hole section will be evaluated during operations. If decided to run a rotary BHA it will be officially communicated by GRN team in Hassi-Messaoud (HMD).

8 1/2" RSS BHA #4 Item

Name

OD (in)/ ID (in)

1

PDC bit

8 1//2

2

AutoTrak V

3

MWD-Stab-Mod

4

BCPM

5

BCPM NM Sub

7

Stab String

9

NM Sub - filter

10

Float Sub with Totco Ring

11

18 x 6-3/4" DC

12

Jar

13

2x 6-3/4 DC

14

12 x 5" HWDP

15

5" DP S-135 19.5 lb/ft, Premium

6,75 2.31 7 2,25 7 2,1666667 6,75 3,25 6,375 2 3/4 6,75 2,8125 6,5 2,875 6,75 2,8125 6,75 2,75 6,75 2,8125 5 3 5 4,2857143

Max OD (in) 8 1//2

8,5 8 3/8 7 6,75 8 1/4 6,75 6 1/2 6,75 6,75 6,75 5 5

Bottom/Top Connection

Length (m)

Cum. Length (m)

4 1/2" Reg Pin

0.29

0.29

2.17

2.46

1.31

3.77

3.39

7.16

0.8

7.96

1.61

9.57

1.8

11.37

0.81

12.18

169.7

181.88

9.54

191.42

18.48

209.9

111.29

321.19

4 1/2" Reg Box T2 Box T2 Pin T2 Box T2 Pin T2 Box T2 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box NC-50 Pin NC-50 Box

Table 26 – 8 ½” RSS BHA WBJ: +/- 20 Ton. 1

Note : Actual Hydraulic Simulation will be carried out during the operations. 2


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3

Note : Totco Ring to be installed in preparation for Gyro operation at TD.

8 1/2" Packed BHA #6 Item

Name

1

PDC bit

2

Near bit Stab

3

1 x 6‐3/4" DC

4

Stab String

5

2 x 6‐3/4" DC

7

Stab String

11

18 x 6‐3/4" DC

12

Jar

13

2x 6‐3/4 DC

14

12 x 5" HWDP

15

OD (in)/

Max OD

ID (in)

(in)

8 1//2

8 1//2

8 7/16 2 1/2 7 2 13/16 8 7/16 2 1/2 6 3/4 2 13/16 8 7/16 2 3/4 6 3/4 2 13/16 6 3/4 2 3/4 6 3/4 2 13/16 5

8 7/16

Bottom/Top Connection

4 1/2" Reg Pin 4 1/2" Reg Box

6 3/4

8 7/16

6 3/4

8 7/16

6 3/4

6 3/4

6 3/4

5

3

5" DP S‐135

5

19,5 lb/ft, Premium

4 2/7

5

NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin NC‐50 Box NC‐50 Pin

Length

Cum, Length

(m)

(m)

0,26

0,29

1,84

2,13

9,41

11,54

1,71

13,25

18,82

32,07

1,61

33,68

169,38

203,06

9,54

212,6

18,82

231,42

111,29

342,71

3571,4

3914,11

NC‐50 Box

Table 27 – 8 ½” Packed BHA 8.3.4.


1.

Pick up enough 5” DP to drill down to section TD (3,914 m MD).

2.

P/U, M/U and RIH 8 ½” SMITH PDC Bit R813 PDC with Autotrak V BHA. Record Weight below jar. Be extremely careful when handling smart tools at the Rig floor.

3.

RIH with 8 ½” ATK BHA to float collar, tag the same and drill out and clean rat hole (2 < WOB < 6)

4.

Condition mud to ensure consistent density and properties. Verify shakers are clean of any shoe track debris. Confirm MW in/out is 1.80sg equal. Note: The previous hole sections mud will be recovered and transferred to the Mud Treatment plant or other rig.

5.

Performed Shoe Bond test.

6.

Drill 3 meters of new formation, circulated hole clean and until having homogeneous MW in/out.

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Pull back into the Casing Shoe and conduct Extended LOT & LOT respectively at 9-5/8” Casing shoe according to GRN procedures.

8.

Record pressures versus pumped/returned volume and inform Drilling Superintendent and Senior Engineer. Report values on DDR.

Open hole / Expected LOT Shoe Depth (m) Casing size (in) value (sg) 8‐1/2”

‐

9‐5/8”

3630

2.10 to 2.80

Mud Weight (ppg)


1.80

1,550‐5,200*

Kick Tolerance (bbls) 444 bbls using 1.26 s.g

Table 28 – 8-1/2” Expected ExLOT *Note: The XLOT will be limited to 5,200psi surface pressure.

9.

Displace hole from 1.80 sg to 1.26 sg Non Damage Avapolyoil Mud.

10. Drill ahead with ATK BHA. 

Increase drilling parameters when the last stabilizer is below Casing Shoe.



Monitor and control vibrations while drilling. The Drillers display must have the proper alarms, and Mud Logger will communicate to Driller and Company Man if vibration appears.






When POOH: If more than 10t drag is observed for more than 10m, immediately M/U the TDS and pump out of the hole the full stand, then try to test on elevators. If back reaming is required low rpm to be used.

11. If Bit change is required, circulated hole clean and pump his vis pill and Supersweep Pills. 12. POOH to shoe, perform flow check, circulate hole clean and resume POOH. 13. Make up & RIH with 8 ½” new bit (7 or 8 blades to be confirmed by HMD depending on the current depth). Continue drilling ahead with ATK or rotary BHA to well TD at +/-3,914m MD . (+-70m below Base of Ged-A reservoir). TD to be agreed with Town based on G&G GedA base definition. 14. Try to optimize the trips to surface to test the BOP´s every 21 days (Max allowed period). 3

15. At TD; Pump 6m of SuperSweep Pill & circulate hole clean (2 bottoms up minimum). 16. Perform a wiper trip to the 9 ⅝” shoe if considered necessary, and after agreement with the office. 17. Drop Gyro, take survey while POOH and rack back BHA. 18. Run wireline logs. 19. Based upon the logs duration, control trips could be performed between wireline runs.

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8 ½” Section Drilling Fluids 8.4.1.


A Low Damage AVAPOLYOIL mud system will be run. Displace hole once the extended LOT is done. Refer to Annex VII for more information about mud system.

Interval Depth

Units

8 1/2” Hole Section

meters

+/‐284

Mud Type Mud Weight

AVAPOLYOIL / SOLTEX / POLYMER sg

1,26

pH

9.5 ‐ 10

Plastic Viscosity Yield Point Gels 10 sec / 10min / 30min API Fluid Loss


cP

ALAP

lb/100sqft

18‐20

10/15/20

cc/30min °C

≤3

cc

140

Table 29 – 8 ½” Recommended Drilling Fluids Parameters

8.5.

8 ½” Cutting Sampling – Mud Logging Program

Set of samples will be collected from the beginning of 8 ½” drilling phase down to TD. Two types of samples will be collected as below. From Muraille de Chine to top of Siegenian, every 5 meters. 

Set-1: GRN: Washed and dried (Dry) / Unwashed (Wet)




From Siegenian to TD, every 3 meters. 

Set-1: GRN: Washed and dried (Dry) / Unwashed (Wet)




Mud Sampling: 

8.6.

Refer to GEOLOGICAL OPS PROGRAM

8 ½” Section Electric Logging Operations

Open Hole The following logs will be run after reaching 8 ½” section TD: 

Run 3A: SGT-EMS-DSI(P&S+Stoneley)



Run 3B: NGS-LDS/MCFL/APS-HRLA

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

Run 3C: SGT-CMR200



Run 3D: MDT (SP-STD)-SGT) – optional

Cased Hole The following logs will be run in 9 ⅝” casing: SGT-CBL-VDL-CCL (USIT/IBC optional)



8.7.

7” Liner Operations 8.7.1.

7” Liner String Weight (lb/ft)

Grade

Connection

Centralization

”

32

13Cr‐110

Vam Top

‐

7

”

32

13Cr‐110

Vam Top

TBA


7

”

32

13Cr‐110

Vam Top

TBA

Float Collar

7

”

32

13Cr‐110

Vam Top

TBA


7

”

32

13Cr‐110

Vam Top

TBA

7”

32

13Cr‐110

Vam Top

TBA

Casing Joint

7

”

32

13Cr‐110

Vam Top

TBA

7” X 9 ⅝” Weatherford Liner Hanger

7”

32

13Cr‐110

Vam Top

TBA

Item

Qty

Description

Size

1

1

Float Shoe

7

2

1


3

1

4

1

5

1

6

1

7

+/‐ 36 1

8

Landing Collar

Table 30 – 7” Liner Specifications 8.7.2.

7” Liner Running Procedure

A detailed Liner Running Program including Baker recommendations and best practices will be issued as a separate document before the Liner Installation Job. 8.7.3. 7” Liner Cementing Procedure Objective: To cover and isolate reservoir main objectives.  Top of slurry 200 m inside 9 ⅝” casing (50m above top of the liner).  The cement slurry design and the placement procedures will be detailed in the final cement proposal to be issued by cementing company. The final recipe has to be on the rig at least 48 hours before the cement job.

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Once the hanger has been set, set down 30 Klbs of DP weight on liner hanger to compensate for pump out forces. Check rotation and condition mud before pumping cement.

2.

Line up the cement unit and pressure test the surface cementing equipment to 6000 psi. Mix the cement as per the program. Note: Keep circulating and rotating (10-20 rpm) while mixing cement.

3.

Pump the cement spacers and slurry (6m3 of mud push + 1.4m3 of intermediate spacer 1,45sg and 8m3 of 1.90sg Flexstone, 25% excess included).

4.

After the cement has been pumped, close the main valve and release the drill pipe wiper dart as required and displace with mud using cement unit pumps to accuracy displacement.

5.

Displace drill pipe volume. For the last 5 bbls, slow pump rate to 2 bbl/min, since excessive pump rate may interfere with the shear mechanism. A slight increase in pressure should be noted as the wiper dart plug latches into the liner wiper plug. After the liner wiper plug shears recalculate the actual displacement and increase pumping rate back.

6.

The following guidelines should be used for the displacement. a.

If wiper plug shears early. Count from the shear

b.

If wiper plug shear is < 1 bbl late. Count from the shear.

c.

If wiper plug shear is > 1 bbl late. Use theoretical displacement only.


Continue to displace the liner as per program, slowing the pump rate to 2 bbl/min on the last 5 bbls. As the liner wiper plug reaches the landing collar, pressure up to 1,000 psi over displacement pressure and hold for 1 minute.

8.

Bleed pressure back in to the pump truck tanks to ensure that the plugs and float equipment are holding. If not holding, pressure up on the liner again increasing pressure slightly and bleed back once again.

9.

Proceed to set and test Weatherford packer (separate detailed program will be provided). 8.7.4. Inflow Test and Clean Out of Liner Top Packer

A detailed Liner Inflow Test Procedure including Horner Plot guidelines and interpretation will be issued as a separate document before the Liner Inflow Test will be performed. Also a positive test will be performed to confirm good seal of the liner top packer.

8.7.5.Preparing for Completion Upon successful Inflow test of the Liner Top Packer the well will be displaced to brine. The clean-out BHA will be POOH and Cased Logs will be run in order to evaluate the 7” liner cement job. The well will be then handed over to Completion Department in order to carry out the planned completion program. Groupement Reggane



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9. ANNEXES 9.1.

ANNEX I – Casing specifications

Grade

Connecti on

ID (in)

Drift (in)

Burst (psi)

Collapse (psi)

Tensile Yield Strength (KLb)

Torque (lb x ft) Min Optimum Max

87.5

K-55

BTC

17.755

17.567

2,248

627

1,366

To Triangle

72

Q-125

Vam Top

12.347

12.25

8,410

2,880

2,596

20,850 23,150 25,450

Special Drift

Vam Top

8.535

8.500

10,900

1,710

20,850 23,150 25,450

Special Drift

Hole Depth (m MD RT )

Casing Size (in)

Lenght (m)

Linear Weight (lb/ft)

24”

+/- 450

18 ⅝”

+/- 450

16”

+/- 2300

13 ⅜”

+/- 2300

12 ¼”

+/- 3630

9 ⅝”

Hole Size (in)

+/- 2900

P-110 53.5

+/- 730

7,950

P-110HC

10,550

8 ½”

+/- 3914

7”

+/- 450

32

13Cr-110 / P-110

Vam Top

6.094

6.000

12,460

10,780

1,025

6”

Contingency

4 ½”

-

13.5

13Cr-110

Vam Top

3.920

3.795

12,410

10,680

422

Table 31 – Casing Specifications

Groupement Reggane

12,450 13,750 15,050 5,200 5,770 6,340

Remarks

Special Drift


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ANNEX II – 10K psi W.P. Wellhead Specifications

Figure 21 – Cameron Wellhead System 10K Groupement Reggane


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ANNEX IV – Drilling Bits Specification.

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9.6.

ANNEX VI – Cement program summary

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9.7. ANNEX VII – LCM Decision Tree

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9.8. ANNEX VIII - Risk Assessment Prior to each non-routine or routine operation commencing a Risk Assessment process must be performed. This process should be well structured and with a logical sequence. It is recommended to carry out the assessments in two stages. Stage one covers the identification of hazards (task analysis); stage two covers the assessment of risk and selection of control measures in order to reduce the risk to an acceptable level (risk assessment) and the subsequent communication of this in the form of information and instruction to the workforce involved in the task. EXPOSURE ( E ) -6

Accident Scenario Frequency (1/year)

< 10

Value t n e m s s e s s a f o a e r A

Specific sector of activity at global level

According to the area of the business/activity

Personal Injuries

Damage to property and loss of profits Environment damage Enviromental remediation costs (€)

Low

Incident without lost time

€ 5 k - € 100 k

Moderate

Up to 30 days of lost time. <1% probability of 1 death

€ 100 k - € 1 M

Serious

Over 30 days of lost time. <10% probability of 1 death

€ 1 M - € 10 M

Very Serious

Could cause a death or permanent injuries

€ 10 M- € 100 M

Disastrous

Could cause betw een 2 and 9 deaths

€ 100 M- € 1000 M

Catastrophic

Could cause 10 deaths or more

Groupement Reggane

> € 1000 M

-5

-5

10 to 10

-4

0.8

1.6

Unheard of

It has not happend

It has happend before

-4

10 to 10 3.1

-3

-3

10 to 10

-2

6.3

Non-significant envir omental incident in an area without guaranteed containment, causing local environmental damage within the limits of the property Relevant environmental damage that exceeds the levels of reference for environmental quality or is capable of generating legal action and does not have permanent effects Serious environmental damage that could affect the property's environment, which exceeds in large areas the reference levels for environmental quality and could affect third parties Very serious environmental damage. The company is required to provide correction and/or significant compensation measures, in large areas it esceeds the reference levels for environmental quality; high probability of permanent residual damage Catastrophic environmental damage; loss of environmental resources and s ervices. Permanent damage Catastrophic and widespread environmental damage; extensive loss of environmental resources and services. Permanent damage

Level of difussion; reputation

Value

No dissemination

1.7

Green level crisis

3

Yellow level crisis

7

Red level crisis

16

Temporary international affectation

40

Permanent international affectation

100

-2

10 to 10

-1

12.5

-1

10 to 1

1 to 100

25

100

It has happend It happens on It happens on a in the last five an annual basis monthly basis years It has happend before

Specific sector of activity in GRN

CONSEQUENCES ( C ) Level of consequences

-6

10 to 10

0.4

It has happend It happens on It happens on a in the last five an annual basis monthly basis years It has happend It has happend It happens on in the last five before an annual basis years



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24" SECTION Scores Operation

Running Casing

Risk / Hazard

● Casing

running equipment failure

Consequences

● Induce losses due to surge

pressure ● Unable to reach bottom

Cementing Job

● Losses

w hile cementing

● Casing Float Equipment failure

Like (L)

1,7

6,3

1,2

hole collapse ● Critical zone not covered by casing ● Cement job operation seriously compromised

Preventive Actions

Risk (R) 12,9

● Stuck casing due to

● To have Casing running equipment back-up on site Minor ● Crosscheck equipment on site since w ill be firs 18 5/8" job in the project

3

6,3

1,2

22,7

1,7

6,3

1,2

12,9

1,7

6,3

1,2

12,9

running speed (run surge simulation prior to start RIH) ● Perform wiper trip prior to run casing ● Pump and displace Hi-vis pill after last w iper trip Moderate * Prepare to incorporate f ibers in your cementation

of c ement in volume (50-100 %) w hile running casing or w hile circulating prior to perform cement job Minor ● To re-design pumping schedule w ith lower pumping rate in case of having losses prior to start cement job

● Lost time (NPT) due to additional

WOC

Groupement Reggane

Mitigation Actions

● Control

● Level drops once c ement job has

finished ● No good isolation achieved

Cementing Job

Expo ( E)

● Lost time (NPT) due to Casing

running equipment repairs Running Casing

Cons (C)

immediately or perform equipment repairs as fast as possible ● Reduce running speed if losses are detected ● Keep w ell fluid level if losses are detected ● POOH casing to condition the hole

● Reduce

● To add some fibers to c ement slurry in cas e of losses

● Perform Top job

to RIH

Residual Risk ( R )

● Sw itch to use bac k-up equipment

● To use considerable excess

● Function test f loat valves f rom float equipment (Shoe) prior

Minor

Success (%)

90%

1,3

Minor

70%

6,8

Minor

70%

3,9

Minor

70%

3,9

Minor

pumping rate

● Sting

back in, Re-pump return volume, maintain pressure until surface samples are hard



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16" SECTION Scores Operation

Cementing Job

Cementing Job

Risk / Hazard

● Losses

● Casing

w hile cement

Float Equipment f ailure

Cons equences

cement job has finished ● No good isolation achieved ● Possible gas c oming into the w ell due to lost of hydrostatic column

Cons (C)

Expo (E)

Like (L)

● Level drops once

● Lost

1,7

6,3

1,2

12,9

1,7

6,3

1,2

12,9

time (NPT) due to additional

WOC

Groupement Reggane

Preventive Actions

Risk (R)

Mitigation Actions

● To use gas tight slurry

● Reduce

● To use excess of

cement according to caliper ● To add some fibers to cement slurry in case of losses w hile running casing or w hile circulating prior to perf orm cement job ● To re-design pumping schedule w ith lower pumping rate in case Minor of having losses prior to start cement job ● To use bottom and top cement plugs method ● Appling Surface Pressure if required w hile WOC.

● Perform Remedial Job

● Function test f loat valves f rom float equipment (Shoe and Collar) Minor prior to RIH ● Do not overdisplace more than 50% of shoe tr ack volume

● Close

Success (%)

Residual Risk ( R )

pumping rate

well to prevent cement flow back and WOC

70%

3,9

Minor

70%

3,9

Minor


9.9. ANNEX IX – Well Diagram (A3 Format)

Groupement Reggane

Reggane Nord Development Project

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9.10. ANNEX X – Offset wells 9.10.1. 24” Section Offset Experience and Information

AZSE-21 No hole Problems were reported. Apart of slow ROP observed from 320m down to section TD. AZSE-1 No Problems were reported. AZSE-2 Washout until 85 m due to unconsolidated sand. Severe Bit balling. AZSE-3ST High Vibration during drilling this section. Bit & Stabilizers got completely balled up. Very Low ROP from 364 m to 398 in Namurian Formation. Reggane-1 Shallow HC occurrence was reported. Reggane-5 The upper section of the well was drilled with a 24” bit to a MD of 267m MD RT. No Problems were reported. Reggane-6 The upper section of the well was drilled with a 24” bit to 393m MD RT. Bit and stabilizers balled up. Also losses were experienced. Not reported severity. The 24” section was then cased (18- ⅝" Casing) without any problems. No shallow gas encountered. Reggane-7 The 24” hole – 18 ⅝” Casing section was drilled to a section TD of 281 m MD RT No Operational problems were reported. Reggane-8 The 24” hole – 18 ⅝” Casing section was drilled to a section TD of 245 m MD RT No Operational problems were reported. Reggane-16 The 24” hole – 18 ⅝” Casing section was drilled to a section TD of 345 m MD RT Groupement Reggane



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No Operational problems were reported. 9.10.2. 16” Section Offset Experience and Information The main difference versus the offset wells the Dolerite will be drilled in the 16” hole section and the TD of this section is most deepest well among the other offset wells. Other than that, tight hole and deviation issues were predominant in all the offset wells. AZSE-21 High Torque & Vibration during drilling this section. Partial & total losses encountered in AZSE-21 where LCM Pills and Thixotropic Cement plug were required to cure losses. Very low ROP in Dolerite & Strunian formation (Quartzitic Sandstone). 7 bits (TCI & PDC) were required to drill the 16” section. AZSE-1 Fluid losses from 599 to 770m (150-600 l/hrs). AZSE-2 Formation Breakout and having ledges in many interval which leaded to difficult Tubular running.. Tight Spots in many intervals. Seepages losses were associated to fractured limestone. AZSE-3ST High Torque & Vibration during drilling this section. At 619m a 6.5 % gas peak with some traces of CO2 was observed. Losses have encountered in this section: Avagraph seal was used from +/- 1000 m to tackle the losses Reggane-5 17-1/2” hole section was drilled from 267 to 1175 m through Carboniferous formations. Shoe was set in Visean A. Several tight hole, overpull and stuck pipe incidents were reported. Necessary to back ream several times and increase the MW to 1.18sg. No dolerite was found in this section. Av ROP ±7 m/hr. 1 bit run. See 12.25” section for more information about dolerites. Reggane-6 16” hole section was drilled from 470 to 1540 m through Carboniferous formations. Shoe was set in Visean A. No operational issues reported. No dolerite was found in this section. Av ROP ±5.5 m/hr. 2 bit runs. Reggane-7 16” hole section was drilled from 282 m to 1182 m through Carboniferous formations. Shoe was set in Tournasian. No operational issues reported. No dolerite was found in this section. Av ROP ±15 m/hr. 1 bit run. Groupement Reggane



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Reggane-8 16” hole section was drilled from 245 m to 1251 m through Carboniferous formations. Shoe was set in Famennian. No operational issues reported. Two main layers of Dolerite were found in RG-8. Both in 16” section Dolerite #1 (735 – 863 m) A PDC with 6 blades 19 mm was used to drill the top part of the section, once dolerite was identified the bit was pulled to preserve bit life as this bit was too aggressive to drill any kind of dolerite.2 runs were required to drill it. Both using same TCI, NOV st nd T52 (IADC 525). 1 run 1.6 m/hr and 2 run 1.47m Dolerite #2(1185-1251m). Drilled with same bit as previous formation, Varel R716 DGHX PDC 7 blades 16 mm cutters. Cuttings comparison showed 1st dolerite much harder than 2nd dolerite. ROP in dolerites: 5m/h

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Reggane-16 16” hole section was drilled from 345 to 1843 m through Carboniferous formations. A long section of Visean formations was drilled with PDC 7 blades 16 mm cutters with average ROP of 15 m/hr,( excluding controlled ROP). Caving has encountered around the dolerite formation. 9.10.3. 12 ¼” Section Offset Experience and Information

AZSE-21 Encountered tight spots, overpull and had to back reaming many intervals. Traces of caving while drilling 12.25” section started 2475 m to section TD. Had to pull out of the hole in most of the trips. AZSE-1 No Problems were reported. AZSE-2 Formation Breakout and caving have encountered around the Dolerite layers. AZSE-3ST High Torque & Vibration during drilling this section. Losses have encountered in Tournsian FM at 20m3/hr and then reduced to 10m3/hr by reducing the flow rate pumping 7m3 of 200kg/m3 LCM Pill. A kick was occurred from Emsian. Gained 23m3, followed by lost circulation and underground blow out. Plugged back and ten sidetrack was carried out. More details will be delivered from AZSE-3 Well Control Report. Reggane-5 12-¼” hole section was drilled from 1175 m to 3183 m Devonian formations. Shoe was set inside Givetian formation. Several tight hole incidents observed. Had to ream/back ream several intervals. Two main dolerite layers were found in this section: 1305-1390m with and av ROP of 2.3 m/h – 2 bits Groupement Reggane



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1743-1790m. with and av ROP of 1.0 m/h - 2 bits Total of 12 bits were required. For non-dolerite formations the average ROP was 2.9m/h Reggane-6 12-¼” hole section was drilled from 1540 m to 3665m through Devonian formations. Shoe was set in Couvinian. Several tight hole incidents observed. Had to ream/back ream several intervals, especially experienced in dolerites. Two main dolerite layers were found in this section: 1780-1890m with and av ROP of 1.35 m/h – 3 bits 2285-2335m. with and av ROP of 0.94 m/h - 2 bits Total of 8 bits were required for the section. For non-dolerite formations the average ROP was 8.6m/h Reggane-7 12-¼” hole section was drilled from 1182m to 3162m through Devonian formations. Shoe was set in Couvinian.. The biggest issue was the deviation of the well trajectory. Two main dolerite layers were found in this section: 1255-1340m with and av ROP of 1.77 m/h – 4 bits 1755-1800m. with and av ROP of 4.12 m/h - 2 bits Total of 7 bits were required for the section. For non-dolerite formations the average ROP was 9.6m/h Reggane-8 12-¼” hole section was drilled from 1251m to 2758m drilling the same formations as the ones to be drilled in RG-16. No major issues were reported with neither inclination nor ROP performance. No dolerite was found though whereas in RG-16 27m are expected. The section was drilled with a PDC 7 blades 16mm. 2 bits were required. In Famenian the average ROP was 15m/hr. In frasnian formation the ROP dropped to 6m/h at the top and 1.8m at the bottom. In Givetian, Couvinian and Emsian, the ROP was around 1.7m/hr. Reggane-16 12-¼” hole section was drilled from 1840 m to 2516 m through Famenian formation. One layer of dolerites was drilled from 2065 m to 2119 m. This section could be finished to the planned TD due to hole instability. Consequently 9 5/8” casing was run prematurely and also not to the drilled TD. Total almost 15.5 days as NPT for hole instability. The main lesson learnt is to take into the formation collapse pressure refer to Geo-mechanical study, wiper trips is recommended to anticipate any potential hole instability and ledges above Dolerite formation. It was related to a geomechanical issue by not having the required minimum mud weight. 9.10.4. 8 ½” Section Offset Experience and Information AZSE-21 Very slow ROP especially in GED A. Encountered hole instability prior/during the 7” CSG cementing Job AZSE-1 Groupement Reggane



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Fluid losses while cutting cores. AZSE-2 This interval was drilled in 6” hole in AZSE-2 and no major issue reported apart of low ROP. AZSE-3ST This interval was drilled in 6” hole in AZSE-3ST and no major issue reported. Hoe deviation of 13.5° at 3,875m. Reggane-5 8 ½” hole section was drilled from 3183 to 4202 m through Devonian and Silurian formations. Shoe was set in Ordovicean. No dolerite encountered. Very low ROP experienced (Av section ROP: 3.1 m/h). 12 bits were required to drill the section. One of them lost a cone. Note – RG-5 well was finished in 6” hole but RG-16 will not drill those formations Reggane-6 8 ½” hole section was drilled from 3665 to 4633 m through Devonian and Silurian formations. Shoe was set in Ordovicean. No dolerite encountered. Problems trying to keep verticality. Cavings reported in Emsian. Special caution to be taken in Emsian formation, during the exploration phase 2x kicks were taken in this formation. Very low ROP experienced (average section ROP: 3.4 m/h). 10 bits were required to drill the section. Covinian formations seemed to be a bit softer but Emsian, Siegenian and Gedinnian are extremely hard. Note – RG-6 well was finished in 6” hole but RG-16 will not drill those formations (Hamra Quartzites). Reggane-7 8-½” hole section was drilled from 3162m to 3552m through Devonian and Silurian formations. Shoe was set in Gothlandian. The biggest issue was the difficulties trying to keep the well vertical. Very low ROP experienced (average section ROP: 1.9 m/h). 9 bits were required to drill the section. Reggane-8 8-½” hole section was drilled from 2758m to 3040m through Devonian and Silurian formations. Not extreme issues observed. Hard formation in reservoirs (silicified sandstones). The ROP throughout the reservoirs was controlled max to 5m/h. 2x bits were required. First was a 7 blade 13mm which drilled 148 at 2.4 m/h and then a new PDC 8 blades 13 mm was run to complete the section. The Gedinnian formations were dilled at around 5m/hr and the Silurian at +6 m/hr. Reggane-16 This section is being drilled in 6” hole without any issue. However it is building angle up to 24° due to formation dip and not using ATK.

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9.11. ANNEX XI – Drilling Jar Change out recommendations

Groupement Reggane

Drilling Program AZSE-4 v.1.1 SIGNED

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