Drilling and workover best practices

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ARPO

ENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OF ACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 7

STAP P 1 M 6090

The present document is CONFIDENTIAL and it is the property of ENI AGIP.It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

TITLE

BEST PRACTICES AND MINIMUM REQUIREMENTS FOR DRILLING

AND COMPLETION ACTIVITIES

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion Units

STAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) anda CD-Rom version can also be distributed (requests will be addressed to STAP Dept.in Eni - Agip Division Headquarter)

Date of issue:

!

"

#

$

% Issued by P. Magarini C. Lanzetta A. Galletta

28-04-2000 28-04-2000 28-04-2000

REVISIONS PREP'D CHK'D APPR'D

28/04/2000



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REVISION

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INTRODUCTION

PURPOSE OF THE DOCUMENT

The purpose of the Best Practices and Minimum Requirements is to guide technicians andengineers, involved in Eni-Agip’s Drilling & Completion worldwide activities, through theManuals & Procedures and the Technical Specifications which are part of the CorporateStandards.

Such Corporate Standards define the requirements, methodologies and rules that enable tooperate uniformly and in compliance with the Corporate Company Principles. This, however,still enables each individual Affiliated Company the capability to operate according to locallaws or particular environmental situations.

The final aim is to improve performance and efficiency in terms of safety, quality and costs,while providing all personnel involved in Drilling & Completion activities with common

guidelines in all areas worldwide where Eni-Agip operates.

The Best Practices and Minimum Requirements (also defined by the acronym BP&MR) is themain reference document for the Audits on the Drilling & Completion activities that theCorporate will be carrying out in the Districts and Affiliates.

IMPLEMENTATION

The “Best Practices and Minimum Requirements” document addresses all well area activities,from the initial feasibility study through completion and workover operations. The topics havebeen divided in three main sections:

1) PLANNING (PL)It includes the fundamental actions preceding the well operations, such as feasibilitystudy, authorisations, operational planning, construction of the location, etc.

2) OPERATIONS (OP)

It address the operations carried out in the well area, such as drilling, well testing,completion, workover, equipment inspection and waste treatment.

3) REPORTING & FEEDBACK (RF)

This section describes all the reports, forms and documents to be filled in and sent to

the Corporate Drilling & Completion Standards Department in Eni-Agip DivisionHeadquarters. This should be done either periodically or at the end of each operation.This will provide a record of the well and where to find all relevant informationnecessary for studies, analysis and evaluations of the operations. This will enableimprovement and optimisation of further activities.

For every BP&MR specified, the source (manual, procedure, technical specification) has beenlisted, to help finding the entire and associated subjects, if required.

Where the reference column is blank, this means that there are no reference documentsavailable or they are currently under preparation.



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UPDATING, AMENDMENT, CONTROL & DEROGATION

The BP&MR is a ‘live’ controlled document and, as such, it will only be amended and

improved by the Corporate Company, in accordance with the development of Eni-AgipDivision and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies andrelated procedures on an ongoing basis.

Locally dictated derogations from BP&MR shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/AffiliateManager and the Corporate Drilling & Completion Standards Department in Eni-Agip DivisionHead Office have been advised in writing.

The Corporate Drilling & Completion Standards Department will consider such approvedderogations for future amendments and improvements of the BP&MR, when the updating of the document will be advisable.



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STAP-P-1-M-6090 0

INDEX

ABBREVIATIONS

SECTION 1 PLANNING (PL)

PRELIMINARY (PL.01)

GEOLOGICAL AND DRILLING WELL PROGRAMME (PL.02)

COMPLETION DESIGN (PL.03)

SECTION 2 OPERATIONS (OP)

MOVING AND POSITIONING (OP.01)

DRILLING OPERATIONS (OP.02)

COMPLETION AND WORKOVER OPERATIONS (OP.03)

MATERIALS AND TRANSPORTATION (OP.04)

WASTE TREATMENT AND DISPOSAL (OP.05)

SECTION 3 REPORTING & FEEDBACK (RF)

REPORTING AND FEEDBACK FORMS (RF.01)

FINAL DRILLING REPORT (RF.02)



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ABBREVIATIONS

The following tables contain the abbreviations used in the document:

AC/DC Alternate Current, Direct Current NB Near Bit Stabiliser

AHTS Anchor Handling Towing Supply NDT Non Destructive Test

API American Petroleum Institute NMDC Non Magnetic Drill Collar

BG Background gas NSG North Seeking Gyro

BHA Bottom Hole Assembly NTU Nephelometric Turbidinity Unit

BHP Bottom Hole Pressure OBM Oil Base Mud

BHT Bottom hole temperature OD Outside Diameter

BJ Blast Joint OEDP Open End Drill Pipe

BMT Blue Methylene Test OH Open Hole

BOP Blow Out Preventer OHGP Open Hole Gravel Packing

BPD Barrel Per Day OIM Offshore Installation Manager BPM Barrels Per Minute OMW Original Mud weight

BPV Back Pressure Valve ORP Origin Reference Point

BSW Base Sediment & Water OWC Oil Water Contact

BUR Build Up Rate P&A Plugged & Abandoned

BWOC By Weight Of Cement P/U Pick-Up

BWOW By Weight Of Water PBR Polished Bore Receptacle

C/L Control Line PCG Pipe Connection Gas

CBL Cement Bond Log PDC Polycristalline Diamond Cutter

CCD Centre to Centre Distance PDM Positive Displacement Motor

CCL Casing Collar Locator PGB Permanent Guide Base

CDP Common Depth Point PI Productivity Index

CET Cement Evaluation Tool PKR Packer

CGR Condensate Gas Ratio PLT Production Logging Tool

CMT Cement POB Personnel On Board

CP Conductor Pipe POOH Pull Out Of Hole

CR Cement Retainer PPB Pounds per Barrel

CRA Corrosion Resistant Alloy PPG Pounds per Gallon

CSG Casing ppm Part Per Million

CT Coiled Tubing PTR Piano Tavola Rotary

CW Current Well PV Plastic Viscosity

DC Drill Collar PVT Pressure Volume TemperatureDE Diatomaceous Earth Q Pump Rate

DHM Down Hole Motor Q/A Q/C Quality Assurance, Quality Control

DHSV Down Hole Safety Valve R/D Rig Down

DIF Drill in Fluid R/U Rig Up

DLS Dog Leg Severity RBP Retrievable Bridge Plug

DLS Dog Leg Severity RCP Reverse Circulating Position (GP)

DM /

D&CM

Drilling & Completion Manager RFT Repeat Formation Test

DOB Diesel Oil Bentonite RIH Run In Hole

DOBC Diesel Oil Bentonite Cement RJ Ring Joint

DOR Drop Off Rate RKB Rotary Kelly BushingDP Drill Pipe ROE Radius of Exposure



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DPHOT Drill Pipe Hang off Tool ROP Rate Of Penetration

DRLG Drilling ROU Radios Of Uncertainty

DST Drill Stem Test ROV Remote Operated VehicleDV DV Collar RPM Revolutions Per Minute

E/L Electric Line RPSP Reduced Pump Strokes Pressure

ECD Equivalent Circulation Density RT Rotary Table

ECP External Casing Packer S (HDT) High Resolution Dipmeter

EMS Electronic Multi Shot S/N Serial Number

EMW Equivalent Mud Weight S/O Slack-off

EOC End Of Curvature S/S Short String

EP External Pressure S/V Supply Vassal

ESD Electric Shut-Down System SAFE Slapper Activated Firing Equipment

ESP Electrical Submersible Pump SBA Safe Breathing Area

ETA Expected Arrival Time SBHP Static Bottom Hole PressureETU Endless Tubing Unit SBHT Static Bottom Hole Temperature

FBHP Flowing Bottom Hole Pressure SCBA Self Contained Breathing Apparatus

FBHT Flowing Bottom Hole Temperature SCC Stress Corrosion Cracking

FC Flow Coupling SCSO Single Completion Seal Flange

FINS Ferranti International NavigationSystem

SCSSV Surface Controlled SubsurfaceSafety Valve

FPI/BO Free Point Indicator / Back Off SCUBA Self Contained Underwater Breathing Apparatus

FTHP Flowing Tubing Head Pressure SD Separation Distance

FTHT Flowing Tubing Head Temperature SDE Senior Drilling Engineer GCT Guidance Continuous Tool SF Safety Factor

GLR Gas Liquid Ratio SG Specific Gravity

GLS Guidelineless Landing Structure SICP Shut-in Casing Pressure

GMS Gyro Multi Shot SIDPP Shut-in Drill Pipe Pressure

GOC Gas Oil Contact SIMOP Simultaneous Operations

GOR Gas Oil Ratio SN Seating Nipple

GP Gravel Pack SPM Stroke per Minute

GPM Gallon (US) per Minute SPV Supervisor

GPS Global Positioning System SR Separation Ratio

GR Gamma Ray SRG Surface Readout Gyro

GRA Guidelineless Re-entry Assembly SSC Sulphide Stress Cracking

GSS Gyro Single Shot SSD Sliding Sleeve Door Valve

HAZOP Hazard and Operability SSLV Sub Surface Lubricator Valve

HDT High Resolution Dipmeter SSR Sub surface Release Plugs

HHP Hydraulic Horsepower SSSV Sub Surface Safety Valve

HO Hole Opener SSTT Sub Surface Test Tree

HP/HT High Pressure - High Temperature SSTV Subsea Television

HSI Horsepower per Square Inches ST Steering Tool

HW/HW

DP

Hewi Wate Drill Pipe STD Stand

IADC International Drilling Contractor STG Short trip gasIBOP Inside Blow Out Preventer STHP Static Tubing Head Pressure



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ICGP Inside Casing Gravel Packing STHT Static Tubing Head Temperature

ID Inside Diameter STT Surface Test Tree

IFR Imposta Fabbricazione Ridotta SX SacksIP Internal Pressure TBG Tubing

IPR Inflow Performance Relationship TCP Tubing Conveyed Perforations

JAM Joint Make-up Torque Analyser TD Total Depth

KMW Kill mud weight TDB Total Drilling Control

KOP Kick Off Point TDS Top Drive System

L/D Lay-Down TFA Total Flow Area

L/S Long String TG Trip Gas

LAT Lowest Astronomical Tide TGB Temporary Guide Base

LC 50 Lethal Concentration 50% THA Tubing Head Adapter (bonnet)

LCDT Last Crystal to Dissolve °C TOC Top of Cement

LCM Lost Circulation Materials TOL Top of Liner LCP Lower Circulation Position (GP) TRSV Tubing Retrievable Safety Valve

LEL Lower Explosive Limit TTBP Through Tubing Bridge Plug

LMRP Low Marine Riser Package TVD True Vertical Depth

LN Landing Nipple TW Target Well

LOT Leak Off Test UAR Uncertainty Area Ratio

LQC Log Quality Control UCP Upper Circulating Position

LTA Lost Time Accident UEL Upper Explosion Level

LTT Lower Tell Table (GP) UGF Universal Guide Frame

LWD Log While Drilling UHF Ultra High Frequency

M/D Martin Decker UR Under Reamer

M/U Make-Up UTM Universal Transverse of Mercator

MAASP Max Allowable Annular SurfacePressure

VBR Variable Bore Rams (BOP)

MD Measured Depth VDL Variable Density Log

MLH Mudline Hanger VHF Very High Frequency

MLS Mudline Suspension VSP Velocity Seismic Profile

MMS Magnetic Multi Shot W/L Wire Line

MODU Mobile Offshore Drilling Unit WBM Water Base Mud

MOP Margin of Overpull WC Water Cut

MPI Magnetic Particle Inspection WHP Well Head Pressure

MSCL Modular Single Completion Land WHSIP Well Head Shut-in PressureMSL Mean Sea Level WL Water Loss

MSS Magnetic Single Shot WO Workover

MUT Make Up Torque WOB Weight On Bit

MW Mud Weight WOC Wait On Cement

MWD Measurement While Drilling WOW Wait On Weather

N/D Nipple-Down WP Working Pressure

N/U Nipple-Up XO Cross Over

NACE National Association of CorrosionEngineers

YP Yield Point



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SECTION 1 OF BP&MR - PLANNING (PL)

SECTION 1

PLANNING (PL)



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INDEX

PL1. PRELIMINARY 7

PL. 1.1. FEASIBILITY STUDY 71. NEW WELL 72. WELL RE-ENTRY 7

PL. 1.2. DRILLING & COMPLETION DEPARTMENT ACTIVITIES 81. DEPARTMENT RESPONSIBILITIES 8

PL. 1.3. RIG SELECTION 101. TECHNICAL SPECIFICATIONS CONTENTS 10

PL. 1.4. AUTHORISATIONS AND PERMITS 121. GENERAL 12

PL. 1.5. TECHNICAL DOCUMENTATION 131. RIG SITE 132. DRILLING & COMPLETION DEPARTMENT 13

PL. 1.6. MAIN CONTRACTORS 141. DRILLING CONTRACTOR 142. MUD LOGGING 183. MUD SERVICE, CHEMICAL SUPPLY, CENTRIFUGES RENTAL 204. CEMENTING SERVICE 22

PL. 1.7. ESTIMATED COSTS 251. BUDGET 252. COSTS 25

PL2. GEOLOGICAL AND DRILLING WELL PROGRAMME 26

PL. 2.1. GEOLOGICAL AND DRILLING WELL PROGRAMME STRUCTURE 271. NUMBER OF THE SECTIONS 272. PRINT MODEL 27

PL. 2.2. GENERAL INFORMATION (SECTION 1) 281. GENERAL 282. GENERAL WELL DATA 283. GENERAL RECOMMENDATIONS 294. GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND SAFETY

EQUIPMENT 295. LIST OF THE MAIN CONTRACTORS 296. CONTACTS IN CASE OF EMERGENCY 307. REFERENCE MANUALS 308. MEASUREMENT UNITS 309. SIGNATURE 30

PL. 2.3. LAYOUT OF THE DRILLING PROGRAMME (SECTION 4) 331. BASIC REQUIREMENTS 33

PL. 2.4. OPERATIVE SEQUENCE (SECTION 4) 351. PRELIMINARY INFORMATIONS 352. CONDUCTOR PIPE PHASE 35

3. SURFACE PHASE 364. INTERMEDIATE PHASES 365. FINAL PHASE 37



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6. TESTING 377. TYPE OF COMPLETION 378. WELL ABANDONMENT 38

PL. 2.5. SOFTWARE (SECTION 4) 391. STANDARDS 392. ALTERNATIVES 39

PL. 2.6. PRESSURE GRADIENTS PROGNOSIS (SECTION 4) 401. PRELIMINARY DATA COLLECTION 402. DEFINITIONS 413. PRESSURE GRADIENTS PREDICTION & EVALUATION 43

PL. 2.7. SHALLOW GAS 481. PRELIMINARY SHALLOW GAS INVESTIGATION 482. SHALLOW-GAS DRILLING GUIDELINES 483. DIVERTER 50

PL. 2.8. CASING SETTING DEPTH 511. DETERMINE PROPER SETTING DEPTH FOR EACH CASING TYPE 512. GENERAL GUIDELINES ON CASING SETTING DEPTHS 513. SAFETY REQUIREMENTS 52

PL. 2.9. DIRECTIONAL WELL PLANNING 531. PRELIMINARY DIRECTIONAL PLAN INFORMATION 532. DEFINITIONS 543. SURVEY CALCULATIONS 554. SURVEY TOOL SELECTION 565. FREQUENCY AND TYPE OF SURVEYS 596. ANTI-COLLISION 597. BHA ANALYSIS 63

8. REPORTING 64

PL. 2.10. CASING DESIGN 701. CASING SETTING DEPTH AND FUNCTIONS OF CASING STRINGS 702. CASING AND HOLE SIZES 703. CASING DESIGN CRITERIA AND DESIGN FACTORS 704. DECREASING IN THE CASING PERFORMANCE PROPERTIES 725. DRILLING PROGRAMME CONTENTS 76

PL. 2.11. DRILLING FLUIDS PROGRAMME 801. GENERAL 802. PRELIMINARY INFORMATION 803. GENERAL PARAMETERS FOR A MUD SYSTEM 804. SURFACE EQUIPMENT FOR TREATING & HANDLING MUD 815. CONTINGENCY PLANS FOR POTENTIAL HOLE PROBLEMS 826. SAFETY REQUIREMENTS 82

PL. 2.12. HYDRAULIC PROGRAMME 831. SOFT WARE 832. FLOW REGIME DEFINITION 833. FRICTION PRESSURE LOSSES CALCULATION 834. BIT NOZZLES SELECTION 845. DRILLING PROGRAMME CONTENTS 84

PL. 2.13. WELLHEAD 861. GENERAL SERVICE CONDITION (NO SOUR SERVICE) ONSHORE,

OFFSHORE JACK-UP & FIXED PLATFORMS WELLHEAD SYSTEM 86

2. MATERIAL 863. UNITISED WELLHEAD (COMPACT) 874. FLANGED WELLHEAD 87



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5. MATERIAL REQUIREMENTS 886. PRESSURE TESTS 897. DRILLING PROGRAMME CONTENTS 89

8. UNCONVENTIONAL WELLHEAD SYSTEM 899. SUBSEA WELLHEAD SYSTEM 89

PL. 2.14. WELL CONTROL 911. BOP SELECTION CRITERIA 912. EQUIPMENT REQUIREMENTS 913. BOP & CASING TESTS 924. TESTS FREQUENCY 955. DURATION OF TESTS 966. WELL CONTROL DRILLS 967. PRIMARY WELL CONTROL 978. SECONDARY WELL CONTROL 98

PL. 2.15. CEMENT PROGRAMME 99

1. PRELIMINARY INFORMATION 992. SLURRY DESIGN 993. SPACER DESIGN 1004. HYDRAULIC CALCULATIONS 1015. PLACEMENT TECHNIQUES 1016. DOWN HOLE EQUIPMENT SELECTION 1017. SURFACE EQUIPMENT SELECTION 1028. OPERATING PROGRAMME 102

PL. 2.16. DRILL STRING DESIGN 1041. DESIGN PARAMETERS 104

PL. 2.17. BIT SELECTION & DRILLING PARAMETERS 1081. FACTORS AFFECTING BIT SELECTION 108

PL. 2.18. EXPECTED DRILLING PROBLEMS & RECOMMENDATIONS 1101. DRILLING DIFFICULTIES 1102. SUGGESTIONS 1103. GENERALITIES 1104. LOSSES CIRCULATION 1105. DIFFERENTIAL STICKING 1116. CAVING HOLE 1127. HOLE RESTRICTION 1138. HOLE IRREGULARITIES 1139. HYDROGEN SULPHIDE GUIDELINES 114

PL. 2.19. WELL ABANDONING 118

1. GENERAL GUIDELINES 1182. TEMPORARY ABANDONMENT 1183. PERMANENT ABANDONMENT - PLUGGING 120

PL3. COMPLETION DESIGN 124

PL. 3.1. FUNDAMENTAL 1241. CONCEPTUAL DESIGN 1242. COMPLETION OBJECTIVES 1243. FUNCTIONS OF A COMPLETION 1254. RESEVOIR CONSIDERATIONS 1255. RESERVOIR/PRODUCTION FORECAST 126

PL. 3.2. RESERVOIR FLUIDS CHARACTERISTICS 1301. GENERAL 1302. OIL CHARACTERISTICS 130



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3. GAS CHARACTERISTICS 1304. GAS CONDENSATE CHARACTERISTICS 1315. SAMPLING 132

PL. 3.3. RESERVOIR ROCK CHARACTERISTICS 1331. GENERAL 1332. AREA OF INTEREST 1333. MAIN CHARACTERISTICS 1334. CORE ANALYSIS 134

PL. 3.4. EFFECTS OF RESERVOIR CHARACTERISTICS 1351. GENERAL 1352. DESIGN PARAMETERS 1353. COMPLETION DESIGN THROUGH FIELD LIFE 1354. NEAR WELLBORE RESTRICTIONS 1355. STRATEGY TO MINIMISE THE SKIN EFFECTS 1376. WELL INFLOW PERFORMANCE 138

PL. 3.5. TUBING PERFORMANCE 1411. GENERAL 1412. TEMPERATURE GRADIENT 1423. PVT DATA CALCULATION 1424. PVT PARAMETERS TO BE MATCHED 1435. VALIDATION 1446. LIMITS 1457. OPTIMUM TBG SIZE THROUGH FIELD LIFE 145

PL. 3.6. STRESS ANALYSIS 1461. GENERAL 1462. PARAMETERS 1463. CALCULATION METHOD 1484. SAFETY FACTOR 1495. OPERATIONAL CASES 1496. TBG - PACKER INTERACTIONS 1507. TUBING MECHANICAL PROPERTIES 151

PL. 3.7. MATERIAL SELECTION 1521. CORROSION GENERAL 1522. CORROSION CONTROL MEASURES 1563. MATERIAL SELECTION 1574. CORROSION MONITORING 1605. ELASTOMER SELECTION 1616. ELASTOMER PRACTICAL GUIDELINES 161

PL. 3.8. LIFTING DESIGN 1631. DEFINITION 1632. BASIC METHODS OF ARTIFICIAL LIFT 1633. SELECTIONCRITERIA 1634. ROD PUMPING 1665. GAS LIFTING 1676. ELECTRICAL SUBMERSIBLE PUMPING 1687. JET PUMPING 169

PL. 3.9. COMPLETION AND PACKER FLUIDS 1701. DEFINITIONS 1702. COMPLETION FLUID DUTY 1713. PACKER FLUID 1714. BRINE PROPERTIES 171

5. FORMATION INTERACTIONS 1726. BRINE FILTRATION 1737. FLUID LOSSES 174



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8. OIL BASE MUD 174

PL. 3.10. PACKERS 1751. DEFINITIONS 1752. SINGLE COMPLETION PACKER 1753. SINGLE SELECTIVE COMPLETION PACKER 1804. DUAL COMPLETION PACKER 1835. DUAL SELECTIVE COMPLETION PACKER 184

PL. 3.11. TUBING JOINT 1851. GENERAL 1852. JOINT SELECTION 185

PL. 3.12. TUBING SAFETY VALVE 1871. GENERAL NOTES 1872. SEALING SYSTEM 1893. APPLICATION 191

4. SELECTION CRITERIA 191PL. 3.13. ANNULUS SAFETY VALVE 192

1. GENERAL NOTES 1922. VALVE TYPES 1923. APPLICATION 1924. SELECTION CRITERIA 192

PL. 3.14. LANDING NIPPLES AND SLIDING VALVE 1941. TUBING HANGER NIPPLE 1942. INTERMEDIATE DOWN HOLE EQUIPMENT 1943. TAIL PIPE 1944. NIPPLES SELECTION 1945. GENERAL 194

6. WORKING PRESSURE 195

PL. 3.15. CHRISTMAS TREE 1961. GENERAL GUIDELINES 1962. PRESSURE RATING 1963. CONFIGURATION 1964. ACTUATORS 1975. MATERIALS 1986. SEALS 1987. TUBING HANGER 2008. TUBING HEAD ADAPTER SEAL FLANGE 200

PL. 3.16. WORKOVER AND COMPLETION PROGRAMME 2011. GENERAL 2012. PROGRAMME CONTENT 201



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PL1. PRELIMINARY

PL. 1.1. FEASIBILITY STUDY

1. NEW WELL Reference

1.1. The Drilling & Completion Department (D&C Dept.) obtain input datafrom the Exploration or Reservoir departments, relevant to:

• Location co-ordinates.

• Targets specifications.

• Reference to offset well information.

• Potential production.

1.2. The D&C Dept. evaluate all input data in order to be able to:

• Determine if any natural or artificial impediments may exist.

• Verify the environmental impact.

• Select the type of rig (Land, Jack Up or Floater).

• Determine the range of pore pressures, which may beencountered.

• Define the type of drilling fluid.

• Fix preliminary casing points and if necessary, also produce thecasing design.

• Establish a preliminary directional well plan in order to evaluatecollision risks.

• Plan the configuration of the well completion.

• Carry out an operations optimisation analysis (pre-drilling, earlyproduction, simultaneous production, etc.).

• Estimate expected time of operations.

• Estimate expected costs.

2. WELL RE-ENTRY Reference

2.1. Other additional information will be obtained, such as:

• Purpose of re-entry (reinstate production, workover, abandoning,

etc.).• Well history and status.

• Wellhead sketch.

2.2. In addition to the normal evaluations, some additional issues must betaken into consideration:

• Re-establishment of the location (onshore wells).

• The ability to approach existing platforms, cluster or single wells(offshore).

• Platform suitability to receive the selected rig.



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PL. 1.2. DRILLING & COMPLETION DEPARTMENT ACTIVITIES

1. DEPARTMENT RESPONSIBILITIES Reference

1.1. The D&C Dept. is activated by the Exploration Department(exploratory wells) or Project Manager (development wells).

1.2. The D&C Dept. obtain the following from the District GeologicalDepartment:

1.2.1. The ‘Geological Programme’ to include:

• Geological Framework

• Seismic Interpretation

• Source Rocks

• Sealing Rocks• Lithostratigraphic Profile

• Reference Wells

• Annexes and/or Figures

P-1-M-6100 16.4.2P-1-N-6001-E 7.2

1.2.2. The ‘Operational Geological Programme’ to include:

• Surface Logging

• Samplings

• Cuttings

• Bottom Hole Cores

• Side Wall Cores

• Fluids Sampling

• Logging While Drilling

• Wireline Logging

• Seismic Survey

• Wireline Testing

• Testing

• Studies And Drawings

• Reference Wells

• Annexes and/or Figures

P-1-M-6100 16.4.3P-12-N-6001-E 7.3



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1.3. The D&C Dept. inform the other departments in accordance with their functions:

• Authorisations & permits

• Budget cost centre opening

• Location preparation

• Contracts acquisition

• Means of transport selection

• Material supplies.

1.4. The D&C Dept. issue technical specification for the Drilling Rig.

1.5. The D&C Dept. activate its Engineering Section to prepare and

distribute the Drilling Programme.

P-1-M-6100 16P-1-N-6001-E 7.4

Reference List :

‘Drilling Design Manual’ STAP-P-1-M-6100

‘Operating Procedure for Drawing the “Well Drilling Program”’ STAP-P-1-N-6001E



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PL. 1.3. RIG SELECTION

1. TECHNICAL SPECIFICATIONS CONTENTS Reference

1.1. General data:

• Well name or activity name

• Foreseen date for starting activity

• Activity time

• Well number

• Job number

• Eni-Agip District

• Location

• RKB/sea level

• Distance from nearest house• Soundproofing required.

1.2. Type of well:

• Exploration wells

• Development wells

• Single wells

• Cluster wells

• Number of wells per cluster

• Vertical wells

• Deviated wells.

1.3. Wel l character is tics for r ig evaluat ion:

• Rig capacity with 5” DP:

• Hole diameter

• Hole depth

• Casing/liner diameter

• Casing/liner setting depth

• Casing/liner weight in air.

1.4. Type of mud predicted:

• If oil based mud predicted, adequate mixing system.

• Max predicted mud density.

• H2S predicted.

P-1-M-6140 6.4P-1-M-6100 5.8



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1.5. Wellhead for each type of well:

• Base flange• Type of flange for casing spool

• Type of flange for casing spool

• Type of flange for tubing spool

• Type of flange for tubing spool.

P-1-M-6140 15

Reference List :

‘Drilling Procedures Manual’ STAP-P-1-M-6140


‘Geological and Drilling Well Programme’ STAP-P-2-N-6001-E



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STAP-P-1-M-6090


PL. 1.4. AUTHORISATIONS AND PERMITS

1. GENERAL Reference

1.1. Authorisations, approvals and documentation necessary to operate inthe various Countries are usually substantially different and dependupon local laws and rules.

Each District / Affiliate have to issue a complete list, specifying thetype of documents and the competent authority.

1.2. Rig site:

All the authorisations and permits relative to the current activity shallbe available for inspection by any authorised personnel.

1.3. Well Area Department:

All the authorisations and permits relative to the current activity shallbe available for inspection by any authorised personnel.



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PL. 1.5. TECHNICAL DOCUMENTATION

1. RIG SITE Reference

1.1. Below is a list of the technical manuals and documentation that shallbe available on the rig site during any well operations:

1.1.1. 1. Dri ll ing And Completion Activit ies:

• Drilling Data Handbook - IFP

• Formulaire du Producteur - IFP.

• Composite Catalogue - WORLD OIL

• Drilling Design Manual - STAP-P-1-M-6100.

• Drilling Procedures Manual - STAP-P-1-M-6140

• Well Control Policy - STAP-P-1-M-6150

• Directional Control and Surveying Procedures - STAP-P-1-M-6100

• Drilling Fluids Handbook - STAP-P-1-M-6160

• Well Test Procedures Manual - STAP-P-1-M-7130

• Completion Design Manual - STAP-P-1-M-7100

• Completion Procedures Manual - STAP-P-1-M-7120

• Specific Technical and Operating Manual for each tool.

1.1.2. 2. Workover And Wireline Activities:

• Formulaire du Producteur - IFP

• Composite Catalogue - WORLD OIL• Well Control Policy - STAP-P-1-M-6150

• Completion Design Manual - STAP-P-1-M-7100

• Completion Procedures Manual - STAP-P-1-M-7120

• Wireline Procedures Manual - STAP-P-1-M-7110.

• Specific technical and operating manual for each tool.

2. DRILLING & COMPLETION DEPARTMENT Reference

2.1. The D&C Dept. of the District/Affiliate must have available andupdated all the technical manuals and documentation to be sent to rig

site.2.2. The D&C Dept. have to take care of the updating status of all the

Corporate Eni-Agip manuals sending request to the Drilling &Completion Standards Department or competent Units in Eni-AgipHeadquarters.

2.3. All technical reports regarding the current activity received from therig shall be filed in and then will constitute the ‘Official Well File’ inwhich all the relevant information, related to the well to be used for further well planning, can be found (see section RF ‘Reporting &Feedback’).



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PL. 1.6. MAIN CONTRACTORS

1. DRILLING CONTRACTOR Reference

1.1. Rig inspections:

1.1.1. The rig must be inspected by the Company before the operating dailyrate commences.

1.1.2. Any unconformity must be reported and rectified as soon as possible.

Any unconformity should be periodically reported to the Companybase Office.

1.2. Certification

1.2.1. The following certification shall be available on the rig site:

• Cranes

• Lifting equipment (blocks, brakes, links, etc..) inspection

• Handling equipment (pipe wrench, elevators, etc.) inspection

• Wire and cables

• Air winches (over 200kg pulling force)

• Tubular inspection

• BOP inspection

1.3. Registers1.3.1. The following registers shall be available at the rig site:

• Diesel

• Wire and cables

• Oils consumed

• Accident at work

• Personnel on site

• Emergency drills

• BOP and choke manifold tests.

1.3.2. The ‘Service Order’ system must be made aware to all personnelinvolved in operations.

1.4. Manuals

1.4.1. The following manuals shall be available on rig site:

• Safety manual

• Rig components and equipment manuals



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1.5. Procedures

1.5.1. Emergency procedures for major scenarios such as:• Fire/explosion

• Toxic material release

• Man overboard

• Well control

• Medical emergency

• Stability control

• Helicopter crash

• Rig evacuation

Must be documented and readily accessible at the rig site.

The Emergency Procedures must be readily accessible and madeaware to all supervisory personnel on the rig location.

Appendix ‘E’ DrillingContract ‘Drilling andWorkover safetyrequirements to becomplied with by theContractor’

1.6. Personnel Requirements

1.6.1. All Contractor Personnel at the work site must be fully trained andcurrently qualified for their job function in accordance with thefollowing minimum standards:

•••• Well control and Blow-out Prevention

The rig manager, toolpusher, driller, assistant driller, and subseaengineer (offshore rig), must posses a current certificate in wellcontrol and blow out prevention (biannual) issued by an industrytraining institute recognised by the Company.

• Fire fighting

All supervisory personnel should receive training in Basic FireFighting. In addition, those personnel assigned as members of afire team on offshore rigs should receive formal fire teamtraining.

•••• Survival at sea

All personnel working on an offshore rig must receive survival at

sea training given by an industry training institution recognisedby the Company.

• First aid

All supervisory personnel must possess a valid First AidCertificate.

•••• Hydrogen sulph ide

When drilling operations are to take place in an area where H 2Sis present or potentially a hazard, all rig personnel must undergotraining in the use of breathing apparatus and escape sets.

Appendix ‘E’ DrillingContract ‘Drilling andWorkover safetyrequirements to becomplied with by theContractor’



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1.6.2. Regularly scheduled safety meetings are required and every personhas to attend a safety meeting at least once per hitch (work cycle).

Each meeting must be documented, and the minutes must include alist of the attendees, topics covered, and any safety concerns raisedand the follow-up action to be taken. The minutes of each meetinghave to be passed to the Company Representative.

Appendix ‘E’ DrillingContract ‘Drilling and

Workover safetyrequirements to becomplied with byContractor”

1.6.3. Health certificates for all the personnel shall be available.

1.7. Personnel qualification

1.7.1. The Contractor’s organisation chart must be available on rig site.

1.7.2. The Contractor will certify that all personnel on duty are qualified for their job in accordance with the following minimum standards:

•••• Derrickman

One year as floorman and shall have attended courses ondrilling activities and drilling mud.

•••• Assistant Driller

Two years as derrickman and shall have attended courses ondrilling activities and have an adequate basic knowledge of all rigcomponents. He shall attend theoretical and practical Blowoutprevention courses every two years and obtain a Well Control

Certificate.•••• Driller

Two years as assistant driller and shall have attended courseson drilling activities and have an adequate basic knowledge of allrig components. He shall attend theoretical and practicalBlowout prevention courses every two years and obtain a WellControl Certificate.

•••• Tourpusher

Four years as a driller and shall have undertaken courses andexaminations for a toolpusher at a recognised educationalInstitute. He shall attend theoretical and practical Blow-outprevention courses every two years and obtain a Well ControlCertificate.

•••• Toolpusher

One year as tourpusher or four years as driller; as per tourpusher requirements and also have some years of educationin scientific or technical subjects. He shall attend theoretical andpractical Blowout prevention courses every two years and obtaina Well Control Certificate.

Appendix ‘A’ - section ‘B’‘Personnel to be providedby Contractor’



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• Rig Manager

Five years as a toolpusher or, if coming from years of educationin a scientific or technical field, a minimum of one years trainingafter a toolpusher course. He shall attend theoretical andpractical Blowout prevention course every two years and obtainthe Well Control Certificate.

• Captain or Barge Master

One year as barge engineer; he shall have attended courses inballast control buoyancy and stability. He shall hold years of education in a scientific or technical subject.

•••• Subsea Engineer

He shall have a through knowledge of, and extensive experiencein, the operation and maintenance of BOP, BOP control andsubsea equipment. He shall have attended appropriatespecialised courses on under water equipment. He shall attendtheoretical and practical Blowout prevention course every twoyears and obtain the Well Control Certificate.

He shall also have some years of education in a scientific or electric/electronic field.

1.7.3. Prior to start with operations, the ‘Curriculum Vitae’ of the Contractorsrig personnel shall be sent to the Company Base.

1.8. Accident reporting

1.8.1. An accident reporting procedure, consistent with local rules, must beinstituted. The Contractor must report all incidents occurring toContractor’s or ancillary contractor’s personnel, to the Company onthe day that the incident occurs.

The Contractor must provide the Company with a written report of theinvestigation into each such incident within seven days of theoccurrence.

Appendix ‘E’ DrillingContract ‘Drilling andWorkover safetyrequirements’

1.8.2. On the first work day of each month, the Contractor must provide the

Company with a monthly safety report which includes:• Number of personnel (rig site and support staff) assigned.

• Numbers of man-hours worked (rig site and support staff).

• Number of fatalities.

• Number of lost time accidents (LTA).

• Number of days away from work resulting from LTA.

• Number of no-lost time accidents.

• Number of near misses.

Appendix ‘E DrillingContract‘ Drilling and

Workover safetyrequirements’



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1.9. Permit To Work system

1.9.1. A ‘Permit to work procedure’ for operations such as hot work,concurrent operations, confined space entry and handling of radioactive materials must be in place.

Appendix ‘E’ DrillingContract.

1.9.2. The permit system must have a space for the entry of hazard(s)identified and the precautions to be implemented.

The ‘Permit to Work Procedures’ must apply to all personnel on therig site including the subcontractor’s and third party personnel.

2. MUD LOGGING Reference

2.1. Surface logging service

2.1.1. All paper recording shall be collected and filed day by day. A-1-SS-1722 3-b

2.1.2. Every sensor shall be independent from any other sensor alreadyexisting on the rig.

A-1-SS-1722 3-d

2.1.3. Each measurement system shall be equipped with automaticallyoperating visual and acoustic alarm.

A-1-SS-1722 3-e

2.1.4. Standard parameters shall be displayed and recorded in a doubledata base (function depth and time) with a clear indication of scale

and recorded data.

A-1-SS-1722 3-i

2.1.5. All geological and engineering data shall be loaded on softwarefurnished by the Company. The aim of this activity is the collection,QC and entry of well data into the Corporate DB

A-1-SS-1722 3-i

2.1.6. The contractor shall give engineering assistance. A-1-SS-1722 3-o

2.1.7. Contractor shall inform Company representative about any change of well conditions, especially for pit level, pressure and mud return fromthe well.

A-1-SS-1722 3-p

2.2. Operative service

2.2.1. The operating service, carry out on 24 hours basis, shall be requestwhen the Company needs geological surveillance and drilling servicewith a control of all parameters and recorded data.

A-1-SS-1722 3.1

2.2.2. A team of 4 (four) surface logger; 2 (two) of them can be junior; it isintended that a surface logger junior can be employed only if on therig there is in service a surface logger senior

A-1-SS-1722 3.1



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2.3. Reduced service

2.3.1. The company could require a ‘Restricted Service’ that shall have, atleast, the following configuration:

• 1 (one) surface logger senior

• Surface Logging unit and relevant equipment

• Gas detector

• Degasser

• Standpipe pressure

• Pump stroke

• Hook load

• Mud pit level• Hook movements.

A-1-SS-1722 3.2

2.3.2. Stored data shall be available in ASCII format if requested A-1-SS-1722 3-g

2.4. Mud logging unit

2.4.1. The unit, installed above a skid and in compliance with local laws,shall be equipped with a no break generating set able to supplyelectric power for at least for 15 minutes; Contractor shall specify themaximum length, breadth, height and maximum weight.

A-1-SS-1722 4.1-b

2.4.2. All equipment must be intrinsically safe and explosion proof. A-1-SS-1722 4.1-c

2.4.3. Recommended spare parts and a complete set of spare sensors shallbe always available in the Unit for a prompt intervention by on siteContractor personnel, in case of a possible malfunction besides, incase of major malfunctioning, the Contractor shall provide for theimmediate replacement of the faulty equipment

A-1-SS-1722 4.1-f

2.4.4. Mud logging unit shall be pressurised.

2.5. Personnel

2.5.1. A Senior Surface Logger is required to have a minimum of threeyears experience working on surface logging service company

A-1-SS-1722 2.1

2.5.2. A Junior Surface Logger is required to have a minimum of one year experience working on surface logging service company.

A-1-SS-1722 2.1



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2.5.3. Senior Surface Logger and Junior Surface Logger:

• ‘Well control course’ issued by Company IWCF approved.• ‘Survival course’ (for offshore activity) issued by Companyapproved.

A-1-SS-1722 2.1

2.5.4. Personnel qualification cards shall be duly and accurately filled in(Annex 9.3), and full details on courses attended, and certificatesshall be provided.

A-1-SS-1722 2.3

2.6. Radioactive sources

2.6.1. In absence of local lows or regulations the following criteria could bea Worldwide guideline:

1. Certification to able the use of radioactive sources released fromcompetent authority

2. Particulars of the deputy “Qualified Expert” or his representative

3. Radioactive safety detailed report drawn up by Qualified expert

4. Procedure to adopt in case of tools failure

5. Particulars of the “Qualified Doctor” for the Medical Surveillance

6. Statement that the radioactive source operative activity will beperformed by suitable personnel with medical examinationperformed in the last 6 months

7. Classification of personnel in terms of radioactive exposure.

8. Declaration stating that land transports are carried out using

vehicles owned by Contractor

Policy for to perform operations by radioactive sources

3. MUD SERVICE, CHEMICAL SUPPLY, CENTRIFUGES RENTAL Reference

3.1. Personnel

3.1.1. Senior Fluid Engineer is required to have a minimum of 5 (five) yearsfield experience as Fluid Engineer.

A-1-SS-1719 4.1

3.1.1.1. He shall be in possession of the following certificates:

• ‘Mud engineer course’• ‘Completion fluid course’

• ‘Survival course’ (for offshore activity) issued by approvedCompany

• ‘Basic well control course’ IWCF or IADC Wellcap approved

A-1-SS-1719 4.1



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3.1.2. Fluid Engineer is required to have a minimum of one years fieldexperience as Fluid Engineer.

A-1-SS-1719 4.2

3.1.2.1. He shall be in possession of the following certificates:

• ‘Mud engineer course’

• ‘Completion fluid course’

• ‘Survival course’ (for offshore activity) issued by approvedCompany

• ‘Basic well control course’ IWCF or IADC Wellcap approved

A-1-SS-1719 4.2

3.1.3. Technical Supervisor is required to have a minimum of eight yearsfield experience as Fluid Engineer.

A-1-SS-1719 4.3

3.1.4. Laboratory technician is required to have at minimum three yearsexperience in laboratory test as per API RP 13I “Standard Procedurefor Laboratory Testing Drilling Fluid” and as per API RP 13J ‘TestingHeavy Brines’

A-1-SS-1719 4.4

3.1.5. During the activity, the Contractor shall supply the followingdocumentation:

• Fluid program (if requested)

• Daily mud report.

• End phase mud report.

• Final well mud report.

A-1-SS-1719 6

3.2. Mud chemicals identif ication

3.2.1. For each product , contractor shall furnish the following informations:

• Commercial name

• Chemical name and composition

• Products classification

• Product application and recommended concentration

• Type of packing (sacks, drums etc.)

• Material safety data sheet.

A-1-SS-1719 5.5

3.2.2. Contractor shall also inform of any possible danger in using theproducts offered (HSE information).

A-1-SS-1719 5.5



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3.3. Equipment

3.3.1. Contractor shall have the availability, when needed a specifictechnical support, of a laboratory able to perform tests according with API RP 13B-1, 13B-2 (Standard Procedure for Field Testing DrillingFluids) and with API RP13I-2 (Standard Procedure for LaboratoryTesting Drilling Fluids).

A-1-SS-1719 5.3

3.3.2. The main performance request is:

• ‘G’ factor up to 3.000

• must be able to work on 5 microns size solids

• high speed

• must be able to treat up to 18m

3

/h• RPM up to 3.300

3.3.3. On request, Contractor must be able to provide centrifuges withindependent generator.

A-1-SS-1719 5.4.1

3.3.4. Nothing shall relieve the contractor of the responsibility for performingsuch analysis, tests, inspections and other activities that he considersnecessary to ensure that the product, and workmanship aresatisfactory for the service intended, or as may be required bycommon usage or good practice.

A-1-SS-1719 3

4. CEMENTING SERVICE Reference

4.1. Engineering

4.1.1. The contractor shall provide an adeguate service for engineeringsupport which shall include the following duties:

A-1-SS-1729 5.1

4.1.2. • Drawing up of cement slurry programmes

• Supplying all the laboratory equipment necessary for testingslurries, spacers and API tests on chemical products includingquality control on cement,

• Computer monitoring for cementing operations, real time

acquisition of data (delivery, pressure, density) for the possibleof a subsequent processing of the data recorded,

• Drawing up of reports concerning the works carried out andrelevant evaluation.

• Drawing up a final well report.

A-1-SS-1729 5.1



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4.2. Personnel

4.2.1. The Contractor shall supply professional curricula for all personnel heintends to use, indicating background, training and work experience.

A-1-SS-1729 5.2

4.2.2. All personnel involved in offshore operations shall hold a survival atsea certificate issued by a Company-approved Organisation or Institute.

A-1-SS-1729 5.2

4.2.3. An operator is required to have a adeguate skill acquired through anappropriate training course and with at least five years of fieldexperience

A-1-SS-1729 5.2.1

4.2.4. Helper is required to have an adequate skill acquired through anappropriate training course.

A-1-SS-1729 5.2.2

4.2.5. Contractor will guarantee availability of a technical supervisor from abase close to the area of operation.

A-1-SS-1729 5.2.3

4.2.6. Contractor shall provide a laboratory technician to perform therequired tests on cement, cement additives and cement slurry.

A-1-SS-1729 5.2.4

4.3. Equipment

4.3.1. The design of equipment and units shall ensure safety operations. A-1-SS-1729 5.3

4.3.2. Cement Pumping Unit must be provided with:

• Twin triplex pumping units for pumping the cement slurry.

• The pumping unit working pressure shall be 10,000 psi and 500HHP.

• The engines will be equipped with spark arresting air filters andair inlet shut-off valve

• The unit shall include two displacement tanks of 1,500/1,600litres capacity each.

• The tanks will be provided with appropriate level gauges

calibrated in liters.• Cement pump pressure gauge 15,000 psi fitted with a pre-selectpump cut out system.

A-1-SS-1729 5.3.1

4.3.3. Recirculation Mixing System shall grant mixing of the cement slurryand its recirculation before it is pumped into the well.

It will include a 1,300-1,500ft basin divided into two parts, eachsupplied with a mixer.

A-1-SS-1729 5.3.2



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4.4. Batch Mixer shall grant the ‘surface’ mixing of determined quantitiesof cement slurry, spacers and/or other fluids. It will consist of tanks of

capacity ranging from 3 to 30m3, each one self sufficient, providedwith agitators, centrifugal pump and gauge to measure the pumpedquantities.

A-1-SS-1729 5.3.3

4.5. Documentation

4.5.1. Contractor will prepare and submit for approval, before the executionof each service, a detailed ‘Operations Program’.

A-1-SS-1729 6.2

4.5.2. After the execution of the service, Contractor shall provide toCompany Operations a ‘Job Report’

A-1-SS-1729 6.3

4.5.3. At the end of the operations, Contractor shall prepare the final reportwhich shall include all the ‘Job Report’, ‘Operation Program’ and finalconsiderations and suggestions, reason for the deviation from theprogram

A-1-SS-1729 6.4

Reference List :

‘Standard Specifications for Drilling and Completion Fluid Services’ STAP-A-1-SS-1719

‘Technical Specifications for Surface Logging’ STAP-A-1-SS-1722

‘Cementing and Pumping Service for Drilling Completion and Workover Activity’ STAP-A-1-SS-1729

‘Drilling Contract ‘Drilling and Workover safety requirements. Appendix ‘E’’

‘Drilling Contract ‘Personnel to be provided by Contractor. Appendix ‘A’ section ‘B’



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PL. 1.7. ESTIMATED COSTS

1. BUDGET Reference

1.1. The Well Area Department, requested by the ‘Project’ or ‘ExplorationManager’, will make cost estimation of the planned well (based on thebest information available at the time), this will be inserted into the yearlybudget.

2. COSTS Reference

2.1. Before starting the activity, the Well Area Department, requested by the‘Project’ or ‘Exploration Manager’, will make a cost estimation of theforthcoming well. It will be split by class of cost, based on the progresschart included in the drilling (or completion, or workover) program, on theselected rig rates and on the other acquired contracts.

2.2. The Estimated Cost shall include:

• Materials (casings, wellhead, mud, etc.)

• Services (contractors)

• Standard costs (supply vessels, helicopters, transports, etc.)

• Logs (from District Geological Department)

• Supervision and operative base costs.

2.3. ‘Project’ or ‘Exploration Manager’, after receiving the Estimated Cost, willcheck the conformity with the original budget (at this point a budget

revision may be made) and will start the procedure for the Job centreopening.

2.4. After Job Centre opening the Estimated Costs can be input in S3C (if available)

2.5. Draw-up a Progress Cost Chart (depth versus cost) and follow up theactual daily costs comparing the same with the previously estimatedcosts, in order to evaluate the activity performance.

2.6. Follow up daily and cumulative costs and compare with budget.



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PL2. GEOLOGICAL AND DRILLING WELL PROGRAMME

The purpose of this document is to provide general guidelines in order to correctly plan a welland prepare a proper Geological and Drilling Well Programme.

It gives the ‘best practices’ covering all aspects in planning a well, in an orderly sequence of steps that must be followed when a Geological and Drilling Well Programme is beingprepared.

The Geological and Drilling Well Programme defines the objectives/targets of the well, reportsthe basic engineering data, specifies equipment and procedures necessary to drill safely awell, provides a realistic forecast of its final cost.

The last column in the document indicates the available reference documents covering theparticular topic.

The list of reference documents and available computer programmes are reported at the endof each section.

Continuous references to operating document sections are necessary for further investigationby the user.



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PL. 2.1. GEOLOGICAL AND DRILLING WELL PROGRAMME STRUCTURE

1. NUMBER OF THE SECTIONS Reference

1.1. The ‘Geological and Drilling Well Programme’, from now on definedas ‘G&DWP’, comprises of four sections:

• GENERAL INFORMATION (Section 1)

• GEOLOGICAL PROGRAMME (Section 2)

• OPERATION GEOLOGY PROGRAMME (Section 3)

• DRILLING PROGRAMME (Section 4)

P-1-M-6100 16P-2-N-6001E(introduction)

1.2. The G&DWP will be drawn in accordance with local regulations, andENI Agip District or affiliate internal rules, taking into account:

1. IGUs Operation Geology Procedures (Specific Agip Rules Nr.

1.4.15.3-8; Procedure Di Geologia Operativa Vers. 0.0 07/94GESO)

2. FGUs Subsurface & Operation Geology Procedures.

3. STAP-P-1-M-6060 (Best Practices and Minimum Requirementsfor Drilling & Completion Activities) and all the documentsconcerning the planning and execution of the well, cited in thesame BP&MR.

4. Operative Procedure for drafting the Well Drilling Programme,STAP-P-1-N-6001E

5. Procedures for well seismic acquisition

6. Procedure for the location of offshore and onshore wells

7. Local law and legislative decrees8. Well Name Designation

9. Rules for Management and Control of Technical Documents

10. Standardisation of documents

P-1-M-6100 16P-2-N-6001E(introduction)

2. PRINT MODEL Reference

2.1. Whenever Microsoft Office products are available in the Eni Agipdistricts or Affiliates, for preparing each section of the ‘G&DWP’’, it isrecommended to use the model built in “WORD 6”, titled‘WLPR_ING.dot’

P-1-M-6100 16P-2-N-6001E 1

2.2. The four sections composing the G&DWP’, are identified by the nameof the well.

P-1-M-6100 16

P-2-N-6001E 3

2.3. In order to make the Well Drilling Programme easily manageable’either in E-Mail or with shared network disks, the graphicrepresentations must be in an electronic format

P-1-M-6100 16P-2-N-6001E 5

Reference List :


‘Operative Procedure for Preparing the Geological and Drilling Well Programme’ STAP-P-2-N-6001E



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PL. 2.2. GENERAL INFORMATION (SECTION 1)


1.1. This section will be written in close co-operation by the Drilling &Completion and Subsurface Geology Departments of the Affiliate.

P-1-M-6100 16P-2-N-6001E 7.1

1.2. All depths, both for offshore and on-shore wells must be referred tothe Rotary Table.

P-1-M-6100 16P-2-N-6002E 7.1

1.3. Section 1 comprises the chapters numbered and titled as follows:

1.1. GENERAL WELL DATA

1.2. WELL TARGET

1.3. GENERAL RECOMMENDATIONS

1.4. GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND SAFETY EQUIPMENT

1.5. LIST OF THE MAIN CONTRACTORS

1.6. CONTACTS IN CASE OF EMERGENCY

1.7. REFERENCE MANUALS

1.8. MEASUREMENT UNITS

P-1-M-6100 16P-2-N-6001E 7.1

2. GENERAL WELL DATA Reference

2.1. The ENI Agip District or Affiliate’s Drilling & Completion Department

will give the Well Profile, the Time Vs Depth Diagram, and theLocation Layout.

P-1-M-6100 16P-2-N-6001E 7.1.1

2.2. Identificative Well Data

2.2.1. • Affiliate or District in charge

• Name and acronym of the well

• Initial classification (LAHEE)

• Expected Final depth

• Permission/concession

• Operator

• Older of the Permit/ Lease (shares specified as %)• Municipal Authority (on-shore wells)

• Province (on-shore wells)

• Harbour-master office (off-shore wells)

• Zone (off-shore wells)

• Distance Rig/coast (off-shore wells)

• Distance Rig/operative base

• Altitude (on-shore wells)

• Sea Depth (off-shore wells)

P-1-M-6100 16P-2-N-6001E 7.1.1



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2.3. Well Profile

2.3.1. The Well Profile contains a Table showing, against the depth (totalvertical depth), at least the following data:

• Pore pressure gradient

• Formation fracture gradient

• Overburden gradient

• Mud weight

• MAASP

• Max differential pressure

• Drilling balance pressure

• Casings setting depth• Static temperature gradient

2.3.2. Diagram showing all above information, including expected lithology.

3. GENERAL RECOMMENDATIONS Reference

3.1. Will be written in close co-operation between the Drilling &Completion and Subsurface Geology Departments.

P-1-M-6100 16P-2-N-6001E 7.1.3

3.1.1. LWD operation joint Considerations:

• The more suitable tools.

• Their positioning in the BHA.

• The drilling parameters to be used.

• The stabilisers are correctly positioned in the BHA, according toLWD tools.

• The maximum admissible flow through the LWD tools must notbe exceeded, otherwise substantial erosion damage will occur inside the tool.

• Limiting the solid content in the mud in order not to exceed theLWD tools limitations.

P-1-M-6140 13.1.2

3.1.2. To highlight the possible operative problems envisaged P-2-N-6001E 7.1.3

4. GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND

SAFETY EQUIPMENT

Reference

4.1. Contains the information of Tables PL.02.02-1 and PL.02.02-2 P-2-N-6001E 7.1.4.1P-2-N-6001E 7.1.4.2

5. LIST OF THE MAIN CONTRACTORS Reference

5.1. Will be written by the Affiliate’s Drilling & Completion Department inco-operation with the Subsurface Geology Department.

P-1-M-6100 16P-2-N-6001E 7.1.5



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6. CONTACTS IN CASE OF EMERGENCY Reference

6.1. Will be written by the ENI Agip District or Affiliate’s Drilling &

Completion Department and shows:1. The ‘flow chart’ of emergency contacts

2. The telephone numbers of the people in charge of theemergency.

P-1-M-6100 16P-2-N-6001E 7.1.6

7. REFERENCE MANUALS Reference

7.1. Will be written by the ENI Agip District or Affiliate’s Drilling &Completion Department. It consists of a list of basic manuals to bereferred for planning and implementation phases of the well.

P-1-M-6100 16P-2-N-6001E 7.1.7

8. MEASUREMENT UNITS Reference

8.1. Will be written in strict co-operation between the ENI Agip District or Affiliate’s Drilling & Completion and Subsurface GeologyDepartments. It will contain a list of the units of measurement of themain parameters used in the Geological Operation and Drillingsections.

P-1-M-6100 16P-2-N-6001E 7.1.8

9. SIGNATURE Reference

9.1. The names and signatures of the technicians and managers involvedin the preparation and control of the section will always be specified.

P-1-M-6100 16P-2-N-6001E 7.1.9

Reference List :



‘Operative Procedure for Preparing the Geological and Drilling Well Programme’ STAP-P-2-N-6001E



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ITEM DESCRIPTION

Contractor

Rig name

Rig type

Rotary table elevation on ground level Only on-shore rigs

Rotary table elevation on sea level Only off-shore rigs

Number of places available Only off-shore rigs

Power installed

Drawwork Type

Rig potential with 5” DP’s

Max. operative water depth Only off-shore rigs

Clear height rotary beams/ground level Only on-shore rigs

Top Drive System type

Swivel assembly working pressure If without Top Drive System

Dynamic hook load

Set back capacity

Deck load Only for semisub rigs

Total load Only for semisub rigs

Rotary table diameter

Rotary table capacity

Stand pipe working pressure

Mud Pumps number and type

Available liner size

Total mud capacity

Shaleshaker number and type

Drinking water storing capacity Only for off-shore rigs

Industrial water storing capacity

Gasoil storing capacity

Barite storing capacity

Bentonite storing capacity

Cement storing capacity

Table PL 2.1 - Rig Characteristics



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ITEM DESCRIPTION

Diverter type

Diverter size

Diverter working pressure

BOP stack type

BOP size

BOP working pressure

Choke Manifold size and working pressureKill Lines size and working pressure

Choke Lines size and working pressure

BOP Control Panel type

BOP Control Panel location

Inside BOP type

Inside BOP location

Table PL 2.2 - BOP Stack and Safety Equipment



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PL. 2.3. LAYOUT OF THE DRILLING PROGRAMME (SECTION 4)

1. BASIC REQUIREMENTS Reference

1.1. The Drilling Program must accomplish with basic requirement setforthin the Geological Program in terms of total depth, targets andreservoir specified needs.

P-1-M-6100 16P-1-N-6001E 6

1.2. Particularly, paragraphs 4.2.1 (Forecast on pressure and temperaturegradients) and 4.2.2 (Drilling problems) will be made in co-operationbetween Drilling & Completion and Geology District/AfiiliateDepartments

P-1-M-6100 16P-1-M-6100 16.4.4

1.3. All depths, both for offshore and on-shore wells must be referred tothe rotary table. If the rotary table elevation is not yet available, it willbe assumed based on past experiences with similar drilling rig types

P-1-M-6100 16P-1-N-6001E 6

1.4. Section 4 will comprise the sub-sections numbered and titled asfollows:

List of contents:

4.1 OPERATIVE SEQUENCE

4.1.1. Preliminaries

4.1.2. Conductor pipe phase

4.1.3. Surface hole phase

4.1.4. Intermediate phases

4.1.5. Final phase

4.1.6. Testing4.1.7. Completion

4.1.8. Well abandoning

4.3 WELL PLANNING

4.2.1. Pressure and temperature gradients forecast

4.2.2. Drilling problems

4.2.3. Casing setting depths

4.2.4. Casing design

4.2.5. Mud programme

4.2.6. Cementing programme

4.2.7. BOP4.2.8. Wellhead

4.2.9. Hydraulic programme

4.2.10. B.H.A. and stabilisation

4.2.11. Bits and Drilling Parameters

4.2.12. Well trajectory (directional drilling plan)

Annexes and/or figures

P-1-M-6100 16P-1-N-6001E 6.1



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1.5. The Drilling Programme index and numbering of sections must be laiddown as shown above; whenever a topic is not applicable to the

actual programme, the relevant sections/paragraphs shall be markedwith ‘not applicable’.

P-1-M-6100 16P-1-N-6001E 6.1

Reference List :


‘Operating Procedure for Drawing the ‘Well Drilling Programme’’ STAP-P-1-N-6001E



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REVISION

STAP-P-1-M-6090


PL. 2.4. OPERATIVE SEQUENCE (SECTION 4)

1. PRELIMINARY INFORMATIONS Reference

1.1. It will detail operations to be undertaken before the spud-in. P-1-M-6100 16

2. CONDUCTOR PIPE PHASE Reference

2.1. The following information must be provided:

1. Driven conductor pipe:

• Type of Pile Hammer

• Diameter of the CP

• Weight of the CP

• Steel grade of the CP

• Connection Type• Expected driving depth

• Refusal point (1,000 strokes/m)

• Remarks/off-set driving data if available

2. Drilled conductor pipe:

• Diameter of the bit

• Drilling procedures for hole cleaning

• Final phase depth

• Diameter of the CP

• Weight of the CP• Steel grade of the CP

• Connection type

• Cementing procedures

• Remarks

P-1-N-6001E 6.2.2



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3. SURFACE PHASE Reference

3.1. The following minimum information must be included:• Description of difficulties and reference to a specific paragraph

for further details

• Description of shallow gas, anticollision procedures (if applicable)

• Hole size and other requirements (hole opened-underreamed)

• Measured shoe depth and, (if applicable) vertical depth at theend of the phase

• Diameter, steel grade and weight of the casing

• Brief description of operations (drilling, casing run, cementing)

• Mud type and density and their adjustment for the entire phaselength

• Survey and directional drilling requirements, if any

• Well head test pressure value

• Diverter/BOP stack installation

• Remarks

P-1-N-6001E 6.2.3

4. INTERMEDIATE PHASES Reference

4.1. The following minimum information must be included:

• Description of difficulties and reference to a specific paragraph

for further details• Reference to anticollision procedures (if applicable)

• Hole size and other requirements (hole opened-underreamed)

• Measured depth and, (if applicable) vertical depth at shoe depth

• Eventual coring requirements and logging programme

• Diameter, steel grade and weight of the casing or liner

• Estimated fracture gradient below the previous casing shoe

• Requirements for FIT. or LOT. (if applicable)


• Mud type and density and their adjustment for the entire phase

length• Survey and directional drilling requirements, if any

• Hanging casing in well head (with or without overpull)

• Value of the liner head seal test pressure (if applicable)

• Casing and well head test pressure value

• BOP stack test

• Remarks

P-1-N-6001E 6.2.4



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5. FINAL PHASE Reference

5.1. The following information is included:

• Description of difficulties and reference to a specific paragraphfor further details

• Reference to anticollision procedures (if applicable)

• Hole size and other requirements tied with drilling operations intarget/reservoir (e.g. target details, eventual use of nondamaging fluids, depth of multiple targets, etc.)

• Vertical and measured total depth


• Eventual requirements for coring and/or testing operations

• Logging programme

• Diameter, steel grade and weight of the casing or liner • Estimated fracture gradient below the previous casing shoe

• Requirements for FIT or LOT (if applicable)

• Mud type and density and their adjustment for the entire phaselength

• Survey and directional drilling requirements, if any

• Hanging casing in well head (if applicable, with or withoutoverpull)

• Hanging of liner and liner head seal test pressure (if applicable)

• Casing and well head test pressure values

• BOP stack test• Remarks

P-1-N-6001E 6.2.5

6. TESTING Reference

6.1. On the basis of information available during the planning phase thisparagraph should describe operations related to the well testing.

P-1-N-6001E 6.2.6

7. TYPE OF COMPLETION Reference

7.1. On the basis of information available during the planning phase, thisparagraph should describe the sequence of operations and maininformation on the type of the foreseen completion.

P-1-N-6001E 6.2.7



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8. WELL ABANDONMENT Reference

8.1. On the basis of information available during the planning phase setsout a programme for well abandoning, describing the operations toperform for the abandonment (temporary or permanent) of the well,including the following minimum information:

• Open hole abandonment procedures

• Tested intervals perforations squeeze-off procedures

• Temporary abandonment of opened producing intervals

• Setting of bridge plugs - cement retainers

• Sequence and height of cement plugs and their eventual testing

• In-hole fluids characteristics

• Eventual temporary completion/killing string composition• Eventual casing cutting and recovery specifications

• Well head/mud line temporay abandonment/recovery

• Surface restoration, if any.

P-1-N-6001E 6.2.8

Reference List :





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PL. 2.5. SOFTWARE (SECTION 4)

1. STANDARDS Reference

As concerns:

• Analysis of pressure and temperature gradients

• The casing point,

• Choke margin and differential pressure,

• Casing design,

• Hydraulic programme,

• The design and control of directional drilling.

Reference should be made to the use of calculation models and formatsof the IWIS system if available.

P-1-N-6001E 6.3

2. ALTERNATIVES Reference

2.1. COMPASS for the design of directional drilling and anticollision analysisfor wells.

P-1-N-6001E 6.3

2.2. Concerning the evaluation of stresses induced:

• In the drilling string,

• In casing and liners

Estimates can be derived from Maurer Engineering Inc.’s Torque & Drag -Casing Wear software.

P-1-N-6001E 6.3

2.2.1. These evaluations must be run for all the deviated/deep wells and dulychecked for calibration while drilling.

P-1-N-6001E 6.3

Reference List :




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PL. 2.6. PRESSURE GRADIENTS PROGNOSIS (SECTION 4)

1. PRELIMINARY DATA COLLECTION Reference

1.1. Geological data

1.1.1. Structure map.

1.1.2. Lithological column.

1.2. Seismic data

1.2.1. Seismic data can be used to estimate the formation pressure andgive an indication of any pore pressure abnormalities. In all cases, itmust be considered an approximate solution.

P-1-M-6130 3.6

1.2.2. Offshore seismic data1

can be used to determine the possiblepresence of shallow gas.

P-1-M-6130 3.6

1.2.3. Seismic data are usually given as vertical average velocity (RMS-velocity, m/s), Vs ‘two way travel time’ (10

-3sec), for a single

CDP2(Common Depth Point).

P-1-M-6130 3.6

1.3. Offset /reference well data

1.3.1. Drilling records - Drilling reports:

The drilling parameters, the recording and interpretation of which only

give a qualitative evaluation of overpressure (i.e., its possiblepresence and the location of its top), include the following:

• Drilling rate

• Torque

• Overpull

• Caving and hole tightening

• Pump pressure and flow rate

• Level in mud pits

• Amount of cuttings at shale-shaker

• Mud pH and resistivity• Resistivity of shales collected at shale-shaker

• Amount of gas present (gas shows)

• Mud temperature

• Montmorillonite percentage.

ARPO-02/AP-1-M-6130 4.1

1 In this case, a high resolution seismic is performed, which usually investigates formations down to 500 meters depth below the

seabed.2 When the relative position of the shot points and geophone locations are known, is possible to identify a series of seismic traces

that are reflected from approximately the same position on reflecting bed, this position is known as common depth point (CDP).



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1.3.2. Drilling records - Mud logs:

• lithology of formations drilled• gas shows

• mud weights

• ROP

• drilling parameters

• bit records

• formation temperature

• other relevant parameters (torque, mud temperature, etc.).

P-1-M-6130 4.2

1.3.3. Leak off tests/FIT data, recorded in terms of equivalent mud weight. P-1-M-6140 11

1.3.4. Wireline or LWD logs:

• Resistivity (induction)

• Sonic

• Density.

P-1-M-6130 5.2

1.3.5. RFT/DST data.

The repeat formation test (RFT), and drill stem testing are directmeasurements that provide accurate information on pressure values.

P-1-M-7130

1.3.6. Interpreted formation pressure profile.

Wireline logs interpretation, sigmalog or similar.

P-1-N-6001E 6.3.1

2. DEFINITIONS Reference

2.1. Kick tolerance volume

2.1.1. Kick tolerance is the term used to define the maximum kick volumewhich can be safely controlled by any well control method withconstant BHP without fracturing the formation below the last casingshoe. The most dangerous situation is when the top of the kickreaches the casing shoe.

P-1-M-6110 2.2

2.1.2. Kick tolerance volume at total depth: (hypothesis vertical well)

( )[ ] ( ) ( )

[ ][ ]

[ ]

[ ][ ] gradient(gas)influxS.G.G

depthtotal mH

weightmud l

kgG

depthtotalatpressureformation cm

kgPdepthshoe mH

shoeatgradientfractureformation 10m

kg/cmG

shoethebeneathcapacityannular m

lC

mV

GG

P 10G HGG H

P

HGC V

g

m

2ps

2

fs

a

3Hi,

gm

pmmfss

p

s fs a4Hi, 10

==

=

==

=

=

=−

−+−=

−

P-1-M-6110 12.2



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2.2. Leak off tests (LOT)/Formation Integri ty Tests P-1-M-6140 11

2.2.1. A Leak-Off Test (LOT) will be performed On Wild-Cat wells at eachcasing shoe after setting the surface casing. LOTs are alsorecommended to be carried out on both appraisal and developmentwells.

P-1-M-6140 11

2.2.2. Leak Off Tests and Formation Integrity Tests (FIT), also termed theLimit Test, are for formation strength pressure tests made just belowthe casing seat prior to drilling ahead.

P-1-M-6140 11

2.2.3. Record and plot pressure values vs. cumulative volume (bbls,1/4 bbl

scale), pumping at1/2bpm constant rate in 17

1/2” (16”) hole sections

and1/4 bpm in 12

1/4” hole sections.

P-1-M-6140 11

2.2.4. LOT pressure doesn’t exceed the pressure to which the casing wastested.

P-1-M-6140 11

2.2.5. Stop pumping when a deviation from linear trend is recorded (two or three points).

Pump uniform volumes of mud and wait for the pressure to stabilise.Flow rates range from

1/8 bbl/min (20l/min) up to a maximum of

1bbl/min (160 l/min), however values of 0.25bbl (121/4” and smaller

holes) or 0.50bbl (171/2” hole) are commonly used. Wait for two

minutes, or the time required for the pressure to stabilise.

P-1-M-6140 11

2.2.6. The leak off point is the last point on the straight line.P-1-M-6140 11.1

2.2.7. When stop pumping, allow the pressure to stabilise: standingpressure.

P-1-M-6140 11.1

2.2.8. Calculate the formation strength in terms of ‘Equivalent Mud Weight’using the lowest between leak off point pressure and stabilisedpressure.

P-1-M-6140 11.1.

2.2.9. LOT/FIT Test procedure. P-1-M-6140 11.1



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2.3. Fracture gradient P-1-M-6130 2.1.5.

2.3.1. Equations used by the Company for fracture gradient calculation,once overburden gradients and pore pressure gradients have beendefined are:

When dealing with elastic formations, the fracture gradient Gfr isobtained by an equation derived from the more general Terzaghiequation:

Terzaghi equation:

( )povpfr GG

1

2GG −

ν− ν+=

If the drilling fluid is water or wherever water deeply invades theformation, Gfr is given by:

povpfr GG2GG − ν+=

With plastic formations, such as clays, marls, etc.:

ovfr GG =

Gfr = fracture pressure gradient.

Gov = overburden gradient.

Gp = formation pressure gradient.

ν = Poisson’s module

P-1-M-6130 2.1.5.

Equation 2.18

Equation 2.19

Equation 2.20

2.3.2. The Poisson’s modulus may have the following values:

ν = 0.25 for clean sands, sandstone and carbonate rocks down tomedium depth.

ν = 0.28 for shaly sands, sandstone and carbonate rocks at greatdepth.

P-1-M-6130 2.1.5.

3. PRESSURE GRADIENTS PREDICTION & EVALUATION Reference

3.1. Seismic data

3.1.1. The seismic data transformed, in accordance with what has beendiscussed above, in terms of depths, interval velocities and/or intervaltransit times, at this point are ready to be used for pressure gradientcalculation, that is of:


• Pore pressure gradient

• Fracture gradient.

P-1-M-6130 3.6.2



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3.1.2. Two methods of analysis of the data can be applied; these are:

1. Plotting of ‘Interval Velocity versus Depth’ or, more commonly,‘Interval Transit Times versus Depth’ graphs;

2. Method of ‘Interval Velocity/Theoretical Velocity Ratio, V1/V2’.

P-1-M-6130 3.6.2

3.1.3. The first purpose of interpretation is to determine ‘interval transit time3

(ITT)’ trend. The normally pressurised shales will be plotted as atrend line on depth vs. ln (ITT) graph. An increase in ITT values awayfrom the trend line will indicate the presence of abnormal pressures.(A draw back in using this method is the difficulty of determining thecorrect trend line.)

P-1-M-6130 3.6.2

3.1.4. The second step of interpretation is the pressure gradient

calculations:


• Pore pressure gradient, calculation is based on equivalent depthmethod

• Fracture gradient.

3.2. Wireline logs

3.2.1. Induction and sonic logs are used to identify any deviation from thenormal compaction trend. The pressure transition is usually clearlyindicated by increased conductivity and sonic transit time.

P-1-M-6130 5.2

3.2.2. Sonic log

3.2.2.1. Sonic log method (SL): also termed ‘∆t shale’, is the most widely usedas, from experience, it gives the most reliability. It consists of theplotting, on a semilog graphic (depth in decimal scale and transit time

in logaritmical scale) of the ∆t values (transit time) at relative depths.

The ∆t value (transit time) is read on sonic log in the shale points

where they are cleanest, ∆t value lowers with the depth increase innormal compaction zones and increases with the depth inoverpressure zones.

P-1-M-6100 2.2.5

3.2.2.2. Several plots for wells drilled in the same area can be used todetermine the ‘average regional trend line’.

3.2.2.3. Once the top of the overpressures is fixed, the next phase concernsthe pore pressure gradient calculation as a function of depth. Themethod generally used is based on the ‘principle of equivalent depth’

P-1-M-6130 3.6.2

3 Interval transit t ime is given in [µsec/ft].



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3.2.3. Resistivity logs

3.2.3.1. Under a normal pressure environment shale resistivity will increasewith depth as porosity decreases

4.

P-1-M-6130 4.2.15

3.2.3.2. Shale resistivities are plotted on semi-log scale versus depth (verticaldepth). The normal trend line can be straight or curved. Onlyresistivity values obtained in good clean shales must be used.

P-1-M-6130 4.2.15

3.2.3.3. Limitations in using resistivity plots are:

• Establishing the shape and position of the normal trend

• Variations in pore water salinity can give false abnormalpressure indications.

P-1-M-6130 5.2.2

3.2.3.4. Several methods can be used to estimate the magnitude of anyabnormal pressure.

3.2.4. Density logs

3.2.4.1. The bulk density readings (g/cc), must be plotted on semi-log scaleversus depth, a straight normal trend in shale’s is observed. Adecrease in shale bulk density away from the normal trend willindicate overpressure.

P-1-M-6130 5.2.2

3.2.4.2.The equivalent depth method can then be used to calculate the valueof any overpressure.

3.3. Methods ’while drilling

3.3.1. Real time indicators P-1-M-6100 2.2.3

3.3.1.1. Penetration rate:

The corrected ‘d’ exponent and Eni-Agip Sigmalog eliminate theeffects of drilling parameter variations and give a representativemeasure of formation drillability. The TDC Engineer is responsible for

continuous monitoring and shall immediately report to CompanyDrilling Supervisor, if any change occur. A copy of corrected Eni-Agipsigma-log/d-exponent shall be sent on daily basis to Company DrillingOffice.

P-1-M-6100 2.2.3P-1-M-6130 4.2.3P-1-M-6130 4.2.4

4 Formation resistively depends primarily on porosity and salinity of the pore water. Temperature also has a minor influence.



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3.3.1.2. Drilling break:

Any time a drilling break is noticed, drilling is to be suspended and aflow check shall be carried out.

P-1-M-6100 2.2.3

3.3.1.3. Torque:

Torque sometimes increases when an abnormally pressured shalesection is penetrated.

P-1-M-6100 2.2.3

3.3.1.4. Tight hole on connections:

A tight hole when making connections can indicate that an abnormalpressure shale is being penetrated using low mud weight.

P-1-M-6100 2.2.3

3.3.1.5. Hole fill:During connections cave ins may have settled preventing the bit fromreturning to bottom. Wall instability in an area of abnormal pressuremay cause sloughing.

P-1-M-6100 2.2.3

3.3.1.6. MWD:

MWD can provide a wide range of bottom hole drilling parametersand formation evaluation: bottom hole weight on bit, torque at bit,gamma ray, resistivity, mud pressure and temperature. If the trueweight and torque at bit are known, drilling rate can be normalisedwith more accuracy.

P-1-M-6100 2.2.3

3.3.2. Indicators depending on lag time

3.3.2.1. Mud gas:

• Background gas.

• Drilling gas.

• Gas shows.

• Trip gas.

• Connection gas.

• Mud weight out & involved total volume.

P-1-M-6100 2.2.4P-1-M-6130 4.2.16

3.3.2.2. Mud temperature:

Measurement of mud temperature can also be used to detect under compacted zones and, under ideal conditions, or to anticipate their approach. This is because temperature gradients observed in under compacted series are, in general, abnormally high compared withoverlying normally pressured sequences.

P-1-M-6100 2.2.4P-1-M-6130 4.2.18



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REVISION

STAP-P-1-M-6090


3.3.2.3. Mud resistivity/chlorides:

When a salinity contrast exists between mud filtrate and formationfluid, is possible to detect overpressure zones by monitoring levels of mud chlorides.

P-1-M-6130 4.2.14

3.3.2.4. Cutting analysis:

• Lithology

• Shale density

• Shale factor

• Shape, size and volume of cuttings.

P-1-M-6100 2.2.4P-1-M-6130 4.2.11

3.3.2.5. In the mud logging a technical specifications document is included in

the detection and evaluation of formation pressure that must be donewith sigma-log/dc-exponent method.

Reference List :



‘Overpressure Evaluation Manual’ STAP-P-1-M-6130

‘Operating Procedure for Drawing the ‘Well Drilling Programme’ STAP-P-1-N-6001E‘Well Testing Manual’ STAP-P-1-M-7130

‘Casing Design Manual’ STAP-P-1-M-6110

‘Dally Report (Drilling)’ ARPO-02/A

‘Well Control Training Manual’ sect.12.4

Software:

IWIS (ADIS) applications



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PL. 2.7. SHALLOW GAS

1. PRELIMINARY SHALLOW GAS INVESTIGATION Reference

1.1. Possibili ty of encountering shallow gas

1.1.1. Well proposals shall always include a statement on the possibility of encountering shallow gas.

Statement contents:

1. Assessments drawn from the shallow gas survey

2. All relevant seismic surveys

3. All offset well data records

4. Geological probability of a shallow cap rock.

P-1-M-6150 9.1

1.1.2. Pilot holes may be drilled, up to the conductor string depth, as part of a preliminary shallow gas investigation programme prior to spuddinga well where platforms are planned to be installed, in areas with highprobability of shallow gas or only a little geological information isavailable.

P-1-M-6150 9.1

1.1.3. A rig that can move away safely in case of shallow gas blow outshould be used to drill pilot holes (mobile offshore drilling unit or adedicate soil boring vessel).

P-1-M-6150 9.1

1.2. Gas pocket pressure

1.2.1. The amount of overpressure at the top of the shallow gasaccumulation depends on the vertical thickness of the gas column (h):

∆p=0.1 (1.03-Ggas) h

P-1-M-6150 9

2. SHALLOW-GAS DRILLING GUIDELINES Reference

2.1. Decision-making guidelines P-1-M-6150 9.3.1

2.1.1. The following drilling practices may be modified for development wellswhere it is confirmed that no shallow gas is expected.

P-1-M-6150 9.3.1

2.2. Pilot hole

2.2.1. • It should be drilled in areas with potential shallow gas.

•••• Pilot holes may be drilled, up to the conductor string depth, aspart of a preliminary shallow gas investigation programme, inareas with high probability of shallow gas or only a littlegeological information is available.

•••• Generally, it is recommended that a drill 121/4” or smaller pilot

hole is drilled.

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2.3. Penetration rate

2.3.1. • Restrict the penetration rate (recommended ROP = one joint/hr).

• Particular care should be taken to avoid an excessive build-up of solids in the hole.

•••• Drilling with heavier mud returns could also obscure indicationsof drilling through higher pressured formations.

P-1-M-6150 9.3.1-b

2.4. Swabbing

2.4.1. • Pumping at the optimum circulating rate is recommended for allupward pipe movements (e.g. making connections and tripping).

• In larger hole sizes especially (i.e. larger than 121/4”), it is

important to check that the circulation rate is sufficiently high andthe pulling speed sufficiently low to ensure that no swabbing willoccur.

• A top drive system will facilitate efficient pumping while trippingout of hole operations.

•••• The minimum required number of stabilisers should be used.

P-1-M-6150 9.3.1-c

2.5. Drilling Fluid

2.5.1. • Accurate measurement and control of drilling fluid.

• Properly calibrated and functioning gas detection equipment anda separate flowmeter are essential in top hole drilling.

• Flow checks must be made before tripping.

•••• When any anomaly appears on the MWD log (if a MWD datatransmission system is used) and at any specific depth referredto in the drilling programme (taken from the shallow seismicsurvey), it is recommended to flow check at each connection

P-1-M-6150 9.3.1-d

2.6. Float Valve

2.6.1. A float valve must be installed in all bottom hole assemblies, whichare used in top hole drilling. The float valve is the only down hole

mechanical barrier available.

P-1-M-6150 9.3.1-e

2.7. BHA

2.7.1. BHAs, used for kick-off operations, have flow restrictions which willconsiderably reduce the maximum possible flow through thedrillstring. Dynamic well killing operation will then be very unlikely.

P-1-M-6150 9.3.1-f

2.8. Shallow Kick-offs

2.8.1. Shallow kick-offs should be avoided in areas with probable shallowgas.

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2.9. Stock

2.9.1. A stock of kill mud based on hole size, and for off-shore rigs, water depth and riser size shall be prepared before commencement of drilling.

P-1-M-6150 9.3.1-g

2.10. Pre-spud meeting

2.10.1. Before spudding the well, a meeting should be held in order to alertkey personnel (Drilling Contractor personnel, mud engineer, mud-logging operator included).

P-1-M-6150 9.3.1-h

3. DIVERTER Reference

3.1. Specific contingency plans

3.1.1. Specific contingency plans for dealing with emergencies which mayoccur during diverter operations should be prepared for each rig andeach well.

P1M6150 9.4

3.2. Main Types of Diverter

3.2.1. Main types of diverter:

• Surface diverter.

• Marine diverter.

• Subsea diverter, which is not common and available only on fewrigs.

P-1-M-6150 9.4.1

3.3. Diverter Test (before start of operat ions).

3.3.1. Before start of drilling operations perform a diverter test. P-1-M-6150 9.4.3

3.4. Operation without the riser

3.4.1. Riserless drilling is considered to be the safest way to cope with theshallow gas problem since the vessel can quickly move away from asubsea blow-out.

P-1-M-6150 9.3.5

3.4.2. Water depth has some influence on buoyancy loss, but it has greater influence on vessel instability, especially at very shallow water depth.

P-1-M-6150 9.3.5

3.5. Conductor pipe

3.5.1. Running and cementing the 30” casing in a pre-drilled hole, after having drilled a pilot hole, is the recommended technique in areaswhere shallow gas might be encountered.

P-1-M-6150 9.3.6

Reference List :

‘Well Control Policy Manual’ STAP-P-1-M-6150



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PL. 2.8. CASING SETTING DEPTH

1. DETERMINE PROPER SETTING DEPTH FOR EACH CASING TYPE Reference

1.1. Preliminary information

1.1.1. When planning, all available information should be carefullydocumented and considered to obtain knowledge of the variousuncertainties.

P-1-M-6110 3P-1-M-6100 3

1.1.2. The selection of casing setting depths is based on:

• Total depth of well.

• Pore pressures.

• Fracture gradients.

• The probability of shallow gas pockets.• Problem zones.

• Depth of potential prospects.

• Time limits on open hole drilling.

• Casing programme compatibility with existing wellhead systems.

• Casing programme compatibility with planned completionprogramme (production well).

• Casing availability (grade and dimensions).

•••• Economy, i.e. time consumption to drill the hole, run casing andcost of equipment.

P-1-M-6110 3P-1-M-6100 3

2. GENERAL GUIDELINES ON CASING SETTING DEPTHS Reference

2.1. Conductor Pipe

2.1.1. The driving depth of the conductor pipe which is specified in theDrilling Programme is established with the following formula:

1.03)]-GOV(x0.67+MW-[1.03

H]x103-H)+(Ex[MW=H

Hii

where:Hi = Minimum driving depth (m) from seabed

E = Elevation (m) distance from bell nipple and sea level

H = Water depth (m)

MW = Maximum mud weight (kg/l) to be used

GOVhi= integrated density of sediments (kg/dm3/10m)

P-1-M-6140 4.1.2

2.1.2. Drive the conductor pipe till the final depth or the refusal point of about 1000-1100 blows/meter.

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2.2. Surface Casing

2.2.1. The depth should be great enough to provide a fracture gradientsufficient enough to allow drilling to the next casing setting point andto provide reasonable assurance that broaching to the surface will notoccur in the event of BOP closure to contain a kick.

P-1-M-6110 3.2P-1-M-6100 3.2

2.3. Intermediate Casing

2.3.1. In general practice, drilling is allowed until the mud weight is within50gr/l of the fracture gradient measured by conducting a leak-off testat the previous casing shoe.

P-1-M-6100 3.3

3. SAFETY REQUIREMENTSReference

3.1.1. Evaluate ‘kick tolerance volume’ at the end of each hole section. PL.02.01 2.1

Reference List :




Software:

CASCADE-IWIS (ADIS)



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PL. 2.9. DIRECTIONAL WELL PLANNING

1. PRELIMINARY DIRECTIONAL PLAN INFORMATION Reference

1.1. The SDE will ensure that the Directional Contractor is provided withall data necessary for an initial well profile.

P-1-M-6120 3.5

1.2. The well deviation diagram (plan and vertical section) is included,along with output tables.

In the case of cluster wells, diagrams and tables for vertical wells arealso given.

P-1-N-6001E 6.3.12

1.3. Preliminary Specification

1.3.1. The following information will be specified :

• Surface and target co-ordinates - UTM or geographical

• Local reference co-ordinates - platform centre, slot

• Orientation of the wells bay (if applicable)

• Displacement among the slots (if applicable)

• Consider the wells position in the template, cluster, platformslots

• Expected lithology - with a clear indication of subsea or RKBdepths

• Total well TVD - with a clear indication of subsea or RKB depths

• Inclination at target• Shape and size of target(s) - restrictions, if applicable

• Preliminary casing programme

• Type of drilling fluid

• Potential drilling problems which may affect the directionalprofile.

• Definitive survey data of all well bores which may constitute acollision risk.

P-1-M-6120 3.5



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1.4. Topographic References

1.4.1. Will comprise the following information:• Reference meridian

• Starting latitude (geographic) N/S

• Starting longitude (geographic) E/W

• Latitude at the targets (geographic) N/S

• Longitude at the targets (geographic) E/W

• Starting latitude (metric) N/S

• Starting longitude (metric) E/W

• Latitude at the targets (metric)

• Longitude at the targets (metric)

• Type of projection

• Semi-major axis

• Squared eccentricity (1/F)

• Central meridian

• False East

• False North

• Scale Factor

P-2-N-6001E 7.1.1


2.1. UTM (Universal Transverse of Mercator)

2.1.1. The co-ordinates for each UTM grid sector are given in metres withthe origins (i.e. the zero value) at a line 500,000m West of the centremeridian to avoid negative values and at the equator. The co-ordinates are given as Eastings and Northings.

P-1-M-6100 12.2.1P-1-M-6140 9.2.1

2.2. Convergence angle

2.2.1. The convergence angle is the angle between UTM North (Grid North)and True North (Geographic North). In carrying out the projectionthere is some distortion of the axes such that UTM North is slightly

offset from Geographic (True) North. This small difference issignificant over large distance and so must be taken into accountwhen converting co-ordinates from one system to another.

P-1-M-6100 12.2.1P-1-M-6140 9.2.1



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2.3. Origin Reference Point

2.3.1. Is the origin which will be used for the horizontal co-ordinates e.g.latitude and departure of the well to be drilled. This will be the zeropoint on the horizontal well plan used to plot the well while drilling.

P-1-M-6120 3.2.4

2.3.1.1. Isolated wells:

The initial ORP will be the planned RKB location.

P-1-M-6120 3.4.3

2.3.1.2. Template wells:

The ORP is the designated template centre.

P-1-M-6120 3.4.3

2.3.1.3.Platform wells:

The ORP is the slot area centre or a designated slot.

P-1-M-6120 3.4.3

2.3.2. Onshore cluster wells:

The ORP is a designated slot.

P-1-M-6120 3.4.3

2.4. Local Magnet ic Declinat ion Correction

2.4.1. The magnetic declination will be individually calculated for each newlocation.

Since it is a time based measurement, the date used for the

calculation will be an estimated mid-point for the drilling operationperiod. Subsequent surveys will require the re-calculation of magneticdeclination if taken more than six months after the well is drilled.

It is obtained from actual geomagnetic field maps.

P-1-M-6120 4.4.12P-1-M-6140 9.1P-1-M-6100 12.1

3. SURVEY CALCULATIONS Reference

3.1. Calculation techniques

3.1.1. Eni-Agip standard survey calculation method:

‘minimum radius of curvature method’

P-1-M-6120 4.4.4P-1-M-6120 3.4.1

3.2. Source of survey errors

3.2.1. Algorithm used to calculate position.

3.2.2. Survey tool uncertainty. Tab. OP.02.02-3Tab. OP.02.02-4P-1-M-6120 4.4.4



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3.3. Surveying requirements

3.3.1. General Surveying Requirements:

• All magnetic surveys will have to be reported after beingcorrected for magnetic declination. Magnetic declination must bespecified.

• For other surveys, ensure that magnetic declination isconsidered while aligning.

• Gyro survey output does not need to be corrected for magneticdeclination.

• The depth of a survey is the survey instrument depth not the bitdepth. This applies to MWD and survey tools.

• Azimuth will be referenced to true North.• Bottom hole location will be extrapolated from the last survey.

This will normally not be more than 30m. To confirm the bottomhole location the dipmeter can be used as it can survey down toaround 5m from TD if hole conditions allow.

For drilling purposes ‘depth’ will always be quoted as drilled depth andnot confused with wireline depth.

P-1-M-6120 4.4.1

4. SURVEY TOOL SELECTION Reference

4.1. Approved surveying tools

4.1.1. Magnetic Survey Tool List

MSS Magnetic single shot (film)

MMS Magnetic multishot

EMS Electronic magnetic multishot

MWD Measurement while drilling

HDT High resolution dipmeter

Gyroscopic Survey Tool List

GSS Gyro single shot (film)

GMS Gyro multishot

SRG Surface reading gyro

NSG North seeking gyro (FINDER)

GCT Guidance continuous tool

FINDS Ferranti Inertial Navigation System

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4.1.2. Survey programme for vertical holes:

• TOTCO will be acceptable only in vertical wells for surface holesif inclination is less then 1.5°

• MSS (magnetic multishot) is the standard.

• MWD will be run if economically and technically justified.

• GSS will not be run below 400m

• In cased hole: gyro multi shot (GMS) is the standard.

• If anticollision is a critical concern the NSG/GTC or the FINDSwill be used

P-1-M-6120 4.5.3P-1-M-6120 4.7

P-1-M-6120 4.8P-1-M-6120 4.6.2

4.2. Factors af fecting survey too l selection

4.2.1. Maximum inclination.

Survey accuracy requirement will differ between vertical and deviatedwells.

P-1-M-6120 4.5.3

4.2.2. Casing size.

FINDS inertial surveying system can be run only in 133/8" casing or

larger.

P-1-M-6120 4.5.3

4.2.3. Survey depth.

GSS will not be run deeper than 400m due to excessive drift rates.

P-1-M-6120 4.5.3

4.2.4. Hole inclination.

Maximum inclination for GSS, GMS and SRG is 70° (stability limit).

P-1-M-6120 4.5.3

4.2.5. Potential drilling problems:

Differential sticking problems precludes the use of wireline basedsurveys with drillpipe in open hole (GSS, SRG, MSS and EMS).

P-1-M-6120 4.5.3

4.2.6. High pressure reservoirs:

In an isolated deviated well, GMS or SRG will be run in the previouscasing to establish minimum uncertainty before drilling through a high

pressure zone (in case of a blow out and a relief well is required). Amore accurate tool (NSG/GCT) may be used for accuracyimprovement.

P-1-M-6120 4.5.3

4.2.7. Temperature limitation.

Maximum borehole temperature must be within specification for thesurvey tools proposed for the programme.

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4.2.8. Well proximity.

Template/platform wells, which are drilled in the neighbourhood of other wells, must maintain a minimum separation with respect to theother wells. This may require additional surveys (e.g. NSG in drillpipe) more often than with individual wells.

P-1-M-6120 4.5.3

4.2.9. Survey accuracy.

Installations will be most crowded immediately below theplatform/template and will require greater survey accuracy to fix wellbore locations. The most accurate tools (FINDS or NSG) may benecessary for minimum uncertainty in critical situations.

P-1-M-6120 4.5.3

4.2.10. Magnetic Influence.

Magnetic based surveying instruments will not be used, in anysituation, as the prime source of well location calculations when within8m of any adjacent casing string.

P-1-M-6120 4.5.3

4.2.11. Target size and depth:

The accuracy of the surveying tools used on a well will be such thatthe total horizontal uncertainty at target depth is reasonablecompared to the target size. The smaller and the deeper the target,the more stringent the survey requirements.

P-1-M-6120 4.5.3

4.3. Non-magnet ic dr il l col lars requi rements

4.3.1. See proper charts in reference documents.

Non-magnetic stabilisers will be the only type permitted for usebetween NMDC's.

P-1-M-6120 4.6.1P-1-M-6140 9.4.1

4.4. Quality control

4.4.1. Magnetic Survey Tools:

Magnetic azimuth values will be considered invalid when the surveyinstrument is within 8m of an adjacent casing shoe:

When magnetic influence is expected from adjacent casing (or whenthe well is separated less than 8m horizontally from an adjacentcasing string), provision will be made to run a gyro based survey toolon top of the MWD.

Survey repeatability should be within 0.5° inclination and 2° azimuth

(above 10ο inclination).

MWD: survey repeatability should be within 0.5° inclination and 2°azimuth (above 10° inclination).

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5. FREQUENCY AND TYPE OF SURVEYS Reference

5.1. Standard minimum survey programme for vertical exploration wells:(Refer to Figure PL 2.3 )

P-1-M-6120 4.7

5.2. Standard minimum survey programme for directional wells:

(Refer to Table PL 2.4)

P-1-M-6120 4.8

6. ANTI-COLLISION Reference

6.1. Objectives

6.1.1. Anti-collision procedures will be implemented, in all cases where is apotential collision risk according to the policies outlined in this manual.

The prime reasons for specifying an anti-collision policy are to:

• Ensure a consistent method is used to evaluate and reducecollision risks between wells.

• Establish a common procedure for developing multi-well siteswhich takes into account actual well trajectory and trajectories of already existing wells.

• Establish a common procedure that discriminates betweeninterference from completed/producing wells andplugged/abandoned/uncompleted wells.

P-1-M-6120 5.1

6.2. Definitions

6.2.1. Current Well (CW):

The well being planned or drilled.

P-1-M-6120 5.2.5

6.2.2. Target Well (TW):

Any well being considered for anti-collision purposes or proximitycalculations.

P-1-M-6120 5.2.5

6.2.3. Radius of Uncertainty (ROU):

The ROU is the radius of a sphere, at a specific vertical depth, whichhas the probability of containing the well-path. It is a cumulativecalculation based on the product of the Horizontal Uncertainty Factor of the survey instrument used to that point and the surveyed depth tothat point.

P-1-M-6120 5.2.5

6.2.4. Uncertainty Factor (UF):

The UF is a coefficient, given in metres/thousand meters surveyed,that reflects the increase in radius of uncertainty of the well path withdepth and depends only on the type of survey instrument and on thehole inclination.

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6.2.5. Separation ratio (SR):

• Separation Ratio > 1 = No interference between ROU’s.• Separation Ratio < 1 = Interference between ROU’s.

SR = CCD/(CW ROU + TW ROU)

P-1-M-6120 5.2.8

6.2.6. Separation Distance (SD):

The SD is the distance, in the plane of the expected closestapproach, between ROU of the CW and the TW at a given verticaldepth.

SD = CCD -[ROU (CW) + ROW(TW) ]

P-1-M-6120 5.2.7

6.2.7. Centre To Centre Distance (CCD):

The CCD is the distance, in the plane of the expected closestapproach, between the centres of CW and TW paths at a givenvertical depth.

P-1-M-6120 5.2.8

6.2.8. Curve A - Threshold of separation:

Is the curve that, at any depth represent the condition SR = 1

At any depth define the distance of potential collision.

P-1-M-6120 5.2-F5.2

6.2.9. Curve B - Threshold of alert:

Is the curve where, at any depth, the condition SR = coefficient B.

Usually coefficient. B = 1.5

P-1-M-6120 5.2-F5.2

6.2.10. Curve C - Threshold of danger:

Is the curve where, at any depth, condition SR = coefficient C

Usually coefficient. C = 2

P-1-M-6120 5.2-F5.2

6.2.11. Zone X - Field of danger:

The field between Curve C and Curve B

P-1-M-6120 5.2-F5.2

6.2.12. Zone Y - Field of alert:

The field between Curve B and Curve A

P-1-M-6120 5.2-F5.2

6.2.13. Zone Z - Field of Potential Collision:

The field delimited by Curve A

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6.3. Proximity calculation

6.3.1. The values of coefficients B and C could be reduced on the basis of aprobabilistic analysis of the occurrence of potential well collisionsituations. The Uncertainty Area Ratio (UAR) concept could be usedto evaluate the probability of the occurrence of potential well collisionsituations. The UAR is the ratio of the sum of the two Uncertainty Area to the sum of the two hole sizes.

( )( )TWOD+CWOD

TWROU+CWROU=UAR

22

22

where:

CWOD = the outside diameter of the current well

TWOD= the outside diameter of the target well

P-1-M-6120 5.2.10

6.4. Responsib il it ies (wel l p lanning stage)

6.4.1. The DM will have overall responsibility for the maintenance of safeoperations while drilling in proximity to other wells.

P-1-M-6120 5.5.1-aP-1-M-6120 5.2.9

6.5. Planning wel ls with interference between existing

producing/completed wells and new wells

6.5.1. Directional Well Plans in which trajectories fall into zone X is onlyallowed when the target well (TW) has been properly plugged.

P-1-M-6120 5.5.1-b

6.5.2. The SDE will define any CWs falling within the zone X, during the wellplanning stage and will prepare necessary recommendationaccording to the following guideline:

• The TW directional data must be of reliable source and quality.

• Planning the CW, relevant anti-collision analysis are performed.

•••• Proximity calculation and projection are done regularly at the

wellsite while drilling the CW in order to confirm the CW positionwithin zone X.

• While drilling within zone X to assure adequate quality andfrequency of the surveys, MWD will be used.

P-1-M-6120 5.5.1-c

6.5.3. The SDE will prepare a contingency plan for plugging appropriateTWs.

The contingency plan will specify procedures, timing andresponsibilities of other Eni-Agip Division and Affiliates departmentsin suspending the appropriate TWs and will be included in the wellprogramme for the CW.

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6.5.4. Planning directional wells in which trajectories fall into the zone Y arenot allowed as a part of normal procedure.

Dispensation will require approval by the DM and must be clearlystated and documented.

P-1-M-6120 5.5.1-f P-1-M-6120 5.5.1-g

6.5.5. Planning and drilling with separation falling in the zone Z isunacceptable under any circumstance.

P-1-M-6120 5.5.1-n

6.6. Planning wel ls with interference between existing, non

completed/plugged & abandoned wells and new wells

P-1-M-6120 5.5.2

6.6.1. Planning new wells within zone Y is allowed when the target well(TW) is a plugged and abandoned, suspended or not completed well.

P-1-M-6120 5.5.1-b

6.6.2. During the well planning stage, the SDE will define any CWs fallingwithin the zone Y and will prepare necessary recommendationaccording to the following guidelines:

• The TW directional data must be of reliable source and quality.

• Planning the CW, relevant anti-collision analysis is performed.

• Proximity calculation and projection are done regularly at thewellsite while drilling the CW in order to confirm the CW positionwithin zone Y.

• While drilling within zone Y to assure adequate quality andfrequency of the surveys, MWD will be used.

P-1-M-6120 5.5.1-d


P-1-M-6120 5.5.1-c

6.7. Suspension of wells

6.7.1. Suspension of target wells (TW):

(Refer to Figure PL 2.3 )

P-1-M-6120 5.6Figure. 5.6

6.7.2. Suspension of current well (CW):

(Refer to Figure PL 2.3 )

P-1-M-6120 5.7Figure. 5.6

6.8. Projection technique

6.8.1. Additional hole uncertainty due to maximum dogleg potential of theassembly will be added to the ROU of the current well.

P-1-M-6120 5.3.4



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6.9. Planning a multi-well site

6.9.1. Reduce potential well collision situations:

• The slot allocations will account for final target displacement anddirection. Higher displacement wells will be drilled from the outer slots whenever possible.

• The kick-off points of wells will be spaced vertically dependingon final target displacement. Larger displacement wells will bekicked off at shallower depths whenever possible.

• If crossing of trajectories is unavoidable, the tangent section onboth wells should be achieved while drilling whenever possible.

• The drilling order of wells will be such that the eventual shut-in

time requirement of adjacent wells is kept to a minimum.

P-1-M-6120 5.4

6.9.2. Spacing of wells for the surface vertical phases will not be subjectedto SR < 1 limit, in case drilling is planned/performed from a multi-wellsite where all the surface phases have to be drilled subsequently atonce time.

P-1-M-6120 5.4

6.9.3. Antic collision procedures will apply, for the surface vertical phase, incase drilling is planned/performed from a multi-well site whereproduction from adjacent wells is on going or during any productionwhile drilling activity.

P-1-M-6120 5.4

6.10. Well site procedure

6.10.1. Proximity calculations will be done at regular intervals depending onthe risk of collision but, at least twice daily while drilling.

P-1-M-6120 5.8-5

6.10.2. Proximity calculations and projections are to be performed on eachsurvey

P-1-M-6120 5.8-8

6.10.3. Unless required for directional control, the use of drilling motors willbe avoided while drilling in this situation. If motor use is unavoidablethen a low torque motor will be the preferred option

P-1-M-6120 5.8-15

6.10.4. Whenever possible use PDC bits instead of tricone bits P-1-M-6120 5.8-16

7. BHA ANALYSIS Reference

7.1. Bottom hole assembly response

7.1.1. Common holding assemblies. P-1-M-6140 9.4.4

7.1.2. Drop off assemblies. P-1-M-6140 9.4.4



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8. REPORTING Reference

8.1. Survey

8.1.1. Surveys of all wells will be filed in printed copy and in electronicformat.

Data must be available on floppy disks (two copies) formattedaccording to Eni-Agip specification. Write protected form issuggested.

P-1-M-6120 6.1.1

8.1.2. SDE will be responsible for the correct archival and retention of survey files and final report.

P-1-M-6120 6.3

8.1.3. Standard Eni-Agip reporting form: survey calculation's output. P-1-M-6120 6.4

8.2. Final report by direct ional cont rac tor .

8.2.1. Contents of final report. P-1-M-6120 6.5

8.3. Contractors evaluation.

8.3.1. Planning requirements:

Minimum required software capabilities.

P-1-M-6120 3.4.1

Reference List :

‘Directional Control & Surveying Procedures Manual’ STAP-P-1-M-6120




‘Operative procedure for Preparing the ‘Geological and Drilling Well Programme’’ STAP-P-2-N-6001E

Software:

3-D IWIS (ADIS)

Compass



S E C T I ON

1 OF B P & MR

-P L A NNI N G ( P L )

FREQUENCY AND TYPE OF SURVEYS Vert i

Platform/Cluster Template Wells IndividuWhile Drilling After Casing set While Drilling

Type of instrument

Frequency Type of instrument


Frequency

30” C.P. Tocto(template)

BottomGMS/SRG 30m

MSS

Tocto At shoe

20” -13” 3/8

Surface CSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

13” 3/8

intermediate

CSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30m

MWD

MSS150M

(and each trip)

9” 5/8 CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

7” CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

5” Liner MSS/MWD

HDT/MMS As required GMS/SRG

NSG/GCT30m

MWD

MSS150M

(and each trip)

Note:1. Records after casing set may be omitted if it is not dictated by local condition, legislation, t

wells and good survey have been taken in open hole.2. If SDD ( Straight Drilling Device) is in use to keep the well in vertical condition, we can sup

and the others survey records should be omitted.

T a b l eP L 2 . 3 -F r e q u en c y an d

T y p e s of S ur v e y s f or V er t i c

al W el l s



S E C T I ON

1 OF B P & MR

-P L A NNI N G ( P L )

FREQUENCY AND TYPE OF SURVEYS Devia


Type of instrument



Frequency

30” C.P. Tocto BottomGMS/SRG 30m

MSS

Tocto At shoe

20” -13”3/8

Surface CSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

13”3/8

intermediateCSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30m

MWD

MSS150M

(and each trip)

9”5/8 CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

7” CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

5” Liner MSS/MWD


NSG/GCT30m

MWD

MSS150M

(and each trip)

Note:1. Records after casing set may be omitted if it is not dictated by local condition, legislation, th

wells and good survey have been taken in open hole.2. Records after casing set may be omitted if a cross-check with a second MWD tool or equiva

T

a b l eP L 2 .4 -F r e q u en c y an d

T y p e s of S ur v e y s f or D ev i a t

e d W el l s



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Figure PL 2.1 - Anti-Collision Responsibil ities (when there is Interference Between Existing

Completed/Productive Wells and New Wells)



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Figure PL 2.2 - Anti-Collision Responsibil ities (when there is Interference Between Existing

Non Completed/Plugged & Abandoned Wells and New Wells)



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Figure PL 2.3 - Anti-Collision dur ing Well Suspension



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PL. 2.10. CASING DESIGN

1. CASING SETTING DEPTH AND FUNCTIONS OF CASING STRINGS Reference

1.1. Determine proper setting depth for each casing type.

1.2. Define the purpose of each casing string. PL.02.08

1.3. Safety requirements.

2. CASING AND HOLE SIZES Reference

2.1. Define each casing diameter according to hole sizes.

2.1.1. • Casing selection chart.

• 30” x 1” conductor pipe is assumed as standard.

P-1-M-6110 3.6

2.2. Exploration well

2.2.1. The 6” hole should be planned as contingency P-1-M-6110 3.6

2.2.2. Evaluate hole size-casing clearance.

2.2.3. Avoid all the problems connected with too large/small clearance. P-1-M-6110 3.6

2.2.4. Size of tubing & completion equipment.

3. CASING DESIGN CRITERIA AND DESIGN FACTORS Reference

3.1. Guidelines

3.1.1. Casing design is actually a stress analysis procedure. The objective isto produce a pressure vessel which can withstand a variety of external, internal, thermal, and self weight loading, while at the sametime being subjected to wear and corrosion.

P-1-M-6110 7

3.2. Max acting burst pressure

3.2.1. Refer to Table PL 2.5

3.2.2. If it is foreseen that future stimulation or hydraulic fracturingoperations may be necessary, the fracture pressure at perforationdepth and at the wellhead pressure minus the hydrostatic head in thecasing plus a safety margin of 70kg/cm

2 (1,000psi), will be assumed.

P-1-M-6110 8.1.2

3.3. Max acting collapse pressure

3.3.1. Refer to Table PL 2.6



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3.3.2. Biaxial stress:

Total tension load affects burst and collapse resistance of the casing,(effects of axial stress on burst resistance are considered negligible).

P-1-M-6110 8.4.1

3.3.2.1. Reduced collapse resistance in biaxial stress must be considered. P-1-M-6110 8.4.1

3.3.3. Prevention of casing collapse in salt sections must be considered. P-1-M-6110 8.7

3.3.3.1. Eni-Agip design procedures assume uniform external pressureexerted by salt on the casing equal to overburden pressure.

P-1-M-6110 8.7.3

3.4. Total TENSION load

3.4.1. Total tension load is given by adding to the weight of casing in air:

(Refer to Table PL 2.7)

3.4.2. Buoyancy force (negative) while running casing. P-1-M-6110 8.3.2

3.4.3. Bending forces in deviated wells (curved section of hole). P-1-M-6110 8.5.1

3.4.3.1. Determination of bending effect5. P-1-M-6110 8.5.2

3.4.4. Tension load due to bump plug after displacing cement does notaffect biaxial stress evaluation.

Take in to account eventual pressurisation about both opening

/closing DV operations and setting ECP.

P-1-M-6110 8.3.3-3

3.4.5. Others parameters affecting total tension load:

3.4.5.1. Drag forces in deviated wells. P-1-N-6001E 6.3.10

3.4.5.2. Shock loads (dynamic stresses), due to arresting casing in slips. P-1-M-6110 11

3.4.5.3. Internal pressure tests6.

The worst situation assumes the casing totally free to move.

P-1-M-6110 11.3

3.4.5.4. Changes in the magnitude of the buoyancy forces. P-1-M-6110 8.3.2

3.4.6. Evaluate ‘safe allowable pull’.

It is normal to consider an overpull contingency of 100000lbs.

P-1-M-6110 11.1

5 B = 15,52 α OD Af ; TB : additional tension [kg] OD : outside diameter [in]

α : build-up/drop-off rate [deg/30m] Af : cross section area [cm2]

TB = 218 α OD Af ; TB : [lb] OD : [in]

α : [deg/100ft] Af : [in2 ]6 The test pressure shall not exceed 70% of the API minimum internal yield pressure of the weakest casing in the string. The test

pressure shall remain stable for 15 minutes.



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3.5. Requi red & actual des ign fac tors

3.5.1. Burst required design factor. Refer to Table PL 2.5 P-1-M-6110 8.1.2

3.5.2. Collapse required design factor. Refer to Table PL 2.6 P-1-M-6110 8.2.1

3.5.3. Tension required design factor. Refer to Table PL 2.7 P-1-M-6110 8.3.3

4. DECREASING IN THE CASING PERFORMANCE PROPERTIES Reference

4.1. Casing wear

4.1.1. Reduction in collapse resistance due to wear will be critical at shallowdepths, the reduction in burst resistance will be critical at the lower

end of the casing string.

P-1-M-6110 8.6

4.1.2. Eni-Agip design procedure.

• In vertical well, casing wear is usually in the first few joints belowthe wellhead or intervals with a high dogleg severity.Considerations should be given to increase the grade or wallthickness of the first few joints below the wellhead.

• In deviated wells, wear will be over the build-up and drop-off sections. The casing over these depths can be of a higher gradeor greater wall thickness.

P-1-M-6110 8.6.8

4.1.3. The percentage casing wear at each point along the casing is thencalculated from the volumetric wear. Eni-Agip acceptable casing wear limit is </= 7%.

P-1-M-6110 8.6.1

4.1.4. The volume of casing worn away by the rotating tool joint equals:

P

SxNxDxLxFxx60 v π

=

where:

V= Wear volume per foot (in3/ft)

F= Wear factor (ins2/lbs)

L= Lateral load on drill pipe per foot (lbs/ft)

D= Tool joint diameter (ins)

N= Rotary speed (RPM)

S= Drilling distance (ft)

P= Penetration rate (ft/hr)

P-1-M-6110 8.6.2



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4.1.5. Prediction of casing wear

4.1.5.1. Wear factor evaluation:

It is depending on drilling fluid characteristic and tool joint type.

P-1-M-6110 8.6.4

4.1.6. Detection of casing wear:

• Use of magnets in mud flow return system.

• Run a calliper survey tool.

P-1-M-6110 8.6.5

4.1.7. Practices to reduce casing wear:

• Use drill pipe without hard facing.

• Keep sand content low.

• Use of rubber drill pipe casing protectors.

• Use DHM, turbines.

• Keep doglegs at a minimum.

• Use oil based mud.

P-1-M-6110 8.6.6

4.1.8. Recommended approach to casing wear problems at well planningstage:

1. Design the casing.

2. At the wear points, calculate the allowable reduction in wall-thickness so that the burst (or collapse) resistance of the casing

just equals to burst (or collapse) load, including the appropriateDesign Factor.

3. Estimate the wear rate in terms of loss of wall-thickness per operating day.

P-1-M-6110 8.6.7

4.2. Corrosive environment

4.2.1. Carbon dioxide (CO2):

• Partial pressure > 30psi - usually indicates corrosion.

• Partial pressure 3 – 30psi - may indicate corrosion.

• Partial pressure < 3psi - no corrosion.

P-1-M-6110 9.1.3

4.2.2. Hydrogen sulphide (H2S):

The combination of H2S with CO2 is more aggressive than H2S and isfrequently found in oilfield environments. Attack due to presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion.

P-1-M-6110 9.1.3



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4.2.3. Factors affecting corrosion rates:

• Temperature• Pressure

• pH

• Fluids velocity.

P-1-M-6110 9.1.3

4.2.4. Acceptable casing for ‘sour’ service Vs operating temperature. P-1-M-6110 Table 9.B

4.2.5. Eni-Agip design procedure.

4.2.5.1. CO2 corrosion:

• Exploration wells - no influence on material selection.

• Producing wells - selection of high alloy chromium steelsresistant to corrosion, inhibitor injection.

P-1-M-6110 9.8.1

4.2.5.2. H2S environment:

• Exploration wells:with high probability of encountering H2S, it should beconsidered to limit casing yield strength according to API-5CTand NACE standard MR-01-75.

• Producing wells:casing and tubing material will be selected according to theamount of H2S and other corrosive media present.

P-1-M-6110 9.8.2

4.3. Temperature effects

4.3.1. High temperature service

4.3.1.1. Reduction in yield strength. P-1-M-6110 10.1

4.3.1.2. Graph ‘modulus of elasticity of casing Vs temperature’. P-1-M-6110 10.1

4.3.2. Low temperature service:

Use high ductility steel to prevent brittle failures during transport and

handling.

P-1-M-6110 10.2



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4.4. Buckling & compression

4.4.1. Buckling

4.4.1.1. Buckling effect may occur in the uncemented portion of a casingstring, if (after the cement has set):

• Internal pressure increases.

• Annular fluid density reduction.

• Casing is landed with less than full hanging weight.

• Temperature increases.

P-1-M-6110 11.4.1

4.4.1.2. Buckling of long uncemented portions of the casing string (in vertical

wells), can be prevented by:• Cementing the casing up to the neutral point.

• Pre-tensioning the casing on landing.

• Rigidly centralising the casing below the neutral point.

P-1-M-6110 11.4.1

4.4.2. Compression

4.4.2.1. Wells with the wellhead at ground level or sea bed.

The surface casing must be cemented to surface / seabed.

P-1-M-6110 11.4.2

4.4.2.2.Wells with the wellhead above sea level (no mudline suspension).

The surface casing must be designed for compression loads.

Every joint of the surface casing must be centralised.

P-1-M-6110 11.4.2

4.4.2.3. Wells with mudline suspension.

The weight of the casing is taken at the seabed, but the wellhead isabove seabed.

The C.P. must be cemented to seabed.

The tieback strings may be subject to buckling, a full structuralanalysis should be carried out (commissioned).

P-1-M-6110 11.4.1P-1-M-6140 15.5



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5. DRILLING PROGRAMME CONTENTS Reference

5.1. If the procedures for calculating casing stress are not directly basedon the corporate ‘Casing Design Manual’, reasons must be given inan introductory sub-paragraph.

The present paragraph shall include:

1. Stress diagrams, with relative reports.

2. A table summarising the following, minimum information for

each casing:

• Casing diameter (inches)

• Casing function (surface, intermediate, production)

• Type and category of steel

• Casing weight (lb/ft)• Type of connection

• Depth interval

• Maximum stress (Buckling, Tearing, Tensile stress)

• Nominal resistance (Buckling, Tearing, Tensile stress)

• Safety factor required (Buckling, Tearing, Tensile stress)

• Safety factor (Buckling, Tearing, Tensile stress)

3. Hang-off load (if applicable)

P-1-M-6001E 6.3.4

5.2. Design operat ional programme for casing running.

5.2.1. Recommended casing running speed to optimise surge pressure dueto pipe motion.

A-1-M-1000 4

5.2.2. Tension load applied on casing string while is landed on the casingspool.

5.2.3. Always, check maximum planned pull against rig capacity, alsoaccording to cantilever position.

Reference List :


‘Operating Procedures for Drawing the ‘Well Drilling Programme’’ STAP-P-1-N-6001E


Software:

CASCADE-IWIS (ADIS)



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BURST PRESSURE (IP-EP)

Internal Pressure External Pressure

Wellhead Bottom-hole

SURFACE

CASING

P-1-M-6110-8.1.2

Working pressure rating of BOP equipment7 or wellheadbut with a minimum of 140Kg/cm

2

Predicted fracturegradient below thecasing shoe.

Surface wellhead:

= hydrostatic pressureof a column of drillingmud.

Subsea wellhead:

= Water Depth xSeawater Density x 0.1(if atm) seawater (1,03kg/dm

3).8

INTERMEDIATE

CASING

P-1-M-6110-8.1.2

Surface wellheads:

60% of difference betweenfracture pressure at casingshoe and gas columnpressure to the wellhead.

Subsea wellheads: as 60% of the value obtained as thedifference between thefracture pressure at thecasing shoe and the pressureof a gas column to thewellhead minus the seawater

pressure.

Predicted fracturegradient of formationbelow the casing shoe.

Formation pressure

With a subseawellhead, at thewellhead, hydrostaticseawater pressureshould be considered.

PRODUCTION

CASING

P-1-M-6110-8.1.2

Wellhead burst limit =difference between the porepressure of the reservoir fluidand the hydrostatic pressureproduced by a column of fluid9

Wellhead pressureburst limit plus annulushydrostatic pressureexerted by thecompletion fluid.

Formation pressure.

With a subseawellhead, at thewellhead, hydrostaticseawater pressureshould be considered

Stimulation or hydraulicfracturing

operations.

Fracture pressure atperforations depth minushydrostatic pressure plussafety margin of 1000 psi.

Fracture pressure atperforations depth.

1.05 H40 - J55 - K55

DESIGN FACTOR

P-1-M-6110-7.2.1

1.10 C75 - L80 - N80 - C90- C95 - P110

Casing grade

1.20 Q125

Table PL 2.5 - Burst Pressure

When testing or producing through a liner, the casing above the liner will be a part of theproduction string and must be designed according to this.

7 If an oversize BOP is selected: (IP)wellhead=60% [(fracture pressure at casing shoe)-(hydrostatic pressure of gas column to

surface)]; methane gas with density of 0,3 kg/dm3 is normally used.8 At shoe =(Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm)

Usually gas (density = 0.3kg/dm3). Actual gas/oil gradients can be used if information on these are known and available.



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COLLAPSE PRESSURE (EP-IP)

Internal Pressure External PressureSURFACE CASING

P-1-M-6110-8.2.1

The casing for onshore operationis considered completely empty.

In offshore wells with subseawellheads, the internal pressureassumes that the mud level dropsdue to a thief zone

Surface wellhead:

External pressure equal to thehydrostatic pressure of a column of drilling mud.

Subsea wellhead:

At the wellhead - Water Depth xSeawater Density x 0.1 (if atm).

At the shoe - (Shoe Depth - Air Gap) xSeawater Density x 0.1 (if atm).

INTERMEDIATE

CASING

P-1-M-6110-8.2.1

The mud level inside the casingdropping to an equilibrium levelwhere the mud hydrostatic equalsthe pore pressure of the thief zone

When thief zones cannot beconfirmed assume the casing to behalf-empty and the remaining partof casing full of heaviest mudscheduled to drill the section belowthe shoe.

Hydrostatic pressure of mud in whichcasing is run.

The uniform external pressure exertedby salt on the casing or cementsheath through overburden pressure,should be given a value equal to thetrue vertical depth of the relative point.

PRODUCTION

CASING

P-1-M-6110-8.2.1

The casing string is consideredcompletely empty.

Hydrostatic pressure of mud in whichcasing is run.

DESIGN FACTOR

P-1-M-6110-7.2.1

1.10 All casing grade

Table PL 2.6 - Collapse Pressure

The reduced collapse resistance in biaxial stress (tension/collapse) should be considered.

When testing or producing through a liner, the casing above the liner will be a part of theproduction string and must be designed according to this.



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TENSION (P1M6110-8.3)

4.

Deviated wells : "bending effect"

3.

Add additional load due to bumping the plug

2.

Calculate casing string weight in mud

1.

Calculate casing string weight in air

DESIGN FACTOR 1.70 • C95 Casing grade

P1M6110-7.2.1 1.80 > C95

Table PL 2.7 – Tension



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PL. 2.11. DRILLING FLUIDS PROGRAMME


1.1. The mud programme is drawn up for each phase on the basis of thefollowing aspects:

• Geological information about chemical, physical and naturalcharacteristics of the expected lithology sequence and depths.

• Drilling site: specify on-shore and offshore characteristics.

• Environmental aspects: concerning waste disposal proceduresin compliance with local, current legislation.

• Drilling programme: resuming the expected pressuregradients, casing profiles, deviation design, hydraulicprogramme, time Vs depth diagram, drilling difficulties and rig

equipment.• Minimum stock of mud products at the rigsite and at base

• Required fluids volumes

P-1-N-6001E

1.2. The mud programme shall be submitted to the Company DrillingOffice for approval before to integrate into the Drilling Programme.

P-1-M-6100 5.1

1.3. No variation from the mud programme is permitted without previousdiscussion with and approval of the Company Shore Base Drillingoffice.

P-1-M-6100 5.1

1.4. The hydrostatic pressure applied by the mud must be greater than thehighest formation pressures to effect pressure control.

P-1-M-6100 5.2.2

2. PRELIMINARY INFORMATION Reference

2.1. Pore pressure profile. P-1-M-6100 5.2.2

2.2. Temperature profile. P-1-M-6100 5.2.2

2.3. Lithology column. P-1-M-6100 5.2.5

2.4. Expected hole problems.

2.5. Directional well profile.

2.6. Environmental pollution constraints.

3. GENERAL PARAMETERS FOR A MUD SYSTEM Reference

3.1. Drilling fluid type in each hole section.

3.2. Mud weight in each hole section [kg/l].



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3.3. Chemical & physical propert ies .

3.3.1. Funnel viscosity [seconds/lt.].

3.3.2. Plastic viscosity [centipoise], [centipoise @ ....°C], for OBM.ó

3.3.3. Yield point [g/100cm2].

3.3.4. Gel strengths / 0-10”-10’ [g/100cm2],[g/100 cm

2 @ ... °C], for

OBM.

3.3.5. Water losses [cc./30min @.... °C].

3.3.6. Filter cake [millimetres].

3.3.7. Filtrate HP-HT [cc /30 min @ 300 °F & 500psi].

3.3.8. Solids content [% volume].

3.3.9. Sand content [% volume].

3.3.10. pH.

3.3.11. BMT [kg/m3].

3.3.12. Oil / water ratio.

3.3.13. Oil content for OBM [% volume].

3.3.14. Electrical stability (only OBM) [volt] .

3.3.15. POM (OBM MUD + LC) [H2SO4 N/10].

4. SURFACE EQUIPMENT FOR TREATING & HANDLING MUD Reference

4.1. Solids control equipment

4.1.1. Shale shakers:• Arrangement (in series/parallel).

• Size of screens.

4.1.2. Mud cleaners.

4.1.3. Centrifuges:

• Arrangement (in series/parallel).

• High/low volume.



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5. CONTINGENCY PLANS FOR POTENTIAL HOLE PROBLEMS Reference

5.1. Material selection

5.1.1. Lost circulation materials (fine/medium).

5.1.2. Spotting fluids (high/low density).

5.1.3. Detergents/lubricants.

5.1.4. Corrosion control agents.

5.1.5. High filtration pills.

6. SAFETY REQUIREMENTS Reference

6.1. Minimum stocks.

6.2. Special safety actions.

Reference List :

‘Drilling Fluids Operation Manual’ STAP-P-1-M-6160





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STAP-P-1-M-6090


PL. 2.12. HYDRAULIC PROGRAMME

1. SOFT WARE Reference

1.1. The Eni-Agip IWIS (ADIS) software programme is currently used for all hydraulic programmes and provides all the necessary informationto be input into the ‘Geological Drilling Programme.

P-1-M-6100 6

2. FLOW REGIME DEFINITION Reference

2.1. Optimum f low rate evaluation in each hole section10

2.1.1. Control of hole erosion. P-1-M-6100 6.3

2.1.2. Cuttings removal P-1-M-6100 6.3

2.1.3. Hole cleaning. P-1-M-6100 6.3

2.1.4. Mud formation invasion. P-1-M-6100 6.3

3. FRICTION PRESSURE LOSSES CALCULATION Reference

3.1. Preliminary information

3.1.1. Rheological model definition. P-1-M-6100 6.4

3.1.2. Geometrical system data. P-1-M-6100 6.4

3.1.3. Mud weight. P-1-M-6100 6.4

3.1.4. Flow rate. P-1-M-6100 6.4

3.2. Frictional pressure drop

3.2.1. Pressure drop in surface equipment. P-1-M-6100 6.4.1

3.2.2. Pressure drop in pipe. P-1-M-6100 6.4.2

3.2.3. Specific pressure drop (MWD, downhole motor). P-1-M-6100 6.4.3

3.2.4. Pressure drop in annulus. P-1-M-6100 6.4.6

3.2.5. Pressure drop across the bit. P-1-M-6100 6.4.4

3.3. Surge/swab pressure Vs t ripp ing speed.

10 Common flow rate:

hole size [ins] 17

1

/2” 15 12

1

/4” 9

7

/8” 8

1

/2” 7

7

/8” 6

3

/4” 6flow rate [l/min] 3000÷4000 2800÷3500 2200÷2600 1500÷1900 1200÷1600 1200÷1600 800÷1000 600÷800



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4. BIT NOZZLES SELECTION Reference

4.1. Optimise jet-impact force.

4.2. Max imise hydraul ic bit horsepower .

4.2.1. 1. Evaluate suitable pump rate & max operating pressure (checkpressure rating of all surface equipment).

2. Calculate the friction pressure loss in surface equipment, pipe &annulus.

3. Calculate the amount of pressure available for friction pressuredrop across the bit;

4. Solve the bit pressure drop equation for the flow area.

P-1-M-6100 6.4.4

4.2.2. Eni-Agip design criteria assume (rotary drilling using roller cone bits):

• Max available pump pressure equal to 90% of nominal pumppressure.

• Min nozzle velocity 100 m/s.

• Hole section Ø 81/2” → HSI=8 ÷ 9 (HHP/in

2).

• Hole section Ø 121/4” → HSI=5 ÷ 6 (HHP/in

2).

• Hole section Ø 171/2” (16”) → HSI=3 ÷ 4 (HHP/in

2).

P-1-M-6100 6.4.4


5.1. For each hole section & depth interval, the drilling programme shouldcontain the following information:

P-1-N-6001E

5.1.1. Mud data

5.1.1.1. Mud weight.

5.1.1.2. Plastic viscosity.

5.1.1.3. Yield point.

5.1.1.4. Gel strengths.

5.1.2. Pump data (for each pump)

5.1.2.1. Pump type.

5.1.2.2. Volumetric efficiency.

5.1.2.3. Mechanical efficiency.

5.1.2.4. Liner size.

5.1.2.5. Max pressure & flow rate.



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5.1.2.6. Max hydraulic power.

5.1.3. Flow rate.

5.1.4. Bit nozzles

5.1.4.1. Jets size.

5.1.4.2. Total flow area.

5.1.4.3. Jets velocity.

5.1.5. Hydraulic system data

5.1.5.1. Pressure drop:

Total, surface, pipes, annulus, specific drillstring components & bitnozzles.

5.1.5.2. Hydraulic power.

Total & bit, including:

• Percentage of bit hydraulic power on total hydraulic power.

• Bit hydraulic power/ins2 (HSI).

5.1.6. Impact force.

5.1.7. Equivalent circulating density.

5.1.8. Annular velocity

5.1.8.1. Min & max according to flow rate value.

Software:

Hydraulic programme-IWIS (ADIS)



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PL. 2.13. WELLHEAD

1. GENERAL SERVICE CONDITION (NO SOUR SERVICE) ONSHORE,

OFFSHORE JACK-UP & FIXED PLATFORMS WELLHEAD SYSTEM

Reference

1.1. The standard for exploration and development well are “MultibowlWellhead” (unitized).

However the ‘Flanged Wellhead’ could be an option only for exploration wells, when particular well difficulties are anticipated or when a tie back or a mud-line system is in use.

M-1-M-5020 2.3

1.2. Pressure Classification

1.2.1. AGIP specification divides wellhead equipment into two classes:

• Class-A: equipment designed to operate up to 5,000psi WP• Class-B: equipment designed to operate up to 10,000psi WP

M-1-M-5020 2.1.1P-1-M-6100 8.2

M-1-SS-5701E 1.1

1.3. Pressure Rating

1.3.1. Definition of Working Pressure for Unitised Wellhead Housing isbased on following criteria:

WP= Static Bottom Hole Pressure (SBHP) or

WP= Max Static Tubing Head Pressure x S.F. (STHP x SafetyFactor)

For gas wells S.F. = 1.1

For oil wells S.F. = 1.3 (recommended)

M-1-M-5020 2.1.2

1.3.2. Pressure rating definition, for spool of a Flanged Wellhead, is basedon maximum anticipated surface pressure.

M-1-M-5020 2.1.2

2. MATERIAL Reference

2.1. General Service

2.1.1. Casing Head & casing spool:

• Temperature Classification Class P (-29°C/+82°C) - as per API6A

• Material Class DD - Sour Service - as per API 6A as defined byNACE MR-01-75

M-1-M-5020 2.2.1P-1-M-6100 8.2.1

2.2. Sour Service

2.2.1. To be defined according to the specific service condition.



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3. UNITISED WELLHEAD (COMPACT) Reference

3.1. Unitised wellhead components

3.1.1. Wellhead Housing (with lateral flanged outlet for control line):

Diam e WP Bottom Casing Hanger Top

135/8” 5,000psi slip lock 13

3/8“ 9

5/8”-7”-tbg Hub profile

or pup joint 10’welded/on

135/8” 10,000psi slip lock 13

3/8“ 9

5/8”-7”-tbg Hub profile

or pup joint 10’welded/on

183/4” 5.000 psi slip lock 185/8“ Suitable to install Hub profile(option depend or pup joint 10’on csg programme) a 13

5/8” Housing welded/on

M-1-M-5020 2.3.1

4. FLANGED WELLHEAD Reference

4.1. Flanged wellhead components

4.1.1. Casing head

4.1.1.1. Ref. No. Top flange Max working pressure Bottom (Ø csg).

1.1 263/4” 3,000psi 24

1/2”

1.2 211/4” 5,000psi 20” & 185/8”

1.3 135/8” 5,000psi 13

3/8” & 9

5/8”

M-1-M-5020 2.3.2

4.1.2. Casing head spool

4.1.2.1. Ref. No. Bottom Max WP Top Max WPflange flange

2.1 135/8” 5,000 psi 13

5/8” 5,000 psi

2.2 135/8” 5,000 psi 13

5/8” 10,000 psi

2.3 135/8” 10,000 psi 13

5/8” 10,000 psi

2.4 211/4” 5,000 psi 13

5/8” 5,000 psi

2.5 211/4” 5,000 psi 13

5/8” 10,000 psi

2.6 263/4” 3,000 psi 21

1/4” 5,000 psi

M-1-M-5020 2.3.2

4.1.3. Other wellhead components. M-1-SS-5701E 1.2.2(TABLES 5-6-7)

4.1.3.1. Outlets for casing head/spool (flanged system) and housing (unitisedsystem).

The standard are two outlets studded 21/16”, threaded for VR plug with

the same WP of the casing spool or of the housing.



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4.1.3.2. Cutting operation on c.p. or on casing will be done with mechanicaldevice.

4.1.3.3. Sealing material: Elastomer selected according to wellenvironments.

4.1.3.4. Painting: Suitable for offshore environment.

4.1.3.5. Standardised completion equipment including sequences of casinghead / spool is reported in Table PL 2.8

M-1-SS-5701E 1.2.1(FIG.1-10)

4.1.3.6. Abbreviations used in Table PL 2.8

• MSCL modular single completion land

• DCSFSL dual completion seal flange solid block land• SCSO single completion seal flange offshore

• DCSO dual completion solid block offshore

M-1-SS-5701E 1.5

4.1.4. Eni-Agip standards give a minimum tubing spool bottom flangeØ=13”5/8.

5. MATERIAL REQUIREMENTS Reference

5.1. General service:

Operating context: (NACE MR-01-75)

• Range of operating temperature: –29 - 82 °C• Partial pressure of carbon dioxide: < 7psia

• Hydrogen sulphide partial pressure: < 0,05psia.

P-1-M-6100 8.2.1

5.2. Chemical composition:

• Casing head: AISI 4130 AISI 4125

• Casing spool: AISI 4140 AISI 4135

M-1-SS-5701E 1.5

5.3. Sour service:

Metallic material specification

• Chemical composition

• Hardness: HRC < 22

M-1-SS-5701E 1.5

5.4. Marine Environment:

Protection from marine environment: use coating suitable for saltspray fog.



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6. PRESSURE TESTS Reference

6.1. Hydraulic oil must be used.P-1-M-6140 15.2.3

6.2. Pressure test value doesn’t exceed 70% casing collapse resistance. P-1-M-6140 15.2.3

6.3. During primary & secondary packing group’s test, previous casingspool valve must be kept open.

P-1-M-6140 15.2.5-4

6.4. All pressure tests should be kept for at least 15 minutes. P-1-M-6140 15.2.5-4


Includes the following, minimum information:

• Manufacturer • Base flange: size, working pressure

• Casing spool: size, working pressure

• Tubing spool: size, working pressure

• Well head components

• Height of individual components and total height of well head

• Part number of all components

• Amounts

• The well head diagram will also be included

• Remarks

In the case of cluster wells, a sketch showing the orientation of the

various well heads with respect to true North will be included

P-1-N-6001E 6.3.8

8. UNCONVENTIONAL WELLHEAD SYSTEM Reference

8.1.1. Mudline casing suspension system: The system makes possible thetemporary abandonment of the well in a short time and without casingcutting.

P-1-M-6100 8.5

9. SUBSEA WELLHEAD SYSTEM Reference

9.1. Functional requirements M-1-SS-5708 4

9.2. Engineering requirements M-1-SS-5708 5

Reference List :



‘Operating Procedures for Drawing the ’Well Drilling Programme”’ STAP-P-1-M-6001E

‘Specification for Surface Wellhead and Christmas Tree Standard Equipment’ STAP-M-1-SS-5701E

‘Specification for 10,000 and 15,000 WP Subsea Wellhead System’ STAP-M-1-SS-5708

‘Standardisation of Surface Wellhead and Christmas Tree Equipment’ STAP-M-1-M-5020





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PL. 2.14. WELL CONTROL

1. BOP SELECTION CRITERIA Reference

1.1. Pressure rating

1.1.1. The working pressure of any blow-out preventer shall exceed themaximum anticipated surface pressure to which it may be subjected

P-1-M-6110 12.1

1.2. Eni -Agip BOP-select ion cr iteria

1.2.1. The maximum theoretical pressure at the casing head occurs whenthe well is full of gas and the fracture pressure has been reached atthe weakest point (generally the last casing shoe).

P-1-M-6110 12.1

1.2.2. Production test operations: see point 1.2.1

1.2.3. Drilling operations: 60% of maximum theoretical head pressure hasbeen chosen as limit value.

P-1-M-6110 12.1

1.2.4. A first approximate determination of BOP size for a wildcat well isgiven in the graph reported on the Casing design manual, both for drilling operations and production tests. The anticipated casing settingdepths and pore pressure values are the required information.

P-1-M-6110 12.1P-1-M-6100 9.1

2. EQUIPMENT REQUIREMENTS Reference

2.1. Minimum BOP stack requirements

2.1.1. Land rigs, Jack-up / Fixed platforms:

• 5,000psi WP stack should have at least 2 ram type preventer (1blind or shear ram type and 1 pipe ram type) and 1 bagpreventer

• 10,000psi WP stack should have at least 3 ram type preventers(1 blind or shear ram type and 2 pipe ram type) and 1 bagpreventer

• 15,000psi WP stack should have at least 4 ram type preventers

(1 blind or shear ram type and 3 pipe ram type) and 1 bagpreventer

P-1-M-6150 6.1.1

2.1.2. Land rigs: the shear rams installation will be evaluate with referenceto local law or deduced by ‘risk analysis’ computations.

M-1-M-5005 1.1

2.1.3. The pipe rams preventers shall be equipped, at all times, with thecorrect sized rams to match string in use.

P-1-M-6150 6.1.1-b



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2.1.4. Floating drilling rigs:

A 10,000psi working pressure stack should have at least:• 4 ram-type preventers (1 shear ram and 3 pipe rams,)

• 1 or preferably 2 x 5,000psi annular-type preventers (oneannular retrievable on Lower Marine Riser Package.)

A 15,000psi working pressure stack should have at least:

• 4 ram-type preventers (1 shear ram and 3 pipe rams).

• 2 x 10,000psi annular type preventers (one annular retrievableon Lower Marine Riser Package.)

P-1-M-6150 6.1.2

2.2. Diver ter general requirements

2.2.1. • The diverter must be equipped with two lines facing oppositedirections (offshore applications).

• Minimum diverter outlets 12” ID

• Diverter valves shall be full opening valves, preferably ballvalves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden.

P-1-M-6150 6.6-b-e-g

2.3. Choke / kill lines & manifold

2.3.1. Choke / kill lines, choke manifold shall have a working pressure ratingequal or greater than preventers in use.

P-1-M-6150 6.3-a

2.3.2. Minimum diameter:• Choke line diameter 3” ID

• Kill line diameter 2” ID

P-1-M-6150 6.1.1-g

2.4. Inside pipe shut -off devices

2.4.1. While drilling shallow holes a float valve is used. P-1-M-6150 9.3.1-eP-1-M-6140 4.1.5-1M-1-M-5012 2.5

2.4.2. Blowout equipment available on drill floor:

• Additional lower kelly cock, kept in open position at all time.

• Gray type inside BOP, with appropriate connection for pipe inuse.

• Drop-in type back pressure valve.

P-1-M-6150 6.4-b-d-e

3. BOP & CASING TESTS Reference

3.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests

3.1.1. All BOP stacks will be pressure tested at their rated working pressure,prior to use, on test stumps.

P-1-M-6150 7.2.1



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3.2. Float ing Rig BOP Surface Test

3.2.1. The complete BOP stack assembly shall be tested at the surface ontest stumps:

• At low pressure of 300psi (21kg/cm2).

• At their rated working pressure

P-1-M-6150 7.3

3.3. Ram type preventer tests after instal lation on the wellhead

3.3.1. Pipe rams shall be tested with open-end cup testers to a low pressureof 300psi (21kg/cm

2) and to a high pressure at least equal to the

maximum anticipated wellhead pressure.

P-1-M-6150 7.2.2

3.3.2. In all cases, the maximum test pressure for each BOP test will notexceed 70% of the rated WP of the lowest rated item of equipment inthe wellhead assembly, casing or preventer stack assembly,whichever is the lower.

P-1-M-6150 7.2.2

3.3.3. • An open-end cup tester is required or a blind test plug may bealways used for BOP testing before or after the shoe is drilledout.

• Tests will be carried out with water.

P-1-M-6150 7.2.3

3.3.4. The accumulator system should be capable of closing each ram BOP

within 30 sec

P-1-M-6150 6.2.1-a

3.4. Bag type annu lar preventer tests

3.4.1. The preventer will be tested to low pressure (300 psi), and to a highpressure at least equal to the maximum anticipated wellheadpressure.

P-1-M-6150 7.2.2

3.4.2. Closing time on 5” DP should not exceed 30secs for annular preventers smaller than 18

3/4” nominal bore and 45secs for annular

preventers of 183/4” and larger

P-1-M-6150 6.2.1-a

3.5. Blind/Shear ram type preventer tests after instal lation on thewellhead

3.5.1. Blind/shear rams shall be tested using blind plug testers to the samepressure as stated above for pipe rams.

P-1-M-6150 7.2.2

3.5.2. Where a plug tester is not available, blind/shear rams will be testedagainst the casing each time a new casing string has been set prior to drilling out the cement. In this case the testing pressure will not besucceed 1,500psi (105kg/cm

2).

P-1-M-6150 7.2.2



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3.6. Floating BOP Test During and After Instal lat ion

3.6.1. While running BOP stacks on the riser joints, the choke/kill andbuster lines from surface to the fail-safe shall be pressure tested totheir rated working pressure.

P-1-M-6150 7.3.1-1

3.6.2. After the BOP stack is landed on the wellhead, a full function test onboth pods shall be carried out.

P-1-M-6150 7.3.1-2

3.7. Floating BOP and Seal Assembly Test After Setting Casing.

3.7.1. The seal assembly shall be pressure tested to a maximum pressure,equal to the maximum anticipated wellhead pressure, or 70% of theinternal yield pressure of the weakest item of equipment, whichever is

the lower.

P-1-M-6150 7.3.2-1

3.7.2. All BOP components, shall be pressure tested to a low pressure of 300psi (21kg/cm

2) and to a minimum pressure equal to the maximum

anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.

P-1-M-6150 7.3.2-3

3.8. Kill/choke lines & manifold tests

3.8.1. Every time tests are carried out on the BOP stack, the associatedequipment shall also be tested, with water.

After the first BOP installation, the equipment shall be tested at their rated working pressure.

On routine tests, they will be tested at to least the same pressureapplied for the BOP test.

P-1-M-6150 7.4.4-cP-1-M-6150 7.5

3.9. Casing tests

3.9.1. In all cases the test pressure will be no higher than 70% of APIminimum internal yield pressure of the weakest casing in the string or to 70% of the BOP working pressure.

P-1-M-6150 7.5

3.10. BOP operat ing equipment

3.10.1. All BOP operating equipment hoses, control panels, regulator connections, shall be regularly checked and tested to the maximummanufacturers recommended values for closing and opening BOP.

P-1-M-6150 7.4.3

3.11. Diverter tests

3.11.1. They mainly consist on function test and closing time evaluation.Closing time (on 5” DP):

• 30 seconds : diverter type • < 20”

• 45 seconds : diverter type • • 20”

P-1-M-6150 9.4.3



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4. TESTS FREQUENCY Reference

4.1. BOP-stack

4.1.1. • After installing stack on well head.

• Any time a new casing string is run and cemented.

• Once every 14 days.

• Prior to run a DST or production test assembly.

• Any time required by Company.

P-1-M-6150 7.4

4.2. Kil l/choke l ines, choke manifold, rig floor and cementing

manifold

4.2.1. Every time tests are carried out on the BOP stack, the associatedequipment shall also be tested, with water (see point 4.1.1).:

P-1-M-6150 7.4.4

4.3. Casing

4.3.1. Each casing shall be pressure tested at the following times:

• When cement plug bumps on bottom with a pressure stated inthe drilling programme.

• When testing blind/shear rams of the BOP stack against thecasing.

• After having drilled out a DV collar.

P-1-M-6150 7.5

4.3.2. A cemented liner overlap will be positively tested applying a pressuregreater than the lea-off pressure of the previous casing. If there isany doubt, an inflow test could be carried out, with a sufficientdrawdown to test the liner top to the most severe negative differentialpressure that will exist during the life of the well.

P-1-M-6150 7.6

4.4. BOP operating equipment

4.4.1. Every time BOP stack is nippled up, and after repairing operations. P-1-M-6150 7.5

4.5. Function tests

4.5.1. 1. The pipe ram and BOP valves should be operated at least onceevery shift.

2. Blind/shear rams shall be operated every round trip in the hole.

3. The annular preventer shall be operated when the scheduledroutine BOP tests are performed.

P-1-M-6150 7.4.2



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5. DURATION OF TESTS Reference

5.1. The BOP 300psi low-pressure tests will be performed first. They areto be held for a min period of 5min

P-1-M-6150 7.4.1

5.2. High-pressure tests are held for a minimum of 10mins. The maximumacceptable pressure drop over this 10mins period is 100psi.

P-1-M-6150 7.4.1

6. WELL CONTROL DRILLS Reference

6.1. Familiarity drills

6.1.1. The purpose of these drills is to familiarise rig personnel with thevarious equipment and with the techniques that will be employed inthe event of a kick.

P-1-M-6150 7.1.1.b

6.1.2. These tests shall be carried out on an each shift basis, at thebeginning of any new activity, any time experienced personnel arereplaced with new recruits, especially when key position personnelare involved such as the Toolpusher, Driller and Assistant Driller.Drills shall be repeated until every crew member gains the correctexperience and training.

P-1-M-6150 8.6.1

6.2. Emergency “On-the-rig” drills

6.2.1. Simulate potential blowout situation. Drilling Contractor’s crew should

follow the close-in procedure according to the current operations (biton bottom, tripping).

P-1-M-6150 8.1.1

6.2.2. Potential fire on wellsite and rig location abandonment simulation. P-1-M-6150 8.2.1

6.2.3. Tests shall be executed on each shift basis every week. P-1-M-6150 8.6.1

6.3. Pit drills

6.3.1. Simulate changes in the pit level indicator. Drilling Contractor’s crewshould follow the close-in procedure according to the currentoperations (bit on bottom, tripping).

P-1-M-6150 8.3.1

6.3.2. Tests shall be carried out:

• Each shift basis every fortnight.

• When the well is nearing or entering high-pressure zones.

P-1-M-6150 8.6.1

6.4. Choke Manipulation drill

6.4.1. The test shall be carried out before drill out the shoe track atintermediate casing string

P-1-M-6150 8.6.1



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6.5. Drills evaluation

6.5.1. Drills evaluation is mainly based on performing time. Correct timingshould be defined in Drilling Contractor’s procedures according to theequipment.

P-1-M-6150 8.6.2

6.5.2. Pit drills:

Not more than 2.5 minutes from a readable change in drilling fluidvolume to the time the well is closed-in or drill pipe started runningback in hole if during trip.

P-1-M-6150 8.6.2

6.5.3. ‘On-the-rig’ drills :

One minute time from giving the alarm signal to have the preventer closed.

P-1-M-6150 8.6.2

7. PRIMARY WELL CONTROL Reference

7.1. General remarks

7.1.1. Underbalance drilling operations, which are not admitted on wildcatwells, shall be approved by Company Operative Base DrillingSuperintendent through a detailed drilling programme.

P-1-M-6150 2.1.1

7.1.2. Primary well control is mainly based on prediction of formationpressure. It depends on correct mud weight evaluation and proper

operating practices.

P-1-M-6150 2.1.1

7.2. Tr ip margin & equivalent mud weight

7.2.1. If while tripping out a swabbing is noted (the well is not flowing):

• Stop the trip

• Run back to bottom

• Circulate bottom up

• Resume tripping carefully.

P-1-M-6150 2.2.3

7.3. Mud volume control

7.3.1. A minimum kill mud volume of 70m3 at 1.4kg/ft shall be stocked while

drilling surface hole without BOP-stack. Anyway, at least minimummud volume must be equal to three times internal drillstring volume.

P-1-M-6140 6.5-nP-1-M-6150 9.3.1-g



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7.4. Maximum Allowable Annular Surface Pressure (MAASP)

7.4.1. The MAASP is representative of a specific drilling section, it dependson the following factors:

• Last casing shoe depth

• mud weight

• Minimum formation fracture gradient below the casing shoe

• minimum last casing burst pressure resistance.

P-1-M-6150 2.1.4

7.5. Ci rculat ing pressure at reduced pumping rate

7.5.1. Reduced pump stroke pressure (RPSP).

Normal circulation flowrate reduced to Q/3 in 121/4” hole and Q/2 in8

1/2” hole.

RPSP must be taken at the following times as a minimum:

• Once per tour, or every 300m (1,000ft) intervals.

• When there is any significant changes in the mud weight or mudproperties.

• Whenever changes occur in the dimension and characteristics of the string, i.e. change in BHA, jet size, jet plugged or jet lost, etc

P-1-M-6150 2.1.5

7.5.2. On floater rigs, the RPSP shall be measured by circulating, first

through the riser and then through the choke/kill line.

P-1-M-6150 2.1.5

7.6. Drilling break

7.6.1. Any time a drilling break is noticed:

• Drilling shall be stopped immediately

• Static control shall be carried out.

P-1-M-6150 2.1.3

8. SECONDARY WELL CONTROL Reference

8.1. Well control decision tree

8.2. Well shut-in procedures P-1-M-6150 3

8.3. Killing procedures P-1-M-6150 5

Reference List :







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PL. 2.15. CEMENT PROGRAMME

1. PRELIMINARY INFORMATION Reference

1.1. In a cementing job the factors, that guide the selection of theadditives for the control of the slurry, flow properties and thickeningtime are:

• The annular configuration

• Wellbore conditions

•••• The mud type and density

• Temperature gradient

P-1-M-6100 7.8

2. SLURRY DESIGN Reference

2.1. Total slurry volume calculation (lead/tai l slurry volumes)

2.1.1. Always a percentage increment in volume must be considered for theopen hole section. In absence of relevant data, can be assumed:

• Surface casing: 100 %

• Intermediate casing: 50 %

• Production casing: 30 %.

P-1-M-6100 7.8.1

2.1.2. If logs are available, assume a percentage increment in volume equalto 10%.

P-1-M-6100 7.8.1

2.2. Slurry density evaluation.

2.2.1. Circulating bottom hole and static temperatures need to beconsidered as well as the temperature differential between the bottomand top of the cement column.

P-1-M-61007.8.3

2.2.2. Circulating temperatures by calculation in accordance withtemperature schedules published in API 10 Specification

P-1-M-6100 7.8.3

2.2.3. One rule of thumb which should apply to the slurry design, is toensure that the static temperature at the top of the cement exceedsthe circulating bottom hole temperature

P-1-M-6100 7.8.3

2.3. Type & amount of cement

2.3.1. The cement type selection is mainly based on estimated bottom holetemperature.

P-1-M-6100 7.1.1

2.4. Amount & composition of mix water. P-1-M-6100 7.1.2



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2.5. Amount & type of additives

2.5.1. Weighting/lightening agents (barite, hematite, diatom, bentonite). P-1-M-6100 7.2.3/4

2.5.2. Retarders. P-1-M-6100 7.2.2

2.5.3. Accelerators. P-1-M-6100 7.2.1

2.5.4. Fluid loss reducers.

2.5.5. Friction reducers.

2.6. Slurry rheology properties evaluation. P-1-M-6100 7.5

2.7. Slurry fluid loss evaluation. P-1-M-6100 7.5

2.8. Slurry thickening time. P-1-M-6100 7.8.4

2.9. Slurry settlement properties. P-1-M-6100 7.8.4

2.10. Slurry compressive strength. P-1-M-6100 7.5

2.11. Laboratory tests

2.11.1. Before start with job on rig site, laboratory tests shall be performed

using samples of actual cement, water and additives.

P-1-M-6100 7.6

3. SPACER DESIGN Reference

3.1. Spacer volume calculation

3.1.1. Unless an effective mud density is required to control the formationpressure, all cement jobs shall be flushed with a water spacer.

The spacer volume shall be equivalent to, more or less, tree minutesof contact time or 150m of annulus capacity.

P-1-M-6140 12.3.1-6P-1-M-6100 7.4

3.2. Spacer density evaluation

3.2.1. The best spacer is a spacer that has a density higher than the mudbut less than the cement slurry.

P-1-M-6100 7.4

3.3. Chemical composition

3.3.1. The spacer fluid must be compatible with both the mud and the slurrysystem, laboratory test shall be carried out.

P-1-M-6100 7.4

3.4 Spacer fluid rheology properties evaluation P-1-M-6100 7.4



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4. HYDRAULIC CALCULATIONS Reference

4.1. Flow rates for cement displacement

4.1.1. Displace at maximum allowable flow-rate. Normally turbulent flow inthe annulus is preferred, in any case always monitor return.

4.2. Estimated pressure profile

4.2.1. Plot versus time/volume the following parameters:

• Surface circulating pressure

• Bottom hole pressure

• Previous casing shoe pressure

• Any critical zone.

5. PLACEMENT TECHNIQUES Reference

5.1. Sing le or mul tistage cementing operat ion

5.1.1. Perform second stage operations as soon as cement setting time of first stage is expired (at least twice the time thickening time). Lab testis recommended.

P-1-M-6140 12.3.2-7

5.2. Inner string

5.2.1. All surface casing will be cemented through inner string.

5.3. Liner cementing operation.

5.3.1. Under normal conditions, the liner will be hung with a 100 to 150moverlap into the previous casing. If a smaller overlap is necessary dueto a particular situation, it shall never be less than 50m

P-1-M-6140 12.7.1-3

5.3.2. If the rat hole exceeds the overlap length, set a cement plug at adistance from the liner shoe setting depth shorter than the overlapitself.

P-1-M-6140 12.7.1-3

5.4. Tie-back string cementing operation.

5.5. Casing cementing operation in sub-sea wells.

6. DOWN HOLE EQUIPMENT SELECTION Reference

6.1. Casing shoe

6.1.1. Guide shoe.

6.1.2. Float shoe.



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6.2. Collar

6.2.1. Float collar.

6.2.2. Multistage collar.

6.3. Casing centralisation programme

6.3.1. Number & type of centralisers.

6.3.2. Number & type of scratchers.

6.3.3. In floating rig-drilling operations the number of centralisers must belimited. Avoid the use of scratchers.

6.4. Cementing plugs

6.4.1. Non rotating PDC drillable plugs are recommended. P-1-M-6140 12.3.1-8

7. SURFACE EQUIPMENT SELECTION Reference

7.1. Type & pressure rat ing of cementing head.

7.1.1. As alternative the circulating head can be requested with a bottomquick seal connection (without thread).

A-1-SS-1729 5.3.7

7.2. Number of cementing units.

7.2.1. It must be provided with twin triplex pumping units for pumping thecement slurry, for high pressure mixing and for general pumpingoperations

A-1-SS-1729 5.3.1-1

7.3. Number & volume of avai lable tanks

7.3.1. It is recommended to mix slurry in advance using batch mixer.

7.4. Layout of surface cementing equipment.

8. OPERATING PROGRAMME Reference

8.1. Summary of operations

8.1.1. Testing pressure for surface lines: 5,000psi. P-1-M-6140 12.3.1-4

8.1.2. Stop displacement in advance only if pressure exceeds 70% of casing burst pressure or 5,000psi, whichever is less.

P-1-M-6140 12.3.1-20



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8.1.3. Prior to mix cement, water shall be checked. When mixing cement,samples of slurry shall be collected. Also take mixing water samples

and dry cement samples from each tank used.

P-1-M-6140 12.3.1-11

8.1.4. In jack-ups and fixed platforms drilling operations, at end of surfacecasing cementing job, carefully wash the annulus between CP andsurface casing to at least 5meters below the sea bottom, in order toallow well abandoning operations according to specifications

11.

P-1-M-6140 12.3.1-28

8.2. Displacement

8.2.1. • The displacement volume (for 30” CP and surface casing)should be 1 bbls less than the theoretical volume.

• Max over displacement volume equal to1/2 of shoe-collar

volume.

P-1-M-6140 12.3.1-28

8.3. Surface pressure at bump plug

8.3.1. The bumping pressure values are always given in the DrillingProgramme.

P-1-M-6140 12.3.1-23

8.4. Parameters recording

8.4.1. Record all mixing, displacing and bumping operations (pressure, flowrate, total volume versus time).

P-1-M-6140 12.3.1-29

8.5. Total Job time

8.5.1. Compare total job time (including mixing time), to pumpability time.

8.6. Time for W.O.C.

8.6.1. • According to laboratory tests results (if done) or 2-3 timesthickening time (check the samples, for surface jobs).

• Check always annulus level.

• Whenever it is possible close BOP and pressurise up to 100-200psi according to weakest fracturing point.

Reference List :‘Drilling Procedures Manual’ STAP-P-1-M-6140


‘Cementing and Pumping Service For Drilling Completion and Workover Activity STAP-A-1-SS-1729

11 In order to have the sea bed free from any obstructions, it is recommended in well abandonment operations to recover at least 5

meters of casing strings below the seabed.



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PL. 2.16. DRILL STRING DESIGN

1. DESIGN PARAMETERS Reference

1.1. Anticipated total depth.

1.1.1. The design of the drill string for static tensile loads requires sufficientstrength in drill pipe to support the submerged weight of drill pipe anddrill collar below.

P-1-M-6100 10.11

1.1.1.1.

bccdpdp K)]WL(+)WL[(=P

where:P = Submerged load

Ldp = Length of drill pipe in feet

Lc

= Length of drill collar in feet

Wdp = Weight per foot of drill pipe in air

Wc

= Weight per foot of drill collar in air

Kb

= Buoyancy factor

P-1-M-6100 10.11

1.2. Hole size.

1.2.1. Drill string acceptability (Refer to Table PL 2.9)P-1-M-6100 10.8

1.3. BHA Buckling

1.3.1. In the design of BHA, it is important to determine the critical values of weight on bit at which buckling occurs.

P-1-M-6100 10.9.

1.4. Formation type & dip.

1.4.1. Crooked hole drilling tendencies.

Standard packed hole assembly should be:

Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K MonelDC + String Stab + 2 DC + String Stab

P-1-M-6100 10.12

1.4.1.1. Mild crooked hole. P-1-M-6140 8.5-a

1.4.1.2. Medium crooked hole. P-1-M-6140 8.5-a

1.4.1.3. Severe crooked hole. P-1-M-6140 8.5-a



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1.4.2. Formation firmness.

Degree of drillability of the formations.• Hard to medium hard formations

- Abrasive

- Non abrasive

• Medium hard to soft formations

P-1-M-6140 8.5-b

1.5. Hole deviation

1.5.1. Hole angle control.

• Packed bottom hole assembly.

• Pendulum bottom hole assembly.

P-1-M-6140 8.3

1.5.2. BHA analysis in directional drilling PL.02.01-8.1

1.6. Concent rat ions in bending st resses

1.6.1. The (I/C) ratio12

is assumed as criterion to evaluate the resistance atbending.

• Soft formation (I/C)ratio < 5,5

• Hard formation (I/C)ratio < 3,5

P-1-M-6100 10.8P-1-M-6140 8.8

1.7. Margin of overpull (MOP)13

.

1.7.1. The minimum recommended value of MOP is 6,0000lbs P-1-M-6100 10.11P-1-M-6140 8.11

1.8. Torque & drag evaluation

1.8.1. Software applications.

1.9. Differential sticking.

1.10. Hydraulic requirements. PL.02.13

12 I, moment of inertia; ( )ID4OD464

I −π

=

C, radius of tube;2

ODC =

(I/C)ratio (I/C)large pipe/(I/C)small pipe

13 MOP=Pa-PP, acting tension load Pa,max allowable design tension load; Pa=90% Pt

Pt, theoretical max tension load



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1.11. Casing wear .

1.11.1. Software applications. PL.02.05 4.1

1.12. Drill stem corrosion & sulphide stress cracking. P-1-M-6110 9.2.1

Reference List :






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Hole Size

(ins)

Drill Collar/Drill Pipe

(ins)I/C I/C Ratio Remarks

DC 91/2 x 3 83.8 1.5

DC 81/4 x 21

3/16 55.9 9.8

DP 5 x 19.5lbs/ft 5.7 - Not

DC 91/2 x 3 83.8 1.5 Recommended

DC 81/4 x 2

13/16 55.9 7.1

DP 51/2 x 19.5lbs/ft 7.8 1.4

DP 5x 19.5lbs/ft 5.7 -

17

1

/2 DC 9

1

/2 x 3 83.8 1.5 OK for DC 8

1/4” x 2

13/16 55.9 5.2 SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

DC 91/2 x 3 83.8 1.5

DC81

/4 213

/16”

55.9 2.5 OK For HARD

DC 61/4 x 2

13/16” 22.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

Note: For every hard formations, add HWDP

DC91

/2” x 3” 83.8 1.5

121/4” DC 8

1/4 x 2

13/16” 55.9 2.5 OK For HARD

DC 61/4 x 2

13/16 22.7 3.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

Note: For every hard formations, add HWDP

DC91

/2” x 3” 83.8 1.5

121/4” DC 8

1/4 x 2

13/16” 55.9 5.2 OK For SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5 lbs/ft 5.7 -

DC 61/4 x 2

13/16” 22.7 Not

DP 5” x 19.5lbs/ft 5.7 3.9 Recommended

85/8 DC 6

1/4 x 2

13/16” 22.7

HWDP 5” x 42.6lbs/ft 10.7 Recommended

DP 5” x 19.5lbs/ft 5.7

Table PL 2.9 - Drill String Acceptability



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PL. 2.17. BIT SELECTION & DRILLING PARAMETERS

1. FACTORS AFFECTING BIT SELECTION Reference

1.1. Main factors to consider and evaluate

1.1.1. • Bit cost

• Method of drilling (turbine, rotary, air)

• Formation type and properties

• Mud system

• Rig cost

P-1-M-6100 11.1

1.2. To opt imise the dr il ling operat ions.

1.2.1. Monitoring the drilling performance and conditions on the prospectwell so that the performance is equal to or above the average in thearea.

P-1-M-6100 11.1

1.2.2. Implementing a bit weight-rotary speed programme based ontheoretical calculations that will improve the performance above theexisting best performances in the area.

P-1-M-6100 11.1

1.3. Parameters involved in the selection of dri ll bi ts

1.3.1. In hard and abrasive formations roller bits in IADC code range 6-1-7or higher are usually more successful.

P-1-M-6100 11.4.1

1.3.2. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness.

P-1-M-6100 11.4.2

1.4. Direct ional dri lli ng considerat ions

1.4.1. Rotary drilling to right-hand walk is increased when using roller bitsare used as cone offset from the bit centre increases.

P-1-M-6100 11.4.3

1.4.2. PDC bits with their relatively lower bit weights and no cones, hencecone offset problems are favoured.

P-1-M-6100 11.4.3

1.5. Rotating system

1.5.1. Rotary table / top drive system.

1.5.2. Down-hole motor

1.5.2.1. Using turbine, bits with long life expectancies should be used such asPDC, diamond and journal bearing insert bits.

P-1-M-6100 11.4.4

1.5.2.2. Turbine drilling may have a tendency to left-hand walk. This iscontrolled by the turbine used, bit gauge length, and BHA stabilisation

P-1-M-6100 11.4.3



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1.6. Geological requirements

1.6.1. Minimum cutting size.

1.7. Mud type

1.7.1. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness.

P-1-M-6100 11.4.2

1.8. Available bit records analysis.

1.9. Drilling cost optimisation

1.9.1. Representative bit-cost curves.P-1-M-6100 11.6

Reference List:




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PL. 2.18. EXPECTED DRILLING PROBLEMS & RECOMMENDATIONS

1. DRILLING DIFFICULTIES Reference

Describe the drilling difficulties encountered in reference wells,detailed by phases.

P-1-M-6001E

2. SUGGESTIONS Reference

Suggestions must be provided in order to prevent or manage at bestall the expectable difficulties.

P-1-M-6001E

3. GENERALITIES Reference

3.1. In the operative sequence of the drilling programme, for each phasein a specific paragraph will be reported the drilling problems that will

include a specific contingency plan to cover each of them.

P-1-N-6001E 6.2

4. LOSSES CIRCULATION Reference

4.1. Preventive measures

4.1.1. Mud characteristics

4.1.1.1. Particularly in surface holes, maintain high mud viscosity values. OP.02 12-9.1.2

4.1.1.2. Keep the mud weight as low as possible providing for adequateoverbalance.

P-1-M-6140 17.1-1

4.1.1.3. Maintain low yield point and gel strengths. P-1-M-6140 17.1-1

4.1.2. Drilling parameters

4.1.2.1. Avoid high circulation rates. P-1-M-6140 17.1-4

4.1.2.2. Always start pumping slowly.

4.1.3. Miscellaneous

4.1.3.1. Use bit nozzles larger than 14/32”. P-1-M-6140 17.1-9

4.1.3.2. While tripping: minimise surge pressure. P-1-M-6140 17.1-5

4.2. Remedial actions

4.2.1. Refer to Figure PL 2.4 P-1-M-6160 6.1



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5. DIFFERENTIAL STICKING Reference


5.1.1. Mud characteristics.

5.1.1.1. Use mud with minimum solids content and low filtrate in order to havea thin wall cake.

P-1-M-6160 7.1P-1-M-6140 16.1.1-3

5.1.1.2. Reduce the friction factor adding mud lubricants. P-1-M-6140 16.1.1-4

5.1.1.3. Reduce mud weight as much as possible, maintaining the minimumdifferential pressure necessary for a safe trip margin.

P-1-M-6160 7.1P-1-M-6140 16.1.1-1

5.1.2. BHA composition

5.1.2.1. Reduce the potential contact surface by using spiral type drill collars. P-1-M-6140 16.1.1-2

5.1.2.2. Use a minimum number of drill collars, insert stabilisers according towell situation.

P-1-M-6140 16.1.1-2

5.1.2.3. Whenever it is possible replace drill collars with HWDP. P-1-M-6140 16.1.1-2

5.1.2.4. Consider the use of a drilling jar/bumper. P-1-M-6140 16.1.1-6

5.2. Remedial actions

5.2.1. Oil pills

5.2.1.1. Light oil pills. P-1-M-6140 16.4.1P-1-M-6160 7.1

5.2.1.2. Heavy oil pills used for specific gravity greater than 1350 g/l. P-1-M-6140 16.4.2P-1-M-6160 7.1

5.2.1.3. Operational planning:

volume evaluation

• Hydrostatic pressure balance

• Displacement techniques.

P-1-M-6140 16.4.1P-1-M-6140 16.4.2P-1-M-6160 7.1

5.2.2. Acid pills P-1-M-6140 16.4.3

5.2.2.1. The use of acid pills can be successful if the string gets stuck acrossof a carbonate formation. This method should be carried out only if others will be ineffective, unless former experiences.

P-1-M-6140 16.4.3P-1-M-6160 7.1

5.2.2.2. The proper amount of corrosion inhibitor must be used and the acidpill will be spaced with oil or water ahead and behind.

P-1-M-6140 16.4.3



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5.2.2.3. Operational planning see point 3.2.1.3.

Whenever acid is handled, the appropriate safety measures shall beadopted

P-1-M-6140 16.4.3

6. CAVING HOLE Reference



6.1.1.1. Possible mud changes are:

• Reduce water losses.

• Lower pH value to 8.5 to 9 (if needed).

• Use inhibited mud.

• Use inhibited mud and polymer.

• Add mud stabilising compounds (mainly sodium asphaltsulphonate).

• Increase the mud weight.

P-1-M-6140 16.3

6.1.2. BHA composition (to avoid stuck pipe)

6.1.2.1. Possible BHA changes are:

Use bits without nozzles, particularly when reaming, to avoid scouring

the well.• Use the minimum acceptable number of stabilisers.

P-1-M-6140 16.3P-1-M-6160 7.1

6.1.3. Drilling parameters

6.1.3.1. Possible changes in parameters are:

• Reduce rotary speed, if possible, to 80rpm or less.

• Reduce the mud flow rate to obtain laminar flow in the annulusbetween hole and drill collars.

• Avoid long circulation times across unstable sections.

• Do not rotate pipe when tripping. Use a spinner or chain out.

• Trip out with care to avoid swabbing. If any swabbing occurs,pull out with the kelly on.

P-1-M-6140 16.3

6.1.3.2. If the string gets stuck in front of carbonate formation: spot an acidpill, see point 3.2.2.

P-1-M-6140 16.3P-1-M-6160 7.1



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7. HOLE RESTRICTION Reference



7.1.2. Reduce mud filtrate and solids content. P-1-M-6140 16.2P-1-M-6160 7.1

7.1.3. Increase mud weight if possible. P-1-M-6140 16.2P-1-M-6160 7.1

7.1.4. Use inhibited mud. P-1-M-6140 16.2P-1-M-6160 7.1

7.1.5. Drilling parameters:

7.1.6. Increase flow rate. P-1-M-6140 16.2P-1-M-6160 7.1


7.1.7.1. Follow accurately sigmalog development..

7.1.7.2. Make frequent wiper trips. P-1-M-6140 16.2

7.2. Remedial actions P-1-M-6140 16.2

7.2.1. Spot oil-based mud or oil containing a surfactant around the BHA. P-1-M-6140 16.2P-1-M-6160 7.1

7.2.2. Work the pipe applying slack-off if the string has become stuckpulling out, and overpull if it stuck while running in.

P-1-M-6140 16.2.1

7.2.3. Increase the mud weight, if possible. P-1-M-6140 16.2.3

7.2.4. Use a drilling jar/bumper. P-1-M-6140 16.2.4

7.2.5. If the string gets stuck in front of carbonate formation: spot an acidpill, see point 3.2.2.

P-1-M-6140 16.4.3P-1-M-6160 7.1

8. HOLE IRREGULARITIES Reference


8.1.1. Bottom hole assembly

8.1.1.1. The formation of dog legs can be prevented by the use of packedbottom hole assemblies.

P-1-M-6140 16.3.1P-1-M-6160 7.1

8.1.1.2. Dog legs can be eliminated by using very stiff BHA's and reamers. P-1-M-6140 16.3.1



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8.1.2.1. A key seat can be eliminated by reaming it with a key seat wiper or anunder-gauge stabiliser installed on the top of the drill collars.

P-1-M-6140 16.3.1P-1-M-6160 7.1

8.1.2.2. Always ream a whole interval drilled with the previous bit. P-1-M-6140 16.3.1

8.1.2.3. Always ream the cored section, even if a full gauge core bit was used. P-1-M-6140 16.3.1

8.2. Remedial actions (stuck pipe)

8.2.1. Work the pipe applying slack-off if dog leg or key seat (the stringbecomes stuck pulling out) and overpull if running a new BHA (thestring becomes stuck while running in the hole).

P-1-M-6140 16.3.1.1

8.2.2. Spot oil-based mud or oil containing a surfactant around the BHA. P-1-M-6140 16.3.1P-1-M-6160 7.1

8.2.3. If the stuck point is in a calcareous section, spot an acid pill. (seepoint 3.2.2).

P-1-M-6140 16.3.1P-1-M-6160 7.1

9. HYDROGEN SULPHIDE GUIDELINES Reference

9.1. Generalities

9.1.1. It is compulsory that the Drilling Contractor has an ‘Emergency SafetyPlan’ including a specific procedure for the presence of H2S.

P-1-M-6150 10.1P-1-M-6160 4.1.4

9.1.2. Adoption of safety measures while circulating bottom-up. P-1-M-7130 20.6.3P-1-M-6150 10

9.2. Drillsite location

9.2.1. Surface elevation / wind direction / access road / briefing area. P-1-M-6150 10.1

9.3. Mater ial specif icat ions ‘sour service’

9.3.1. Tubular goods / wellhead / blowout preventer equipment / chokemanifolds.

P-1-M-6110 9

9.3.2. Drill pipe inspections.

9.4. Drilling fluids

9.4.1. Use H2S scavengers. P-1-M-6150 10.9.6

9.4.2. Use corrosion inhibitors.



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9.5. Safety requirements for particular operat ions

9.5.1. Core Recovery In Presence Of H2S

After coring in a H S bearing formation, it is necessary to wear theCascade System masks (if available ), or Self Breathing Apparatuswith 30-45min bottles, during the whole core recovery operation, bothusing a rubber type core barrel or a inner tube core barrel.

P-1-M-6150 10.2.3

9.5.2. Drill stem testing.

9.5.3. Logging and perforating.

9.6. Rig safety equipment

9.6.1. H2S detection system

9.6.1.1. H2S detection in air. P-1-M-6150 10.10.1P-1-M-7130 20.2.1

9.6.1.2. The system measuring capacity must be 0-50ppm in air.

Danger thresholds are set as follows:

• Pre Alarm: for a concentration between 10ppm and 20ppm inair;

• Alarm: for a concentration upper of 20ppm. in air

P-1-M-6150 10.10.2

9.6.2. Breathing apparatuses. P-1-M-7130 20.7.2/4P-1-M-6150 10.11

9.6.3. Wind direction indicators. P-1-M-7130 20.7.6P-1-M-6150 10.14

9.6.4. Ventilation equipment. P-1-M-7130 20.7.3P-1-M-6150 10.14

9.6.5. Inspection and maintenance of detection/protection systems. P-1-M-6150 10.16

9.7. Alarm & emergency drills

9.7.1. Results shall be reported on the IADC daily drilling report and on thededicated form. It is important to measure the time required for personnel gathering and being accounted at the meeting point.

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9.7.2. Drills frequency

9.7.2.1. Alert or emergency drills when the presence of H2S is either predictable or ascertained are to be performed weekly (during a trip),no-routine drills shall be performed before:

• Entering in a H2S zone

• Coring job

• DST or well testing

• Drilling an overpressured zone.

P-1-M-6150 10.9.3

9.8. Operating procedures

9.8.1. Pre Alarm: for a concentration between 10ppm and 20ppm in air;P-1-M-7130 20.5.2P-1-M-6150 10.3.2

9.8.2. Alarm: for a concentration upper of 20ppm. in air P-1-M-7130 20.5.3P-1-M-6150 10.3.3

9.8.3. Emergency conditions. P-1-M-6150 10.4.1

Reference List :

‘Well Test Procedures Manual’ STAP-P-1-M-7130

‘Well Control Policy’ STAP-P-1-M-6150

‘Drilling Procedures Manual’ SPAP-P-1-M-6140

‘Operating Procedure For Drawing The ‘Well Drilling Programme’’ STAP-P-1-N-6001E



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Figure PL 2.4- Lost circulation control techniques

A L M O S T T O T A

L

m o r e t h a n 5 0 %

S P O T P I L L S

W I T H L C M

H I G H

F I L T R A T I O N

M I X T U R E

G E L C E M E N T

D O B C

A E R E T E D F L U I D S

S T I F F - F O A M

S E

E P A G E

L O S S

l e s s

t h a n 5 0 %

S U R F A C E

A R E A S

H

I G H L Y

P E R

M E A B L E

F R A C T U R E S

H I G H V I S C O S I T Y

F L U I D A N D H I G H

G E L S


F

L U I D

- L C M I N C I R C U L A T I O N

- H I G H F I L T R A T I O N F L U I D

S P O T P I L

L W I T H L C M

H I G H / V E R Y H

I G H F I L T R A T I O N

M I X

T U R E

T O T A L

F R A C T U R E S

H I G H

F I L T R A T I O N

M I X T U R E

C E M E N T / G E L

C E M E N T

S L U R R I E S

D O B C

C A V E R N S

G E L - C E M E N T

S L U R R I E S

C E M E N T +

G E L S O N I T E

D O B C

H Y D R A U L I C A L L Y - I N D U C E D

F R A C T U R E S

L O W

D E N S I T Y

F L U I D S

S E T T I M E L O W

L O A D I N G

H I G H

F I L T R A T I O N

M I X T U R E

D O B

D O B C


S T I F F - F O A M

H I G H D E N S I T Y

F L U I D S

F L U I D T H I N N I N G

A N D / O R

U N W E I G H T I N G

H I G H F I L T R A T I O N

M I X T U R E

F R A C T U R E S


S T I F F - F O A M



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PL. 2.19. WELL ABANDONING

1. GENERAL GUIDELINES Reference

1.1. Consent for well abandonment

1.1.1. On the basis of information available during the planning phase setout a program for well abandoning (temporary or permanent)

P-1-N-6001E 6.2.8

1.2. Purposes in wel l abandoning operat ions

1.2.1. To ensure full and permanent isolation of formation fluids anddifferent pressure regimes.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2P-1-M-6140 14.2.2

1.2.2. To free, in offshore operations, the seabed from any obstructions. P-1-M-6100 14.2.2P-1-M-6140 14.2.2P-1-M-6100 14.1.2P-1-M-6140 14.1.2

1.3. Abandonment p rogramme contents

1.3.1. Well identification data. P-2-N-6001E 7.1.1

1.3.2. The operations to perform for the abandonment (temporary or permanent) of the well, including the following minimum information:

• Open hole abandonment procedures

• Tested intervals perforations squeeze-off procedures

• Temporary abandonment of opened producing intervals

• Setting of bridge plugs - cement retainers• Sequence and height of cement plugs and their eventual testing

• In-hole fluids characteristics

• Eventual temporary completion/killing string composition

• Eventual casing cutting and recovery specifications

• Well head/mud line temporay abandonment/recovery

• Surface restoration, if any.

P-1-N-6001E 6.2.8

2. TEMPORARY ABANDONMENT

2.1. During drilling operations P-1-M-6140 14.1.1

2.1.1. All hydrocarbon zones shall be individually isolated by means of amechanical plug. Them a cement plug shall be set at last 50-100metres in length into the casing and between 20-50meters belowground level/sea bed.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.2. Last casing string above open hole section shall be sealed with acement plug extending at least 50metrers above and below thecasing shoe.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.3. The top of cement plug shall be located and verified by mechanicalloading.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1



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2.1.4. If hole/formation conditions make cementing difficult, a mechanicalplug must be positioned in the lower part of casing (not more than 50

meters above the shoe).

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.5. A cement plug at least 20meters long shall be placed on top of mechanical plug.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.6. A cement plug, at least 50-100meters long, shall be set with its topplaced at least 20-50meters below the ground level / seabed.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.7. The top of cement plug shall be located and verified by mechanicalloading.

P-1-M-6100 14.1.1P-1-M-6140 14.1.1

2.1.8. In case a liner has been set, a cement plug shall be placed, it isextending at least 50meters above and below the top liner.

P-1-M-6100 14.2.2

P-1-M-6140 14.2.2

2.2. Plugging programme before a product ion test

2.2.1. Open hole with permeable zones containing fluid: all zones shall beindividually isolated with cement plugs. Each plug shall be located atleast 50 meters above and below the zone.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

2.2.2. The top of each cement plug shall be located and verified bymechanical loading.

P-1-M-6100 14.1.2-1P-1-M-6140 14.1.2-1

2.2.3. Last casing string above open hole section shall be sealed with acement plug, it is extending at least 50meters above and below thecasing shoe.

P-1-M-6100 14.1.2-1P-1-M-6140 14.1.2-1

2.2.4. The top of each cement plug shall be located and verified bymechanical loading.

P-1-M-6100 14.1.2-1P-1-M-6140 14.1.2-1

2.2.5. If hole/formation conditions make cementing difficult, a mechanicalplug must be positioned in the lower part of casing (not more than50meters above the shoe).

P-1-M-6100 14.1.2-1P-1-M-6140 14.1.2-1

2.2.6. A cement plug at least 20meters long shall be placed on top of

mechanical plug.

P-1-M-6100 14.1.2-1

P-1-M-6140 14.1.2-1

2.2.7. The above mentioned plugs shall be verified by mechanical loadingand pressure tested.

P-1-M-6100 14.1.2-1P-1-M-6140 14.1.2-1

2.3. Plugging Programme af ter a product ion test P-1-M-6140 14.1.2.2

2.3.1. Uninteresting perforated zones. All intervals shall be isolated bymeans of a mechanical plug and shall be squeeze cemented.

P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2



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2.3.2. If the injection through formation is expected to be negative, a cementplug shall be placed with its upper and lower ends located at least 50

meters above and below the perforated zone respectively, or down tothe nearest plug if the distance is less than 50meters.

P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2

2.3.3. A bridge plug shall be placed on top of cement plug. P-1-M-6140 14.1.2.2

2.3.4. All the plugs shall be tested. P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2

2.3.5. Interesting perforated zones.

These intervals shall be isolated by means of mechanical plug.

P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2

2.3.6. A cement plug, at least 20meters long, shall be set above the bridge

plug.

P-1-M-6140 14.1.2-2

2.3.7. A cement plug, 50-100meters long, shall be set between 5-50metersbelow the seabed (jack-up rigs & fixed platforms).

P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2

2.3.8. The top of the cement plug shall be located and verified bymechanical loading.

P-1-M-6100 14.1.2-2P-1-M-6140 14.1.2-2

3. PERMANENT ABANDONMENT – PLUGGING Reference

3.1. General information

3.1.1. When static bottom hole temperature exceeds 110°C, use Geoterm

type cement.

P-1-M-6100 14.2.3-1

P-1-M-6140 14.2.3-13.1.2. Water spacers should be used ahead and behind the slurry. The

spacers should be normally 100 m long

P-1-M-6100 14.2.3-2P-1-M-6140 14.2.3-2

3.1.3. The slurry volume should be calculated using a calliper log, if available. When a calliper log is not available, use a slurry volumeexcess based on local experience. Plugs exceeding 200 meters inlength should not be set in one stage.

P-1-M-6100 14.2.3-3P-1-M-6140 14.2.3-3

3.1.4. If the hole is badly washed out or when potential losses are expected,it is preferable to set two short plugs instead of one long one.

P-1-M-6100 14.2.3-4P-1-M-6140 14.2.3-4

3.1.5. All cement plugs shall be set using a tubing stinger P-1-M-6100 14.2.3-5P-1-M-6140 14.2.3-5

3.1.6. As soon as the plug is set, pull out slowly 30-50 m above theoretical

top and circulate

P-1-M-6100 14.2.3-8

P-1-M-6140 14.2.3-8

3.1.7. Using drilling or workover rig each cement plug shall be located andverified, (WOB: 20,000-40,000 lbs, depending on hole size).

P-1-M-6100 14.2.3-11P-1-M-6140 14.2.3-11

3.1.8. Slurry volume calculations in squeeze cement jobs assume roughly,100 litres slurry/meters perforated formation.

P-1-M-6100 14.2.2P-1-M-6140 14.2.2

3.1.9. A cement plug, at least 150 meters long, shall be placed with its top50 meters below the seabed (off-shore), or ground level (on-shore).

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.1.10. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below seabed, using mechanical cutters.

P-1M-6140 14.2.2



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3.2. Explorative wells

3.2.1. Open hole

3.2.1.1. All permeable zones shall be plugged individually to avoid any crossflow.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.2.1.2. Cement plugs shall be set with top and bottom at least 50 metersabove and below each zone.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.2.1.3. The top of the cement plugs shall be located and verified bymechanical loading.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.2.2. Casing shoe

3.2.2.1. Last casing string above open hole shall be sealed with a cementplug, it shall extend at least 50meters above and below the shoedepth.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.2.2.2.Plug shall be tested by mechanical loading. P-1-M-6100 14.1.2

P-1-M-6140 14.1.2

3.2.3. Liner head

3.2.3.1. At the hanging point of the liner a cement plug shall be set, it isextending at least 50meters above and below the top of liner.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.2.4. Casing cutting

3.2.4.1. The casing shall be cut at least 100meters above the shoe of theprevious casing string and a cement plug shall be placed in suchmanner that extends at least 50 mertres above and below the casingcut point.

P-1-M-6100 14.3P-1-M-6140 14.3

3.3. Completed wells

3.3.1. Onshore Wells with pressure in the annulus casing/casing

3.3.1.1. Case I° (Casing with top of cement below the surface) Open holePhase one:

3.3.1.1.1. By pulling unit to retrive both packer and completion string

3.3.1.1.2. By coiled tubing to seal the last casing string above open hole with acement plug: it shall extend at least 50 meters above and below theshoe depth.

3.3.1.1.3. If it is impossible to retrieve the packer a cement squeeze will beperformed in the formation below the packer.

3.3.1.1.4. Proceed with cutting and retrieving of the completion string above thepacker.

3.3.1.1.5. If the squeeze is not allowed, in HPHT wells, a bridge plug will be setin the completion string below the packer, the completion stringabove the packer will be retrieved and a cement plug on the packer wil be performed

3.3.1.1.6. In the other wells, if the squeeze is not allowed, to retrieve thecompletion string above the packer and to perform a cement plug onthe packer.



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3.3.1.2. Case I° (Casing with top of cement below the surface) perforatedcasing zones Phase one:

3.3.1.2.1. Perforated zones shall be isolated with mechanical plug and shall besqueeze cemented.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.3.1.2.2. Before to setting either cement or mechanical plugs, clear the internalof the casing using taper mill

3.3.1.2.3. A cement retainer will be set maximum 10-15meters above theperforations.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.3.1.2.4. A 50 m long cement plug shall be placed above the cement retainer,the length of this plug may be reduced to avoid any interference withany upper perforated intervals

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

3.3.1.2.5. Instead of point 3.3.1.2.1, a cement plug shall be placed with upper and lower ends located at least 50meters above and below the

perforated zone. This solution must be considered as a contingency.3.3.1.3. Case I° (Casing with top of cement below the surface) Phase two:

3.3.1.3.1. In both cases Open hole and Cased hole, 20/30 day later, return onthe well with a workover rig and verify the hydraulic seal of theplugging previously performed.

3.3.1.3.2. The workover rig will be selected with particular attention to the wellsite dimensions.

3.3.1.3.3. The well site will guarantee as safety distance that the derrickdownfall radius is free from houses, electrical lines, roads and anylogistic structures (engine area, office bunk houses, etc.)

3.3.1.3.4. If it is impossible to respect the safety distance, the Responsible for

the Operations has faculty of derogation.3.3.1.3.5. All casing will be retrieved as much as possible.

3.3.1.3.6. The casing shall be cut at least 100 m above the shoe of the previouscasing string and a cement plug shall be placed in such a way tocover the casing at least 50 m above and below the casing cut point.

P-1-M-6100 14.3P-1-M-6140 14.3

3.3.1.4. Case II° (Casing with top of cement at the surface) Phase one:

3.3.1.4.1. Some as per case I° Phase one.

3.3.1.5. Case II° (Casing with top of cement at the surface) Phase two:

3.3.1.5.1. If the annulus casing/casing is cemented, in order to insulate thepressures, windows will be made in zones suitable to allow the

positioning of inflatable packer.3.3.1.5.2. Subsequently a 50 m long cement plug shall be placed above the

inlettable bridge plug.

3.3.2. Onshore Wells without pressure in the annulus casing/casing

3.3.2.1. When the cement top is above the shoe of the previous casing, theutilisation of drilling rig unit can be avoided and the well abandoningoperations will be carried out utilizing the best technique availableconsidering both economic and operative constraints

3.3.2.2. The cement plug test will be performed by pressurising the top of theplug with a 1500 psi differential pressure.



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3.3.2.3. If the top of cement is under the shoe of the previous casing, it will bemandatory to carry out a cement plug 100 m long in the annulus

casing/casing by circulating through the casing perforations3.3.2.4. Several levels with the same hydraulic regime (homogeneous

formations, pressure and production fluid) can be plugged by meansof two cement plugs, provided the lower extends at least 50 m belowthe bottom of the deeper level and the upper extends at least 50 mabove the top of the higher level

3.3.2.5. Between such two plugs it will be placed a fluid with the samecharacteristics of that one used during the running of the productioncasing.

3.3.2.6. If SBHP is lower than hydrostatic pressure of the production fluid, allannuli will be cemented to surface and the completion string will be

totaly abandoned in the well.3.3.2.7. In the other situations, the completion string will be rercovered up to

50 m under the shoe of the surface casing or in any cases not deeper than 250 m from surface.

3.3.3. Offshore Wells with pressure in the annulus casing/casing

3.3.3.1. The use of workover rig is mandatory

3.3.3.2. Both for explorative and completed offshore wells the wellabandonment will be carried out following the procedure (abovespecified) for onshore well, making distintion between the two cases(pressure or not in the annulus), but performing the operation in oneunique phase.

3.3.4. Offshore Wells without pressure in the annulus casing/casing3.3.4.1. The use of workover rig is mandatory

3.3.4.2. Both for explorative and completed offshore wells the wellabandonment will be carried out following the procedure (abovespecified) for onshore well, making distintion between the two cases(pressure or not in the annulus), but performing the operation in oneunique phase.

Reference List :

‘Drilling Design Manual’ STAP-P-1-M-6100‘Drilling Procedures Manual‘ STAP-P-1-M-6140



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PL3. COMPLETION DESIGN

PL. 3.1. FUNDAMENTAL

1. CONCEPTUAL DESIGN Reference

1.1. The approach to completion design must be interdiscipline, involvingReservoir Engineering, Petroleum Engineering, ProductionEngineering and Drilling Engineering. This is vital in order to obtainthe optimum completion design

P-1-M-7100 1.1

1.2. Many of the decisions made by the various disciplines are interrelatedand impact on the decisions made by other disciplines. For instance,the decision on the well architecture may subsequently be changeddue to the availability of well servicing or workover techniques. This

does not mean that the process is sequential and many decisions canbe made from studies and analysis run in parallel.

P-1-M-7100 1.1

1.3. The design process consists of three phases:

• Conceptual

• Detailed design

• Procurement.

The process of well preparation and installation of completions is fullydescribed in the ‘Completions Procedures manual’.

P-1-M-7100 1.1

1.4. As more information is gleamed from further development wells andas conditions change, the statement of requirements need to

reviewed and altered to modify the conceptual design for future wells.This provides a system of ongoing completion optimisation to suitchanging conditions, increased knowledge of the field and incorporatenew technologies.

P-1-M-7100 1.1

2. COMPLETION OBJECTIVES Reference

2.1. The fundamental objectives for a completion are:

• Achieve a desired (optimum) level of production or injection.

• Provide adequate maintenance and surveillance programmes.

• Be as simple as possible to increase reliability.

• Provide adequate safety in accordance with legislative or

company requirements and industry common practices.• Be as flexible as possible for future operational changes in well

function.

• In conjunction with other wells, effectively contribute to the wholedevelopment plan reservoir plan.

• Achieve the optimum production rates reliably at the lowestcapital and operating costs.

P-1-M-7100 1.2

2.2. These may be summarised as to safely provide maximum long termprofitability. This, however, in reality is not simple and many criticaldecisions are needed to balance long term and short term cash flowand sometimes compromises are made.

P-1-M-7100 1.2



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3. FUNCTIONS OF A COMPLETION Reference

3.1. The main function of a completion is to produce hydrocarbons tosurface or deliver injection fluids to formations. This is its primaryfunction, however a completion must also satisfy a great many other functions required for safety, optimising production, servicing,pressure monitoring and reservoir maintenance.

These main functional requirements must be built into the conceptualdesign and include:

• Protecting the production casing from formation pressure.

• Protecting the casing from corrosion attack by well fluids.

• Preventing hydrocarbon escape if there is a surface leak.

• Inhibiting scale or corrosion.

• Producing single or multiple zones.

• Perforating (underbalanced or overbalanced).

• Permanent downhole pressure monitoring.

P-1-M-7100 1.3

4. RESEVOIR CONSIDERATIONS Reference

4.1. Hydrocarbon data P-1-M-7100 2.3

4.1.1. The practical approach to the study of reservoir fluid behaviour is toanticipate pressure and temperature changes in the reservoir and atsurface during production, and to measure, by laboratory tests, the

changes occurring in the reservoir samples. The results of these teststhen provide the basic fluid data for estimates of fluid recovery byvarious methods of reservoir operations and also to estimatereservoir parameters through transient pressure testing.

P-1-M-7100 2.3

4.1.2. Two general methods are used to obtain samples of reservoir oil for laboratory examination purposes, by means of subsurface samplersand by obtaining surface samples of separator liquid and gas. Thesurface samples are then recombined in the laboratory in proportionsequal the gas-oil ratio measured at the separator during well testing.

P-1-M-7100 2.3

4.2. Oil Property Correlation

4.2.1. Several generalisations of oil sample data are available to permitcorrelation’s of oil properties to be made (refer to the Company WellTest Manual for sampling techniques).

P-1-M-7100 2.3.1



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5. RESERVOIR/PRODUCTION FORECAST Reference

5.1. To obtain the optimum performance from a well, it is first necessary todetermine its full potential and which way this can be fully exploitedwithin any technical or economic constraints. The determination of thewell’s performance entails analysing the following:

• In-flow performance

• Near wellbore performance and design

• Multiphase flow of tubing performance

• Artificial lift.

P-1-M-7100 2.4

5.2. The process of this analysis is shown in

Figure PL 3.1 which requires continuous repetition during field life toaccount for changing conditions.

P-1-M-7100 2.4

5.3. Inflow Performance P-1-M-7100 2.4

5.3.1. The inflow performance relationship (IPR) provides the flow potentialof the reservoir into the wellbore against the resistance to flow of theformation and near wellbore region. The theoretical IPR is anidealistic assumption of flow performance without pressure drop dueto skin effect in the near wellbore region and governed only by thesize, shape and permeability of the producing zone and the propertiesof the produced fluids. The basic theory of this is described in thissection along with some simplified IPR relationships from observedfield data.

P-1-M-7100 2.4

5.4. Near wel lbore per formance and design P-1-M-7100 2.4

5.4.1. Flow behaviour in the near wellbore region may cause a dramaticeffect on the IPR curve which results in greatly reduced flowcapability. This is characterised by a damaged IPR curve and theamount of damage or skin effect, is mainly caused by the drilling andcompletion practices. Good drilling and completion practices can or may minimise this damage allowing use of the idealised IPR curve tobe used for completion design.

P-1-M-7100 2.4

5.5. Mult iphase f low of tubing performance P-1-M-7100 2.4

5.5.1. Some completion designs to deal with reservoir conditions, such asgravel packs for unconsolidated sands, will also cause reduced IPRcurves which must be anticipated during the design phase. Twophase flow, velocity effects in gas wells, high rate or high GOR oilwells, in undamaged near wellbore regions also reduce the IPRcurve. Alternatively, stimulation procedures which can provide anegative skin are desirable as this increases production.

P-1-M-7100 2.4



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5.6. Artificial lift

5.6.1. A well will not flow naturally if the IPR and TPC curves do notintersect and in this case artificial lift could be used to provide thepressure differential between the curves (Refer to

Figure PL 3.2). An artificial lift system places an injection of energyinto the flow system which displaces the TPC curve downwards.

In a pumping well, the displacement is dependent on the pumpperformance curve (i.e. pump differential versus rate) which is plottedbelow the well performance curves as shown in

Figure PL 3.2. This results in a combined outflow performance curvetermed the pump intake curve.

P-1-M-7100 2.4.5

Reference List :

‘Completion Design Manual’ STAP-P-1-M-7100



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Figure PL 3.1 - Process of Determining Optimum Well Performance

Selecting, or optimising, the tubing size is necessary to optimise the well performance over

the life of the well and should include the potential benefits of artificial lift systems and/or stimulation to reduce near wellbore skin effects.



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Figure PL 3.2 - IPR/TCP



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PL. 3.2. RESERVOIR FLUIDS CHARACTERISTICS


1.1. The practical approach to the study of reservoir fluid behaviour is toanticipate pressure and temperature changes in the reservoir and atsurface during production, and to measure, by laboratory tests, thechanges occurring in the reservoir samples. The results of these teststhen provide the basic fluid data for estimates of fluid recovery byvarious methods of reservoir operations and also to estimatereservoir parameters through transient pressure testing.

P-1-M-7100 2.3

2. OIL CHARACTERISTICS Reference

2.1. Oil density.

2.2. Gas gravity.

2.3. Volume factor.

2.4. Bubble point.

2.5. Viscosity.

2.6. Pour point.

2.7. Compressibility.

2.8. Gas-oil ratio.

2.9. Chemical composition.

2.10. Asphaltenes deposition curve

2.11. Corrosive agents content.

2.12. Scale deposition capability.

2.13. Water density.

2.14. Water salinity.

2.15. Water pH.

3. GAS CHARACTERISTICS Reference

3.1. Gas gravity.

3.2. Volume factor.



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3.3. Viscosity.



3.6. Hydrate forming capability.

3.7. Water density.


3.9. Water pH.

4. GAS CONDENSATE CHARACTERISTICS Reference

4.1. Gas gravity.

4.2. Condensate density.

4.3. Dew point.

4.4. Volume factor.

4.5. Viscosity.



4.8. Condensate-gas ratio.


4.10. Asphaltenes deposition curve.

4.11. Hydrate forming capability.

4.12. Water density.


4.14. Water pH.



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5. SAMPLING Reference

5.1. Bottom hole and/or surface reservoir fluid sampling should be alwaysplanned during the well testing executed on exploratory and appraisalwells in order to get a PVT study before final completion design carryon.

5.2. The PVT study should contain FLASH vaporisation data for tubingPVT calculation. (P & T tubing range).

5.3. The PVT study should contain DIFFERENTIAL vaporisation data for reservoir PVT calculation.

5.4. Bottom hole sampling shall be executed at stabilised flow parameters

and at depth where FBHP is greater than bubble point.

5.5. When FBHP is lower than bubble point a multirate test shall beperformed to obtain the real GOR and a surface sampling shall beperformed.

5.6. Surface sampling shall be executed at stabilised flow parameters atrelevant pressure & temperature separator conditions and well headparameters shall be recorded at same time.

5.7. Field measurement of H2S concentration shall be always referred tothe sampling point conditions. (first stage separator; second stage

separator; tank gas).

Reference List:




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PL. 3.3. RESERVOIR ROCK CHARACTERISTICS


1.1. Within Completion engineering rock characteristics are primarilyconcerned with the way in which the rock system will react to thecompletion and production process.

1.2. Drilling and completion fluid and their interactions with the reservoir rock can cause formation damage

1.3. Production can cause sand problems with depletion in poor consolidated formations

1.4. Low permeability reservoir may need fracturing.

2. AREA OF INTEREST Reference

2.1. Choice of completion fluids.

2.2. Matrix stimulation engineering.

2.3. Frac. job engineering.

2.4. Sand control engineering.

2.5. Cement squeezing.

2.6. Temporary plugging of depleted reservoir.

3. MAIN CHARACTERISTICS Reference

3.1. Porosity. P-1-M-7100 2.2.1

3.2. Permeability. P-1-M-7100 2.2.2

3.3. Relative permeability. P-1-M-7100 2.2.3

3.4. Grain size and shape (sand control).

3.5. Wettability. P-1-M-7100 2.2.4

3.6. Clay content.

3.7. Cementing material.

3.8. Mechanical properties (frac jobs).



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4. CORE ANALYSIS Reference

4.1. The Completion engineer should check the availability of formationcores, and address the request to core in case of lack of theinformation essential to the particular design in progress.

4.2. The core study should be addressed to the Well Area Laboratoriesand a synthesis of results should take part of the Completion designstudy.

Reference List:




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PL. 3.4. EFFECTS OF RESERVOIR CHARACTERISTICS


1.1. The driving mechanisms and thermodynamics of the hydrocarbons inthe reservoir is a matter of reservoir engineering that should decidethe reservoir depletion strategy and address to the completionengineering the information of concern to the completion design.

1.2. In an oil reservoir, primary production results from existing pressure inthe reservoir. There are three basic drive mechanisms:

• Dissolved gas

• Gas cap

• Water drive.

Most reservoirs in actuality produce by a combination of all threemechanisms.

P-1-M-7100 2.2.7

2. DESIGN PARAMETERS Reference

2.1. The effect of the drive mechanism on the producing characteristicsmust be evaluated in the completion design process, and also for later re-completions, to systematically recover reservoir hydrocarbons. Figure PL 3.3 and Figure PL 3.4, show typicalreservoir pressures versus production trends and gas-oil ratioproduction trends for the three basic drive mechanisms.

P-1-M-7100 2.2.7

3. COMPLETION DESIGN THROUGH FIELD LIFE Reference

3.1. Natural flow to artificial lift design should be considered.

3.2. Production to injection status should be considered.

3.3. Sand consolidation or control should be considered.

4. NEAR WELLBORE RESTRICTIONS Reference

4.1. The well performance at bottom hole is given by the summation of thereservoir performance and the near wellbore performance. The near wellbore performance may be reduced by different causes that shallbe considered.

4.2. Formation damage skin

4.2.1. Formation skin occur when the permeability in the near wellboreregion is reduced as a result of various fluid-fluid and fluid-rockinteractions. This is often due to the invasion of solids or incompatiblefluids during drilling or completion.

4.2.2. Particles in wellbore fluids can block pore throats.

4.2.3. Trapped water can cause shale swelling.



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4.2.4. Trapped water can reduce relative permeability to hydrocarbons.

4.3. Perforation skin

4.3.1. Perforation skin occurs when the radial flow of reservoir deviates to aspherical/cylindrical flow through the crashed zone around theperforation tunnel.

This is more significant where the shot penetration does not cross thedamaged zone and where the effective shot density is reducedbecause some perforation tunnel is plugged or collapsed.

4.4. Partial completion skin

4.4.1. Partial completion skin occurs when less than about 85 % of the totalnet pay thickness is open. In that case the flow converge to theperforated interval to enter the wellbore and cause additionalpressure losses.

4.4.2. Partial completion skin, called also geometrical skin, can be verylarge especially in high anisotropy formations and should be generallyavoided. However a zone may be intentionally partly perforated toavoid gas or water coning.

4.5. Multiphase flow skin

4.5.1. Multiphase skin occur when multiphase flow occur in the near wellbore area and the relative permeability to the main fluid isreduced. That can happen in oil wells producing below bubble pointand in gas wells producing below dew point.

The effect of the multiphase pressure drop depends on how therelative permeability to gas and liquid varies with saturation.

4.6. Gravel packing skin

4.6.1. The Gravel packing skin occur when screens and sized gravel sandare positioned in front of the pay zone to inhibit formation sand from

invading the gravel pack. Additional pressure drop should be given bypoor perforation filling allowing the tunnel to collapse and/or whensand gravel intermixing occur.



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4.7. Rate dependent skin

4.7.1. The Rate dependent skin, also called non-Darcy skin, occur when thehigh velocity of the fluids in the near wellbore area causes turbulenceand associated pressure drop. The magnitude of the non-Darcy effectshould be very large and shall be taken into account in gas wellsproducing more than 10,000Nm³/day and oil wells producing morethan 50m

3/day per perforated meter.

4.8. Reduction of permeabil ity dur ing product ion

4.8.1. Obstructions may occur also during production phase and caused bythe following.

4.8.2. Produced fines.

4.8.3. Scales.

4.8.4. Asphaltenes.

5. STRATEGY TO MINIMISE THE SKIN EFFECTS Reference

5.1. In a radial flow situation, where fluids move towards the well from alldirections, most of the pressure drop in the reservoir occurs fairlyclose to the wellbore. In a uniform sand, the pressure drop across thelast 15ft of the formation surrounding the wellbore is about one half of

the total pressure drop from the well to a point 500ft away in thereservoir. Obviously flow velocities increase tremendously as fluidapproaches the wellbore. This area around the wellbore is the ‘criticalarea’ and as much as possible should be done to prevent damage or flow restrictions in this critical area.

P-1-M-7100 2.2.6

5.2. If a well is to be perforated overbalanced, then strict control over thefluid used to ensure it is compatible with the reservoir formation,formation fluids and must also be clean to prevent formation damage.

P-1-M-7100 9.3.1

5.3. Phasing P-1-M-7100 9.3.1

5.4. Gun stand-off P-1-M-7100 9.3.1

5.5. Use of clean tubular goods.

5.6. Maximise the perforated zone within the net pay. P-1-M-7100 9.3.1

5.7. Use of underbalance perforating practice. P-1-M-7100 9.3.2

5.8. Use of maximum shot density. P-1-M-7100 9.3.1



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5.9. Perforating tunnels should be large and deep enough to prevent anyrestriction to flow.

P-1-M-7100 2.2.6

5.10. Gravel Pack Completions

Due to the problem of flow restriction the important factors are:

• Hole diameter to achieve adequate flow area.

• Shot density to achieve adequate flow area.

• Debris removal.

• Shot phasing.

• Penetration.

This in conjunction with correct gravel pack procedures is essentialfor to prevent high skin factors.

P-1-M-7100 9.3.1

5.11. Specific chemical treating of the near wellbore area to removeformation damage.

5.12. Limit brine volume losses in depleted reservoir and use surfacetension reducer.

6. WELL INFLOW PERFORMANCE Reference

6.1. The inflow performance relationship (IPR) provides the flow potentialof the reservoir into the wellbore against the resistance to flow of theformation and near wellbore region. The theoretical IPR is an

idealistic assumption of flow performance without pressure drop dueto skin effect in the near wellbore region and governed only by thesize, shape and permeability of the producing zone and the propertiesof the produced fluids.

P-1-M-7100 2.4

6.2. The equation used shall take into account all the Darcy and non-Darcy effects.

6.3. Where inflow relationship passes through the bubble point, a straightline IPR is drawn above the bubble point and the curved IPR signifiesthe two phase flow below this point. For this, Vogel’s equation is

combined with the PI to develop a general IPR equation. This hasbeen published by Brown. When the BHFP is above the bubble pointuse the normal straight line equation:

( )wf Ro ppJq −=

and when it drops below the bubble point use the modified Vogelequation:

( )

−

−+−=

2

b

wf

b

wf bwf Ro

p

p8.0

p

p2.01

8.1

JpppJq

P-1-M-7100 2.4.1



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6.4. Fetkovich recognised that many oil wells could be handled in thesame way as gas wells using the curved IPR:

( )n2

wf

2

Ro ppCq −=

where:

C = Linear deliverability coefficient

n = Deliverability exponent (0.5 to 1.0)

P-1-M-7100 2.4.1

6.5. Blount and Jones presented an alternative generalised IPR equationwhich was an extension to the Forcheimer equation to include thenon-Darcy flow effects:

2

wf Rbqaqpp

+=−

P-1-M-7100 2.4.1

6.6. Forcheimer equation for gas wells should be used for pressure below2,000psi and where the drawdown is small as in high permeabilitywells:

2

ggwf R Aq Aqpp +=−

P-1-M-7100 2.4.1

6.7. When the µz value is not constant the pseudo pressure m(p) shall beused instead of P².

Pseudo pressure m(p) shall be used when pressure is above 2,000psi

and in low permeability wells where drawdown greater than 500psi isexpected.

Reference List :




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Figure PL 3.3 - Reservoir Pressure Trends For Various Drive Mechanisms

Figure PL 3.4 - Gas-Oil Ratios Trends For Various Drive Mechanisms



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PL. 3.5. TUBING PERFORMANCE


1.1. The relationship between pressure and temperature drop in wells andPVT behaviour is complex. Pressure drop is determined usingempirical and semi-empirical correlation’s and carried out oncomputer software programmes.

P-1-M-7100 2.4.4

1.2. Calculating pressure drop in tubing involve numerical integration of the steady-state pressure gradient equation over the entire tubinglength. It consists of the following three components:

• Hydrostatic head

• Wall friction

• Fluid acceleration.

P-1-M-7100 2.4.4

1.3. The acceleration term is usually negligible except in system involvingsignificant fluid expansion (gas wells when near atmosphericpressure).

P-1-M-7100 2.4.4

1.4. The friction losses are controlled by fluid viscosity and geometricfactor (pipe diameter and roughness) and normally accounts for around 10 % of overall head losses.

P-1-M-7100 2.4.4

1.5. The gravitational component accounts for around 90 % of the overallhead losses and is proportional to the density of the fluid mixture at

each point in the tubing and is a complex function of the relativevelocity of the phases present.

P-1-M-7100 2.4.4

1.6. The geometrical distribution of the gas and liquid in the pipeconstitute the “flow pattern” or “flow regime”. The flow patterns aregoverned by the flow rates of each phase, the tubing diameter and toa lesser extent PVT fluid properties.

P-1-M-7100 2.4.4

1.7. Flow patterns are identified using empirical flow pattern maps. Eachflow regime has different pressure gradients that should be calculatedby the use of different empirical correlation for liquid hold-up andfriction factor.

1.8. Typical pressure gradients in wells for different flow patterns are:

• Single phase oil = 0.36psi/ft

• Bubble flow = 0.25psi/ft

• Slug flow = 0.20psi/ft

• Mist flow = 0.1 - 0.2psi/ft

P-1-M-7100 2.4.4



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2. TEMPERATURE GRADIENT Reference

2.1. The temperature profile shall be considered in the outflowperformance calculation.

2.2. Computer calculation should be performed to predict both steadystate or transient temperature changes overtime.

2.3. A temperature prediction method shall be always validated withmeasured data.

2.4. Some wells have produced fluids with special properties that are verysensitive to temperatures and more complex heat transfer calculations are required. These are:

• Gas condensate wells with retrograde condensate.

• High pour point crude oil wells.

• Wells in which hydrate formation can occur.

P-1-M-7100 2.4.4

3. PVT DATA CALCULATION Reference

3.1. Due to the complexity of the relationship between pressure andtemperature drop in wells and PVT behaviour all calculation shall beperformed on a computer.

3.2. The software to be used within Well Area Engineering is PROSPER

that allows the use of the most accepted correlation in the industry or WPM already in use in Reservoir engineering.

3.3. To predict pressure and temperature changes from the reservoir,along the wellbore, it is necessary, at an early stage, to accuratelypredict fluid properties as the pressure and temperature changes.

3.4. Minimum data

3.4.1. Oil

3.4.1.1.Solution GOR.

3.4.1.2. Separator condition (P&T).

3.4.1.3. Oil gravity.

3.4.1.4. Water salinity.

3.4.1.5. Gas gravity.



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3.4.2. Dry & wet gas

3.4.2.1. Gas gravity.



3.4.2.4. Condensate/Gas ratio.

3.4.2.5. Water/Gas ratio.

3.4.3. Retrograde condensate


3.4.3.2. Separator GOR and gas gravity.

3.4.3.3. Tank GOR and gas gravity.

3.4.3.4. Condensate gravity.

3.4.3.5. Dewpoint at reservoir condition.

3.4.3.6. Reservoir condition (P&T).

3.4.3.7. Water/Gas ratio.


4. PVT PARAMETERS TO BE MATCHED Reference

4.1. For a best fluid properties prediction FLASH PVT data shall bematched.

4.2. If only Differential liberation PVT data is available it shall be correctedto FLASH conditions.

4.3. Oil

4.3.1. Bubble point.

4.3.2. GOR.

4.3.3. Oil formation volume factor.

4.3.4. Oil viscosity.



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4.4. Dry & wet gas

4.4.1. Z factor.

4.4.2. Gas formation volume factor.

4.4.3. Gas viscosity.

4.4.4. CGR (condensate/gas ratio).

4.5. Retrograde condensate

4.5.1. Dew point.

4.5.2. CGR.

4.5.3. Z factor.

4.5.4. Gas viscosity.

4.5.5. Gas formation volume factor.

5. VALIDATION Reference

5.1. After that a solid PVT table is obtained the TBG performance shall becalculated.

5.2. Several correlations for predicting pressure gradients in oil wells areavailable. Validation with actual field data is the only reliable methodfor choosing the best correlation for a particular case and within aparticular range of fluids rate.

5.3. Try to get more than a flowing gradient at different flow rate from welltesting.

5.4. Do not tune calculated value with measured data by changing theTBG roughness or friction factor multiplier. Act on the gravitational

term rather than on frictional.

5.5. Always check the shape of the TBG performance curve and do notconsider operating point (intersection IPR/TCP) on the left of theminimum of the curve to avoid instability.



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6. LIMITS Reference

6.1. In gas wells, liquid loading can also be predicted using simplifiedmethods presented with Turner et al which are independent of pressure drop calculations. These methods have been reviewed byLea and Tighe. For wells producing high gas-water or gas-condensate ratios, it is recommended that tubing size be assessedusing these methods in addition to lift curve methods and that themost conservative approach be adopted.

P-1-M-7100 2.4.4

6.2. Erosion in completions occurs when there are high velocities and if there are solids particles in the flow stream. The most common pointsfor erosion is where there are restrictions that cause increasedvelocities. The API have published a method in API RP 14E, to

determine the threshold velocities for erosion to occur in pipingsystems but the validity of this for all conditions is questionable.

P-1-M-7100 2.4.4

6.3. The choice of the optimum tubing size should be taken into accountthe AGIP standardisation in terms of:

6.3.1. Well head diameter.

6.3.2. Subsurface safety valve diameter.

6.3.3. Production casing diameter.

6.4. The maximum tubing OD for a particular design shall consider theclearance CSG / TBG in order to be able to washover and fish abroken tubing by standard overshot.

7. OPTIMUM TBG SIZE THROUGH FIELD LIFE Reference

7.1. Optimum TBG size should change with changing reservoir conditionand different configurations should be evaluated through time.

7.1.1. Compromise diameter.

7.1.2. Workover to substitute the tubing.

7.1.3. Concentric TBG installation.

Reference lis t:




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PL. 3.6. STRESS ANALYSIS


1.1. All completion tubing strings will have tubing movement calculationsconducted to ascertain the maximum load applied to the string and/or completion tubing movement to be catered for in the completiondesign.

All tubing strings should be designed for stress, preferably using anappropriate up to date computer programme. Currently Eni-AgipDivision and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version.

P-1-M-7100 7.1

1.2. The triaxial equivalent stress must be computed from the axial, radial,hoop, and torsional shear stresses.

1.3. The effective axial force shall be computed by summing the actualaxial force and the force that causes the same outer fiber stress thatis induced by the curvature due to buckling and hole doglegs.

1.4. Hoop and radial stresses shall be computed using Lame’s formulas atthe OD and ID.

1.5. Shear stress shall be computed from the torque and polar moment of inertia.

1.6. Stresses shall be computed on the side with compressive bending

stresses and on the side with tensile bending stresses, to insure theworst stress conditions have been identified.

2. PARAMETERS Reference

2.1. During completion tubing design process, it is necessary to calculatethe variations in length for the stresses applied under load conditions.When these have been determined it will confirm the suitability of theselected tubing.

Tubing movement occurs due to only two reasons:

• Temperature changes

• Change in pressure induced forces.

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2.2. The well data and parameters required (or already determined) toproduce an accurate tubing movement/stress analysis and, hence,

selection of a tubing are:

• Casing design profile

• Casing programme contingency profile

• Tubing size from optimisation analysis

• Pressure gradient

• Temperature gradient

• Reservoir fluids specific gravities

• Completion fluid specific gravities

• Production/injection or stimulation forecast.

P-1-M-7100 7.3

2.3. Movement can only occur if the tubing is free to move. If the tubing isnot free to move and is anchored to a packer then stress will besubjected to the tubing string and packer.

Tubing movement upward (contraction) is assumed to be negativeand downward (lengthening) is positive.

P-1-M-7100 7.2

2.4. The optimum tubing size, determined by nodal analysis conducted bythe reservoir engineers, is required and is the basis of all thecalculations.

The tubing movement/stress calculations will then determine the

tubing weight or any change in grade required to meet with theapplied SF for stress.

P-1-M-7100 7.3.2

2.5. Bottom-hole Pressure:

Accurate initial and prognosed future formation pressures both staticand dynamic are fundamental to tubing movement/stresscalculations. These pressures can be obtained from previous wellexploration test data or appraisal well test reports.

P-1-M-7100 7.3.3

2.6. Temperatures (Static and Flowing):

Accurate well temperature data are vital in tubing movement/stress

analysis as the temperature effect is usually the effect which causesthe greatest tubing movement.

P-1-M-7100 7.3.4



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2.7. Temperature changes cause expansion and contraction in metals,which is a significant factor in tubing strings. All metals have a

particular expansion rate that is termed the ‘Co-efficient of thermalexpansion’.

The co-efficient of liner expansion for tubular steels is usually 6.9 x10

-6 in/in/F°.

P-1-M-7100 7.2.2

2.8. When a well is completed, either with a tubing seal unit in a packer bore or a tubing movement device, it will have completion fluid in boththe tubing and the annulus, this is referred to as the initial condition. All subsequent conditions are calculated from this initial condition.

P-1-M-7100 7.4

2.9. The prediction of temperatures and pressures is of high concern to

the tubing design and a lot of care shall be given in the choice of theoperational parameters.

2.10. Production operations normally yield tubing elongation’s and injectionoperations normally yields tubing contractions.

2.11. Usually injection or cold operations are the most critical for the stressbehaviour.

3. CALCULATION METHOD Reference

3.1. For each operation the tubing movement and the relevant stresses

shall be calculated as per the method described in the AGIPprocedure.

P-1-M-7100 7.10

3.2. Effects to consider :

3.2.1. Piston (Hooke). P-1-M-7100 7.4.1

3.2.2. Buckling. P-1-M-7100 7.4.2

3.2.3. Ballooning. P-1-M-7100 7.4.3

3.2.4. Temperature. P-1-M-7100 7.4.4

3.3. The completion shall be divided into as many sections as anychanges in material, tubing OD, tubing ID, casing ID, internal fluidlevel, external fluid level.

3.4. The stress at bottom and top of every section shall be calculated.

3.5. All tubing strings should be designed for stress, preferably using anappropriate up to date computer programme. Currently Eni-AgipDivision and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version.

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4. SAFETY FACTOR Reference

4.1. A completion string’s safety factor is defined as the ratio between theyield stress and the maximum value of the stress obtained.

P-1-M-7100 7.10.2

4.2. Carbon and CRA Steels up to 13%Cr

• The acceptable SF for these types of materials is: 1.25

P-1-M-7100 7.10.2

4.3. Cold Worked (CW) CRA Steels

• The acceptable SF for these types of materials which includeduplex, super-austenitic and Incoloy is: 1.35

P-1-M-7100 7.10.2

4.4. Uniaxial and biaxial safety factor P-1-M-7100 7.10.2

4.4.1. If triaxial safety factor is not computed

4.4.1.1. Tensile safety factor = 1.6

4.4.1.2. Burst safety factor = 1.3

4.4.1.3. Collapse safety factor = 1.125 (not for tensile cases)

4.4.2. Use biaxial stress calculation for Collapse when Tension is applied.

5. OPERATIONAL CASES Reference

5.1. Minimum operat ional cases to be evaluate

5.1.1. Packer setting. P-1-M-7100 7.6.2

5.1.2. Production and shut-in at initial reservoir conditions. P-1-M-7100 7.7.4P-1-M-7100 7.7.5

5.1.3. Tubing leaking.

5.1.4. Production and shut-in at final reservoir conditions.

5.1.5. Injection of treatment or killing fluids.

5.1.6. Packer or anchor unsetting.

5.2. Injection strategy

5.2.1. Whenever an injection operational case under investigation yieldsmaterial’s stress greater than the minimum accepted one, changes inthe operating procedure shall be investigated prior to change the besttubing diameter derived from outflow performance.

Consideration shall be given but not limited to the following cases:



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5.2.2. Warming up the treatment fluids.

5.2.3. Increase treatment fluid viscosity.

5.2.4. Reduce treatment flow rate.

5.2.5. Reduce treatment volume.

5.2.6. Increase casing pressure.

5.2.7. Use of dynamic tubing/packer connection.

5.3. Production strategy

5.3.1. Production operational cases may yield thermal elongation’s thatmake the tubing buckle into a helix.

5.3.2. The pitch of the helix shall be calculated to make prevision of freepassage of tools.

5.3.3. Applied casing pressure can reduce this buckling effect and straightthe tubing reducing wire line or coiled TBG overpulling.

5.3.4. Applied casing pressure must balance the effect of reducing bucklingand the increasing of compression and packer loads.

6. TBG - PACKER INTERACTIONS Reference

6.1. With free moving packer/tubing seals systems, the calculations aremade for the selection of an appropriate length of seal assembly,PBR or ELTSR with anchored packer/tubing systems.

P-1-M-7100 7.5

6.2. In some completions the tubing is firmly fixed to the packer,preventing any movement of the string when well conditions vary. Inthis situation the tubing-packer forces generated by the presence of the anchoring must be determined so as to be able to confirm if thetubing-packer anchoring system and the packer have sufficientstrength to safely withstand all the forces exerted.

P-1-M-7100 7.6

6.3. The packer shall withstand the force imposed by the tubingmovement and the differential pressure.

6.4. When available the use of Packer Envelopes is suggested to insurethe packer works within the design limits.



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7. TUBING MECHANICAL PROPERTIES Reference

7.1. Mechanical properties that must be considered

7.1.1. Minimum yield stress.

7.1.2. Ultimate yield stress.

7.1.3. Thermal expansion coefficient.

7.1.4. Young modulus.

7.1.5. Weakening of yield strength with temperatures.

7.2. CRA material and high alloy steel should have anisotropic behaviour.

The derating of yield in relationship the direction of stress shall beconsidered when anisotropic material is used.

7.3. When reduction in tubing thickness is expected due to corrosion theexpected final tubing thickness shall be also considered.

7.4. The connections to be used shall be qualified according to therequirements as set in the Eni-Agip Division and Affiliates procedure‘Connection Procedure Evaluation’.

• The use of premium connections for tubing is mandatory.

• The use of premium connections for production casing is

advised but not mandatory.

M-1-M-5006P-1-M-7100 7.9.1

Reference List :


‘Test Procedure for Connection Evaluation’ STAP M-1-M-5006



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PL. 3.7. MATERIAL SELECTION

1. CORROSION GENERAL Reference

1.1. In general, the ideal material is determined by the results of corrosionstudies carried out prior to the tubing design stage, especially whenthe severity of the conditions suggest the use of expensive CRAmaterials.

P-1-M-7100 7.8.1

1.2. The existence, if any, of the following conditions alone, or in anycombination may be a contributing factor to the initiation andperpetuation of corrosion:

P-1-M-7100 6.2

1.2.1. Oxygen (O2):

Oxygen dissolved in water drastically increases its corrosivitypotential. It can cause severe corrosion at very low concentrations of less than 1.0ppm.

The solubility of oxygen in water is a function of pressure,temperature and chloride content. Oxygen is less soluble in salt water than in fresh water.

Oxygen usually causes pitting in steels.

P-1-M-7100 6.2

1.2.2. Hydrogen Sulphide (H2S):

Hydrogen sulphide is very soluble in water and when dissolvedbehaves as a weak acid and usually causes pitting. Attack due to the

presence of dissolved hydrogen sulphide is referred to as ‘sour’corrosion.

The combination of H2S and CO2 is more aggressive than H2S aloneand is frequently found in oilfield environments.

Other serious problems which may result from H2S corrosion arehydrogen blistering and sulphide stress cracking.

It should be pointed out that H2S also can be generated by introducedmicro-organisms.

P-1-M-7100 6.2

1.2.3. Carbon Dioxide (CO2):

When carbon dioxide dissolves in water, it forms carbonic acid,decreases the pH of the water and increase its corrosivity. It is not ascorrosive as oxygen, but usually also results in pitting.

The important factors governing the solubility of carbon dioxide arepressure, temperature and composition of the water. Pressureincreases the solubility to lower the pH, temperature decreases thesolubility to raise the pH.

Corrosion primarily caused by dissolved carbon dioxide is commonlycalled ‘sweet’ corrosion.

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1.2.4. Temperature:

Like most chemical reactions, corrosion rates generally increase withincreasing temperature.

P-1-M-7100 6.2

1.2.5. Pressure

Pressure affects the rates of chemical reactions and corrosionreactions are no exception.

In oilfield systems, the primary importance of pressure is its effect ondissolved gases. More gas goes into solution as the pressure isincreased this may in turn increase the corrosivity of the solution.

P-1-M-7100 6.2

1.2.6. Velocity of fluids within the environment:

Stagnant or low velocity fluids usually give low corrosion rates, butpitting is more likely. Corrosion rates usually increase with velocity asthe corrosion scale is removed from the casing exposing fresh metalfor further corrosion.

High velocities and/or the presence of suspended solids or gasbubbles can lead to erosion, corrosion, impingement or cavitation.

P-1-M-7100 6.2

1.3. Cor ros ion cel l minimum envi ronment

1.3.1. An electrolyte.

1.3.2. An oxidising agent.

1.3.3. A conductive path in the metal.

1.4. Corrosion of steel does take place to the fact that an electrochemicalprocess occurs between an anode area which loose material and acathode area, on the surface of the metal, in contact with the water.There are many reasons that this could happen:

1.5. Steel itself is not a pure element but an alloy. The iron carbide, whenin contact with pure iron, will form a cell and become the cathode thuscausing the anode to corrode.

1.6. The formation of scale in isolated areas can lead to a corrosion cellbeing formed.

Bacteria, especially slime forming bacteria, can cause corrosion cellsto form if only isolated areas are covered.

1.7. The use of different metals in contact is an obvious way to cause acorrosion cell.

1.8. Water effect



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1.9. Sulphide St ress Cracking (SSC) P-1-M-7100 6.3.1

1.9.1. The SSC phenomenon occurs usually at temperatures of below 80°Cand with the presence of stress in the material. The H2S comes intocontact with H2O, which is an essential element in this form of corrosion by freeing the H

+ ion. Higher temperatures, e.g. above 80°C

inhibit the SSC phenomenon, therefore knowledge of temperaturegradients is very useful in the choice of the tubular materials sincediffering materials can be chosen for various depths.

Evaluation of the SSC problem depends on the type of well beinginvestigated. In gas wells, gas saturation with water will producecondensate water and therefore create the conditions for SSC. In oilwells, two separate cases need to be considered, vertical anddeviated wells:

P-1-M-7100 6.3.1

1.9.2. In vertical oil wells, generally corrosion occurs only when the water cut becomes higher than 15% which is the ‘threshold’ or commonlydefined as the ‘critical level’ and it is necessary to analyse the water cut profile throughout the producing life of the well.

P-1-M-7100 6.3.1

1.9.3. In highly deviated wells (i.e. deviations >80o), the risk of corrosion by

H2S is higher since the water, even if in very small quantities,deposits on the surface of the tubulars and so the problem can belikened to the gas well case where the critical threshold for the water cut drops to 1% (WC <1%).

P-1-M-7100 6.3.1

1.9.4. The water does not take part in the corrosion process if emulsified inthe oil phase. The water phase must wet the metal wall to set up acorrosion cell.

1.9.5. Condition to get water wet walls

1.9.5.1. Gas well with WC < 1 %

1.9.5.2. Vertical oil well with WC > 15 %

1.9.5.3. Horizontal or high deviated wells with WC > 1 %

1.9.6. Using the partial pressure of carbon dioxide as a yardstick to predictcorrosion, the following relationships have been found:

• Less than 3psi will not result in corrosion

• Between 3 and 30psi may result in corrosion

• Greater than 30psi will result in corrosion

P-1-M-7100 6.2



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1.9.7. The problem of carbon dioxide attack is much worse in gasproduction than in oil production. In the oil tubular the surface of the

steel may be protected by the oil flowing through it. In gas productiondroplets of saline water will accumulate on the surface of the steel,resulting in small anodes and large cathode causing rapid localisedcorrosion.

1.10. Hydrogen sulphide

1.10.1. Hydrogen sulphide is soluble in water and acts as a weak acidproducing iron sulphide which is cathodic to steel that corrode andtends to form a scale on steel thus further promoting the corrosionreaction.

1.10.2. Free hydrogen is generated by the reaction that may enter the steelstructure causing embrittlement. Low hardness material (22 HRCmax) shall be used where this phenomena can occur.

1.11. St ress cor ros ion cracking

1.11.1. Hydrogen sulphide and a tensile stress can act in concert to providecracks in a susceptible material in particular environment. This formof attack is named stress corrosion cracking (SCC).

The tensile stress can be residual, applied or a combination of thetwo. The important factor in stress corrosion cracking which makesthis form of attack so damaging, is that cracks propagate at muchlower values of stress than would cause failure if the corrodent wasnot present. Stress corrosion cracking can occur in a system whichpreviously has not shown no sign of any corrosion problem, if theoperating condition are changed.

1.11.2. The susceptibility to SSC decrease with increasing pH. This decreasestarts at a pH of approximately 6 and above a pH of 9.5 SSCgenerally do not occur.

1.11.3. At temperature above 80°C the SSC is not a concern. That allow to

use different material in relationship with the well temperature anddepth.

1.11.4. Stress corrosion cracking can occur also in presence of chloride or bromide ions, particularly in hot conditions. These ions can bepresent in formation water, injection water and brines used ascompletion, workover and packer fluids.

1.11.5. Certain corrosion resistant alloys (CRA), especially austeniticstainless steel, are susceptible to stress corrosion cracking.



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2. CORROSION CONTROL MEASURES Reference

2.1. Corrosion control measures may involve the use of one or more

of the following

P-1-M-7100 6.2

2.1.1. Control of the environment:

• pH

• Temperature

• Pressure

• Chloride concentration

• CO2 concentration

• H2S concentration

• H2O concentration

• Flow rate• Inhibitors

P-1-M-7100 6.2

2.1.2. Surface treatment:

• Plastic coating

• Plating

P-1-M-7100 6.2

2.1.3. Improvement of the corrosion resistivity of the steel:

• Addition of the alloying elements micro structure

P-1-M-7100 6.2

2.2. Corrosion Inhibitors P-1-M-7100 6.5

2.2.1. An inhibitor is a substance which retards or slows down a chemicalreaction. Thus, a corrosion inhibitor is a substance which, whenadded to an environment, decreases the rate of attack by theenvironmental on a metal.

Corrosion inhibitors are commonly added in small amounts to acids,cooling waters, steam or other environments, either continuously or intermittently to prevent serious corrosion.

There are many techniques used to apply corrosion inhibitors in oiland gas wells:

• Batch treatment (tubing displacement, standard batch, extendedbatch)

• Continuous treatment

• Squeeze treatment

• Atomised inhibitor squeeze - weighted liquids

• Capsules

• Sticks.

P-1-M-7100 6.5



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2.3. Coating

2.3.1. Coating prevents contact of the metal by corrosive fluids. Internallycoating tubing, however, is relatively expensive and has severaldisadvantages.

2.3.2. Easily damaged by wireline tools..

2.3.3. Imperfect coating may result in severe localised corrosion.

2.3.4. Requirement for a “Seal Ring” TO protect each connection which isnot coated

2.3.5. Coated tubing does not eliminate the need to protect trees andflowlines.

2.4. Gas removal

2.4.1. Removal of corrosive gases has most application in water injectionsystems. Even 1 ppm dissolved oxygen corrodes steel several timesfaster than oxygen free water.

2.4.2. Methods

2.4.2.1. Use of chemical scavengers.

2.4.2.2. Vacuum deaeration.

2.4.2.3. The choice between the two methods shall be made in accordancewith the topside facilities engineer.

2.5. Corrosion resistant alloy

2.5.1. The use of high cost alloy materials shall be in long term the cheapestmethod to manage corrosion because of their resistance that mayreduce the needs of workover and the risk associated with a failedcompletion

3. MATERIAL SELECTION Reference

3.1. The material selection of tubing shall be made upon the followingdiagram:

P-1-M-7100 6.8



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10-1

10-2

10-3

10-4

100

FBHT <= 150 Cand Cl- <= 50000 ppm13% Cr

150 > FBHT <= 200 CCl- <= 50000 ppm22% Cr

200<FBHT<=250 C25% Cr-SAor 25% Cr

C- STEELJ 55N 80P 110

FBHT<= 250 CandCl- <= 20000 ppm25% Cr-CW

FBHT<=250 CandCl- <= 50000 ppm25% Cr-CW

200<FBHT<=250 CandCl- > 50000 ppm28 % Cr or

INCOLOY- 825

(*)

FBHT <= 200 CCl-<=50000 ppm22 % Cr-SAor 25 % Cr-SA28 % Cr INCOLOY- 825

FBHT <= 250 CCl- <= 50000 ppm25 % Cr-SAor 28 % Cr INCOLOY- 825

FBHT<= 250 C

Cl

-

> 50000 ppm28 % Cr INCOLOY- 825

FBHT < 200 C28 % Cr

or INCOLOY-825

LOW ALLOY STEEL

L 80 modC 90 T1C 95 T1

10

1

10010110-110-210-310-4

pH 2S (atm)

pCO2(atm)

(*)FBHT<= 150 C

Cl- <= 50000 ppm

13 % Cr 80 Ksi max

or 22 % Cr 25 % Cr

FBHT <= 200 C

Cl- > 50000 ppm

22 % Cr- CW 25 % Cr -CW

150 < FBHT <= 200 CCl- < 50000 ppm

22 % Cr 25 % Cr

200 < FBHT <= 250 C

Cl- < 50000 ppm

25 % Cr-CW

200 < FBHT <= 250

Cl- > 50000 ppm

25 % Cr-CW

FBHT < = 65 CL 80or L 80 mod;C 90 T1T 95 T1

FBHT >80 CJ55 K55 N80-1 C95P110-1 (only oil)or L80 mod C90 T1

65 < FBHT<= 80CJ 55 K 55 N80-1or L 80 mod C90 T1T 95 T1



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3.2. For the down hole equipment the selection shall be made as per the

following diagram

P-1-M-7100 6.5

10 -1

10 -2

10 -3

10 -4

100

FBHT <= 100 CCl- <= 50000 ppm9 Cr 1 Mo

100 < FBHT <= 150 CCl- <= 50000 ppm13 % Cr 80 ksi max

150 > FBHT<= 250 C25% Cr-CWor 25% Cr INCONEL 718INCOLOY 825

C-STEELor

AISI 41XX

200 < FBHT<= 250 CCl- <= 50000 ppm25 % Cr or INCONEL 718INCOLOY 825

200 < FBHT<=250 CCl- > 50000 ppm28 % Cr or INCONEL 718INCOLOY 825

(*)

FBHT <= 200 CCl-<=50000 ppm

22 % Cr-SA25 % Cr-SA28 % Cr INCOLOY 825INCONEL 718

200 < FBHT <= 250 CCl- <= 50000 ppm25 % Cr-SA28 % Cr INCOLOY 825INCONEL 718

FBHT<= 250 CCl- > 50000 ppm28 % Cr INCOLOY- 825INCONEL 718

FBHT < 200 C28 % Cr

or INCOLOY 825INCONEL 718

AISI 41XX22 HRC max

10

1

10010110-110-210 -310-4

pH2S (atm)

pCO 2(atm)

(*)150 < FBHT <= 200 C

Cl - <= 50000 ppm

22 % Cr 25 % Cr

INCONEL 718

INCOLOY 825

200 < FBHT <= 250 C

Cl - > 50000 ppm

25 % Cr

INCONEL 718

INCOLOY 825

100 < FBHT <= 200 C

Cl - > 50000 ppm

22 % Cr-CW 25 % Cr-CW

INCONEL 718

INCOLOY 825

200 > FBHT <= 250 C

Cl - > 50000 ppm

25 % Cr-CW

INCONEL 718

INCOLOY 825

FBHT < = 65 C AISI 41XX22 HRC max

65 < FBHT <=80 CC-STEEL 80 Ks i max AISI 41XX

FBHT > 80 CC-STEEL 110 Ksi max AISI 41XX



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4. CORROSION MONITORING Reference

4.1. Where any kind of corrosion is expected a corrosion monitoringshould be planned during the field exploitation.

Field sources to get information about corrosion to consider are:

4.2. Coupon exposure test

4.2.1. Coupon exposure tester should be applied where wireline tools areplanned in the completion or in a specific wireline mandrel. Weightloss, area of coupon and exposure time are used to calculatecorrosion rate reported in mils (0.001inch) per year (MPY). A lowMPY rate can be serious if concentrated pitting is occurring, while a

high MPY loss with a general area type of loss may be fairlyinsignificant.

4.2.2. Both MPY and pitting penetration shall be reported to evaluate thecorrosion problem.

4.3. Tubular inspection logs

4.3.1. Casing inspection logs are magnetic flux leakage detection tools andare available from various service companies. They use the distortedmagnetic field around an anomaly in the pipe wall, such as acorrosion pit, to create a signal which is recorded on a log.

4.3.2. A single recording of the tubing wall may be not used for a goodcorrosion evaluation. Multiple recording at different time and their relative comparison shall give a better understanding of the corrosionprocess in act.

4.4. Inspection of too ls recovered during workover

4.4.1. Whenever a workover is planned for any contingency reason a visualinspection of the tubing and the downhole equipment shall beperformed to detect any kind of visible corrosion.

4.4.2. The failed equipment shall be addressed to the Corrosion Dept whichis in charge to evaluate the corrosion process that took part andsuggest the solution to problem.

4.5. Equipment fai lure records useful data

4.5.1. Source of equipment.

4.5.2. Metal type and characteristic. Material traceability data (ROM,Supplier)



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4.5.3. Characteristic of the environment. Well production and interventionhistorical data.

4.5.4. Dynamic flow data.

4.5.5. Operating time before failure.

5. ELASTOMER SELECTION Reference

5.1. Elastomer (and other components of the sealing unit) shall be chosenup the following but not limited consideration.

5.1.1. Temperature.

5.1.2. Pressure.

5.1.3. Pressure and temperature cycling.

5.1.4. Dynamic or static seal.

5.1.5. Wetting fluids.

5.1.6. H2S.

5.1.7. CO2.

5.1.8. Chloride, Bromide.

5.1.9. Corrosion inhibitors.

6. ELASTOMER PRACTICAL GUIDELINES Reference

6.1. The effect of a chemical reaction doubles for every 10°C temperaturerise. The lifetime roughly doubles for every 10°C drop.

6.2. Make sure that the upper temperature is within the capability of theseal material.

6.3. The seal material must be compatible with the fluid environments.

6.4. Do not use Zinc Bromide brine with Nitriles.

6.5. Be careful with Vitons if amine inhibitors are present. It may better touse Aflas.

6.6. Methanol can affect Vitons. Use Aflas or Nitrile if possible.



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6.7. Do not use EPDM where hydrocarbons are present.

6.8. For really aggressive, hot and sour conditions, the best choice is theexpensive Kalrez (to 260°C) or Chemraz (20% cheaper and better properties over -20° to 230 °C).

6.9. Consider use of T-seals with back-up rings if pressure exceeds 1500psi, or pressure exceeds the modulus of the material.

6.10. Consider whether there is likely to be gas dissolved into the seal,which may be subjected to rapid decompression. There are specialgrades with improved decompression resistance available.

6.11. Seal stacks form good solutions to wide ranging service. They allowuse of varying hardness or differing materials in the stack, and theouter rings may be sacrificial for the sake of the main inner seal.

6.12. Elastomers with higher chemical and temperature resistance (Aflasand Kalrez) achieve this resistance often at the expense of elasticity.This compromises their ability to seal with temperature fluctuation.

Reference List :

‘Completion Design Manual’ STAP P-1-M-7100



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PL. 3.8. LIFTING DESIGN

1. DEFINITION Reference

1.1. The application of artificial lift simply displaces the TPC curvedownwards so that a lower bottom-hole flowing pressure is achieved.In simple terms, the artificial lift injects energy into the system.

P-1-M-7100 10

2. BASIC METHODS OF ARTIFICIAL LIFT Reference

2.1. Rod pumping. P-1-M-7100 10.4

2.2. Electrical Submersible Pumping. P-1-M-7100 10.2

2.3. Gas lifting. P-1-M-7100 10.1

2.4. Hydraulic Pumping Systems P-1-M-7100 10.3

2.5. Screw Pump System. P-1-M-7100 10.5

2.6. Plunger Lift. P-1-M-7100 10.6

3. SELECTIONCRITERIA Reference

3.1. Design Considerations and Overall Comparisons:

• Capital Cost

• Downhole Equipment

• Efficiency• Flexibility

• Miscellaneous Problems

• Operating Costs

• Reliability

• Salvage Value

• System (total)

• Usage/Outlook

P-1-M-7100 10.7.1

3.2. Operating Conditions Summary:

• Casing size limits

• Depth limits

• Intake Capacity

• Noise Level

• Obtrusiveness

• Prime mover flexibility

• Surveillance

• Testing

• Time Cycle

P-1-M-7100 10.7.2



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3.3. There are more than one method of artificial lift in a given well or group of wells. Each method may be classified from excellent to poor

in accomplishing separate objectives as listed below

ROD P ESP GAS L. HYD P

Sand Fair Fair Excellent Fair

Paraffin Poor Good Poor Good

High GOR Fair Fair Excellent Fair

High Volume Poor Excellent Good Good

Depth Fair Fair Good Excellent

Simple Design Yes Yes No No

3.4. Long time choice criteria

3.4.1. The long-range recovery plan of the reservoir must be evaluated.

3.4.2. In the initial stages, reservoir pressure and GLR are generally high,so gas lift is favoured.

3.4.3. As both pressure and GLR decline, (GLR may increase), gas lift loses

its advantage and ESP become more appropriate.

3.4.4. Finally for very low pressure or low productivity Rod or Hydraulicpumping are suited.

3.5. Well productivity

3.5.1. Rate > 20,000bbl/d - ESP or Gas lifting.

3.5.2. Rate between 2,000 - 1,000bbl/d - Any except Rod pumping.

3.5.3. Rate between 200 - 1,000bbl/d – Any.

3.5.4. Rate < 200 bbl/d - Any except ESP.

3.6. Flowing bottom hole pressure

3.6.1. Gas lifting is questionable when pressure drops below about one-thirdof the hydrostatic pressure at the depth in question because theamount of gas required to lift the liquid became excessive.

3.6.2. The other methods can operate down to very low pressure with gasventing perhaps becoming a necessity.



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3.7. Water cut

3.7.1. Water cut directly influences the total production rate and thepressure losses. Generally high water cut production is common inhigh production well.

3.7.2. ESP is suggested with high WC.

3.7.3. Gas lifting is suggested with high WC.

3.8. Viscosity

3.8.1. Viscosities less than 10 cp are not a factor in determining the lift

method. However consideration shall be made for different methods.

3.8.2. For highly viscous crudes sucker rods will not fall freely, thereforeeffective stroke is reduced and the rods may become overloaded.Long stroke, low speed unit shall be preferred in this case.

3.8.3. Jet pumping may have application in that a low viscous power fluidcan be mixed downhole with the viscous crude.

3.8.4. Gas lift may cause additional problems such as hydrate or paraffinplugging due to the cooling effect of the gas expanding through thegas lift valves.

3.8.5. High viscosity may deteriorate ESP efficiency.

3.9. Formation volume factor

3.9.1. Formation volume factor must be considered for all type of artificiallift, since any bottom hole pumping must be designed to pump theadditional volume at the bottom of hole.

3.10. Depth criteria

3.10.1. Sucker rod are capable of lifting from depth around 3000 m but

horsepower, stroke length, rod size and stretch, load and drag frictionlimit design and they tend to be low in volumetric efficiency.

3.10.2. ESP require high fluid heads and at depth, with elevated temperature,experience motor and/or cable failure.



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4. ROD PUMPING Reference

4.1. The most common pumping system on low rate land wells is the rodor beam pumping. It is usually limited to shallow wells (<8,000ft)producing less than 500stb/d although they can produce up to2,000stb/d.

P-1-M-7100 10.4

4.2. On land and where enough space around wellhead is available therod pumping is suggested for shallow to medium deep well.

4.3. The annulus is usually left open and used to vent any free gas that isseparated downhole. Tubing is used as the production conduit andcontains the rods preventing wear and corrosion to the annulus.

P-1-M-7100 10.4

4.4. Where high GOR is expected a gas anchor shall be installed or thepump shall be installed below perforation.

4.5. The tubing is usually anchored to the casing and pulled into tension toreduce tubing movement, buckling and, hence rod wear.

P-1-M-7100 10.4

4.6. The load on the polished rod can be estimated from dynamometer surveys, which measure the rod load versus displacement at thesurface and serves the most effective means of diagnosing pumpproblems.

P-1-M-7100 10.4

4.7. Where paraffine is expected rod with paraffin scratcher and rod

rotating device is suggested.

4.8. System design is very complex and is an iterative process normallycarried out by computer software. API have produced a programmeto generate a set of design curves published in API RP11L andprovided some general results in Bulletins 11L3 and 11L4 which are auseful starting point for design.

P-1-M-7100 10.4

4.9. Where the well is naturally flowing and rod pumping is foreseen later on, the use of TBG anchoring and pump seating nipple is suggested.



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5. GAS LIFTING Reference

5.1. The main advantage of gas lift is flexibility. It is applicable in a widerange of rate and depth and the design may be changed by wirelineoperations.

5.2. Gas lifting is adaptable to deviated well both onshore and offshore butthe design may be more critical in high deviated well due to the flowpattern that may occur in the tubing.

5.3. Care shall be given to hydrates and freezing problem that may occur in the supply line.

5.4. In recent times, much higher gas supply pressures have been used to

enable deeper valves to be reached or reduce the number of mandrels and valves required. This increased pressure, however,applies more pressure on the annulus casing, hence gas tight or premium connections are generally selected.

P-1-M-7100 10.1.1

5.5. Where the production casing joint is inadequate or the supply gas iscorrosive a dual string completion for injection and production isrecommended. Local regulations are TO be considered (I.E. HS&Erequires a SCSSV on the annulus)

5.6. Where the well is naturally flowing and the gas lifting is foreseen later on the preinstallation of spaced gas lift mandrels equipped with

dummy valves should be planned.

5.7. In continuous gas lift, it is desirable to position the lower gas injectionpoint as deep as possible in the well, however this is limited by:

• Available gas lift pressure

• The flowing tubing pressure at the intended offtake rate

• The depth of the packer and deepest gas lift mandrel

• The differential required to close the upper valves closed (+/-20psi) and to ensure that injection at the operating GLV isstable (between 50 and 500psi)

P-1-M-7100 10.1

5.8. The supply gas pressure design shall take into account the frictionloss term and at least 20psi/valve for closing upper valves and 100-500 psi margin for stable injection through the operating valve.

5.9. Gas lift design is an iterative and complex process which is normallycarried out on computer. The software in use in AGIP Well AreaEngineering is Prosper.

5.10. Consider that the main gas lift trouble should be the incorrect valvespacing and the leaking in upper valves.



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6. ELECTRICAL SUBMERSIBLE PUMPING Reference

6.1. ESP is an easy operation lift method applicable in any location exceptwhere the cost of workover is high.

6.2. ESPs greatest application is in moving large volume of low GOR(<100scf/stb) fluids. They are particularly popular for high rateundersaturated oil wells, high water cut wells and water supply wells.Their main limitation is gas production but improved downholeseparators and procedures can now handle GORs up to 1,000scf/stb.

P-1-M-7100 10.2

6.3. If possible, the installation should be designed to facilitate downholeseparation of free gas and vented up the annulus which is necessarywhen the gas volume exceeds the pump operating limit (typically +/-10% of the total fluid volume). On offshore installations, gasproduction up the annulus may be a significant problem. Annular safety valves or dual string with SCSSV’s shall be considered.

P-1-M-7100 10.2

6.4. Most pump installations are on the end of tubing and positionedabove the perforations or open hole. The motor is situated at thebottom of the assembly so that the well flow around the motor willdissipate the heat generated. If the pump has to be positioned belowthe interval, a shroud is used to draw the produced fluid down pastthe motor. Bottom discharge pumps are used in powered dump floodwells.

P-1-M-7100 10.2

6.5. The key to an efficient ESP design is heat removal and insulationmaterial selection for the actual operating temperatures andenvironment, especially when temperatures are in the region of 250

oF. The clearance between the pump and the casing should be

small enough that a flow velocity of a minimum of 1ft/sec is achieved.In large casings, a shroud must be used to provide this rate.Centralisation of the pump is also critical.

P-1-M-7100 10.2.2

6.6. Cable selection and splicing procedure shall take into account thewell temperature and the well fluids characteristic including thepresence of corrosion inhibitors.

6.7. Cable failure may occur and require pulling the tubing to repair. Hightemperature, corrosion and poor handling on splicing lead to cablefailure.

6.8. The electric power supply shall be stable to avoid unwanted pumpstops.



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6.9. A motor electric protection device shall be installed in the main power line to avoid current drop or rise more than 20% of the actual value.

6.10. It is normal procedure to select the largest pump that will fit into theproduction casing (especially if this was catered for in the planningstage). Small casing or liners will obviously limit the pump sizeselection.

P-1-M-7100 10.2.1

6.11. Application with variable speed driver reduce starting loads andincrease system life and flexibility from around 50 to 190% of nominalrate.

6.12. The ESP design is a complex process, which is normally carried outon computer. The software in use in Eni/Agip Well Area Engineeringis PROSPER or AUTOGRAPH.

7. JET PUMPING Reference

7.1. The jet pump uses no moving parts and imparts momentum into thefluid using the Venturi effect with a jet, throat and diffuser. The size of these can be varied to pump volumes of 100-15,000stb/d althoughfree pump systems are limited to 8,000stb/d with 4

1/2” tubing.

P-1-M-7100 10.3

7.2. The pumps can be installed and retrieved by wireline or pumpingmethod using swab cups, hence providing lower servicing costs.

P-1-M-7100 10.3

7.3. As there is no moving parts, the pump is not as sensitive to damage

and lower quality power fluids can be used and can be used in higher GOR wells up to 3,000scf/stb.

P-1-M-7100 10.3

7.4. Pump efficiency is low at 33-66% and large production rates can onlybe achieved in high rate installations.

P-1-M-7100 10.3

7.5. Initial capital cost is high because topside facilities must be providedto treat the mixture of power and produced fluid.

7.6. Down time in production may be caused by corrosion and abrasivefluid that will damage the nozzle as well as the maintenance of surface equipment.

7.7. Since the production must accelerate to a fairly high velocity to enter the throat, cavitation is a potential problem that shall be considered.

Reference List :

‘Completion Design Manual’ STAP P-1-M-7100



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PL. 3.9. COMPLETION AND PACKER FLUIDS


1.1. Completion Fluid:

It is the fluid in the well during the installation (or the removal) of thecompletion (300psi minimum overbalance). The hydrostatic of thecompletion fluid has to control the formation pressure.

M-1-M-5015 2.1

1.2. Packer Fluid:

It is the fluid in the annulus CSG/TBG above the upper packer after the packer has been set. Packer fluid can be either the same fluidused while running the completion (completion fluid) or any other fluiddisplaced in the annulus above the upper packer after the completion

operation. In some special applications HP wells, Packer fluid couldbe “non kill weight fluid”.

M-1-M-5015 2.2

1.3. Safety Barrier Status Of Complet ion Fluid:

The completion fluid continues to be a barrier until its specific gravityremains adequate to the formation pressure.

During well testing, after packer setting, the annulus completion fluidis an indirect barrier because two operations (opening circulatingvalve and BOP pipe rams shut-in) are required to establish the fluidcirculation to kill the well.

M-1-M-5015 2.2

1.4. Safety Barrier Status Of Packer Fluid:

The packer fluid cannot be considered a barrier. Main reasons are:

• Rheological properties and circulating capability cannot beensured for a long term period.

In evenience of leakage from the tubing string, the tubing pressurecould be higher than the hydrostatic pressure in the annulus(whichever is the density of the packer fluid). The pressureaccumulated into the annulus could impair the casing integrity(especially in HP/HT wells).

M-1-M-5015 2.2



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2. COMPLETION FLUID DUTY Reference

2.1. The completion fluid, usually a brine, is chosen for its compatibilitywith the formation and its fluids so as not to cause any formationdamage. It should be selected to provide an overbalance at the top of the reservoir. It also must be selected for its stability over long timeperiods and not suffer from dehydration or deterioration.

P-1-M-7100 7.3.6

2.2. Limit settling of solids if any present.

2.3. Provide carrying capacity to remove solids.

2.4. The information required to make a considered selection may beobtained from the IWIS database (which holds all the data regardingthe drilling of the well), well tests carried out earlier and other sourceswhich may be useful in the decision making process.

P-1-M-7100 7.3.6

3. PACKER FLUID Reference

3.1. Packer fluid duty

3.1.1. Limit settling of solids if any present.

3.1.2. Minimise corrosion rate.

3.1.3. Stable with temperature and time.

3.1.4. Environmental and operational safety.

3.2. Packer fluid choice

3.2.1. Water base drilling mud, should be avoided.

3.2.2. Water, Brine or OBM mud should be preferred.

4. BRINE PROPERTIES Reference

4.1. Brines characteristic should minimise hydration, swelling and / or dispersion of formation clays. When the fluid weight is not a concern

typical concentration of the most common brine to inhibit clayhydration are:

4.1.1. Na Cl 5-10 %

4.1.2. Ca Cl2 1-3 %

4.1.3. KCl 1-3 %



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4.2. Brine parameters

4.2.1. Brine type at a relevant density shall take into account the followingparameters:

4.2.1.1. Freezing point. and Crystallisation temperature

4.2.1.2. Corrosive properties.

4.3. Fluid density variation with temperature, it shall be taken intoconsideration the reduction of fluid density caused by temperature

4.4. Brine density attainable

4.4.1. Na Cl 1- 1.17 kg/l

4.4.2. Ca Cl2 1 - 1.38 kg/l

4.4.3. Na Cl and Ca Cl2 1.19 - 1.4 kg/l

4.4.4. KCl 1 - 1.16 kg/l

4.4.5. Ca Cl2 and Ca Br 2 1.4 - 1.8 kg/l

4.4.6. Solution density is a function of temperature. Thus density at surface

conditions may have to increased to obtain desired hydrostaticpressure downhole. Average temperature and relevant density shouldbe adopted.

5. FORMATION INTERACTIONS Reference

5.1. Consideration shall be given to brine/formation interactions

5.1.1. The quality of the fluid used during a completion and workover operation cannot be over-emphasised as the productivity is governednot only by the damage caused by visible contaminants such assolids but also the damage caused by invisible contaminants such as

calcium ions, sulphate ions and dissolved iron. It is, therefore,essential that all of these and other similar contaminants arecontrolled to as low a level as feasible and, wherever possible,completely removed.

P-1-M-7120 4.7.2

5.1.2. Incompatibility with formation fluids.

5.1.3. Entrained solids.

5.1.4. Water blocks.



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5.1.5. Emulsion blocks.

5.1.6. Interference with TDT logging readings.

5.1.7. Completion fluid brines and additives may not be compatible withreservoir interstitial water. Rock permeability cam be plugged byprecipitates formed when incompatible waters are intermingled. For example barium sulfate will precipitate when solutions containingbarium ion and sulphate ion are intermixed. Barium is sometimespresent in formation water and sulphate ion is present in seawater and in fluids containing calcium lignosulfunate fluid loss additive or asimpurity in some sacked Na Cl.

5.1.8. Completion fluids that are reported solid free can contain solidparticles that can cause deep bed formation plugging. Sources of these organic and/or inorganic solids include:

• The base fluid itself

• Impurities in dry salts

• Particulate matter from surface pits and well tubular

• Iron oxides precipitated from solutions containing dissolvedoxygen that are circulated downhole

6. BRINE FILTRATION Reference

6.1. The prime filtration system is the Diatomaceous Earth filter press witha bag filter system for use as a downstream guard filter. Sometimes,on standby is a low pressure, Cartridge Filter unit.

Both the DE and the cartridge units are capable of filtering down to 2microns.

P-1-M-7120 4.8

6.2. Solid content in brine shall be minimised by a good cleaning of surface equipment and well tubular and by the use of 2µm filteringunit.

6.3. Diatomaceous earth shall be used when filtering is a need. DEfiltering can remove 90% of particles above 2µm. Care must be taken

to prevent DE going downhole.

6.4. Absolute cartridge filters must be placed downstream of press filter toact as guard filters.

6.5. The fluids shall be treated to prevent iron oxide precipitation withscavenging oxygen or sequestering oxygen products.



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7. FLUID LOSSES Reference

7.1. In depleted reservoir where high fluid loss may occur the followingproblems shall be also considered:

7.1.1. Lack of supply water.

7.1.2. Souring (BHT< 100 °C).

7.1.3. Well clean up trouble due to the high invasion.

7.2. Temporary plugging

7.2.1. Whenever the high fluid loss may occur, the benefit to temporary plug

the perforation shall be considered.

7.2.2. Calcium carbonate can be used as a drilling fluid and for LCM pills tocontrol fluid losses. In completion operations it is now the mostcommonly used fluid for controlling fluid losses within Eni-Agip’operations.

P-1-M-7120 4.9.3

8. OIL BASE MUD Reference

8.1. In place of brines when high fluid losses or severe corrosion problemcan occur the use of oil based and inverted emulsion mud should beused. They are formulated in the range from 0.86 up to 2.5kg/l and

are particularly useful where high density are required.

8.2. Inverted emulsion muds for completion and packer fluid purposesmust be well sheared to assure stable characteristic. The mainparameters to control are:

8.2.1. Oil / water ratio P-1-M-6160 10.1.6

8.2.2. Plastic viscosity, yield point, gel strength P-1-M-6160 10.1.3

8.2.3. Electric stability P-1-M-6160 10.3.1

Reference List :

‘Drilling Fluids Operations Manual’ STAP-P-1-M-6160

‘Completion Procedures Manual’ STAP-P-1-M-7120


‘Guidelines for Utilization of “Non Kill Weight Packer Fluid”’ STAP-M-1-M-5015



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PL. 3.10. PACKERS


1.1. High corrosive wells:

• The fluids have high corrosive problems.

P-1-M-7100 8.1.3

1.2. Highly critical wells:

• Deep depths > 4500m.

• High temperatures, SBHT > 130°C.

• High pressures, SBHP > 700 atm.

• Subsea well-head well.

• Platform well having the risk of failure due to the potential

collision from a vessel with the structure.• Gas injection well with pressures, ITHP above 3,000psi.

P-1-M-7100 8.1.3

1.3. Critical Well

• Temperatures between 100 and 130°C

• Depths between 3,000 and 4,500m.

P-1-M-7100 8.1.3

1.4. Non-critical well

• Depth of less than 3,000m.

•••• Temperatures below 100 °C.

P-1-M-7100 8.1.3

2. SINGLE COMPLETION PACKER Reference

2.1. Packer selection

2.1.1. The choice is mainly linked to the type of well:

1. In the case of a highly critical well, select a permanent packer.

2. If the well has high corrosive, select a permanent/retrievable or permanent packer, with priority be given to the former.

3. If the well is critical or non-critical, (Refer to Figure PL 3.5)

P-1-M-7100 8.1.4



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A High frequency of tubing pullout.

B High frequency of tubing-packer pullout.

C Use of TCP drilling techniques

D Measured well depth ≥ 3000 m.

E The workover fluid damages the formation.

F The packer fluid is a high density mud (> 1.6 kg/l) with probable soliddeposits on the packer.

G Gas injection well with injection pressure > 3,000psi.

Figure PL 3.5 - Type of Packer for Crit ical and Non-Critical Wells



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2.2. Setting method

2.2.1. Permanent and Permanent Retrievable Packers

2.2.1.1. The selection is dependent mainly on the well characteristics:

1. If the well is corrosive or very critical, choose hydraulic setting.

2. If the well is critical or not critical, (Refer to Figure PL 3.6).

3. Reference (A) is only true if one of the following conditions arerelevant:

• SBHT > 150 °C (= 270 °F).

• Is a deviated well, with a maximum deviation angle > 50°.

• The completion fluid = mud with density > 1.6 kg/l.• Gas a production liner with inclination > 30°.

P-1-M 7100 8.1.4

Figure PL 3.6 - Packer Setting Method for Critical and Non-Criti cal Wells

For a mechanical type permanent packer, the setting is defined by the conditions detailed in(A). The same procedure will also be used later for packers of the type used in a selectivetype completion.



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2.2.2. Retrievable Setting Method

2.2.2.1. The method of setting used for retrievable packers is made, followingthe diagram in Figure PL 3.7:

P-1-M 7100 8.1.4

Figure PL 3.7- Retrievable Packer Setting Method

1) Check (A) is only true if one of the following conditions are relevant:

The well is deviated with a maximum deviation angle of > 20°.

• The bottom-hole temperature (SBHT) is > 60°C.

• The vertical depth of the packer setting is > 2,000m (this is true to definitiveand not test completions).

• Stimulation’s are planned.

2) Check (B)

• Using TCP shooting techniques.

3) Check (C)

• There is high frequency of tubing pullout (life of the completion < 5 years).

4) Check (E)

• Completion fluid and damage to the formation

5) Check (F)

• The packer fluid is a high density mud (> 1.6kg/l) with the probability that itleaves solid deposits on the packer.



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2.3. Packer Tubing Connection

2.3.1. Retainer or Permanent Retrievable Packer Tubing Connection

2.3.1.1. The packer tubing connection selection is in according to the stressanalysis and the displacement method.

2.3.2. Retrievable Packer Tubing Connection

2.3.2.1. The choice of the tubing-packer connection for retrievable packers(hydraulic and set down weight) is made on the basis of that in

Figure PL 3.8.

Particular conditions raise questions over which type of retrievablepacker to use. In these cases, a permanent/retrievable packer is thepriority or a permanent should be used and consequently theassociated setting procedure and seal assembly selected.

P-1-M 7100 8.1.4

Figure PL 3.8 - Tubing-Packer Connections for Retrievable Packers



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3. SINGLE SELECTIVE COMPLETION PACKER Reference

3.1. Packer selection

3.1.1. The first case classifies the well on the basis of depth characteristics

(≥ 4,000m) but more on the basis of its complexity.

P-1-M 7100 8.1.5

Figure PL 3.9 - Single Select ive Packer For Complex Wells

if several different configurations are available, as for example in Figure PL 3.9, the engineer has a certain degree of freedom of choice but is, however, governed by the or der of priorityspecified along with the choices.

If the conditions as of Figure PL 3.9, are not applicable, these cases are classified by welldepth:



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Figure PL 3.10 - Selective Sing le Well w ith Depths Between 3,000 and 4,000m

Figure PL 3.11 - Selective Sing le Well w ith Depths Between 1,500 and 3,000m



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Figure PL 3.12 - Selecti ve Single Well w ith Depths Less Than 1,500m

In the case of depths less than 1,500m in a well not considered complex, it is stronglyrecommend that a retrievable type packer be used.

Application of the criteria illustrated in Figure PL 3.9 through Figure PL 3.12 is common withthe only exception, in the case of multiple choices, being that the order of priority for the lower zone can be changed by applying the following rules:

• If workovers are planned with removal of the tubing and packer, and aretrievable packer is one in the list of possible choices, then it should be

selected.• If the completion fluid is a mud with deposition problems, and a permanent

or permanent/retrievable packer are in the list of possible choices, then thepermanent/retrievable should be selected over of the retrievable.



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3.2. Setting method

3.2.1. The type of setting method proposed depends on the followingfactors:

• Type of packer

• Setting distance between the packers.

The setting criteria of a mechanical permanent packer (on aworkstring, or wireline) are those already defined for the singlecompletion

P-1-M 7100 8.1.5

3.3. Packer Tubing Connection

3.3.1. By classifying the packers by type and setting with the zones treatedseparately. In some cases, three zones are assumed (upper,intermediate, and lower). In cases where there is no specific mentionof an Intermediate zone, it is treated with the same criteria used for the upper zone.

Generally, the result of the stress analysis specifically identifies thepackers with releasing problems. Due to this, the zones are betreated separately; i.e. modifications are be made only to thosepackers which have the problems. It is recommended in any case tore-check the completion after having made the modifications.

P-1-M 7100 8.1.5

4. DUAL COMPLETION PACKERReference

4.1. Packer Characteristics

4.1.1. Dual string packer selected, shall be qualified following ARPO/STAPprocedures, to verify that the features requested are present and fullyoperating.

M-1-SS-5705

4.1.2. Dual string packer shall be hydraulic set M-1-SS-5705 4.1.2.1

4.1.3. Mandrel shall have at least same strength of the tubing string. M-1-SS-5705 4.1.2.7

4.1.4. Mandrel shall have the ability to rotate

4.1.5. Bi-directional slips below packing element are preferred. M-1-SS-5705 4.1.2.12

4.2. Setting Method

4.2.1. Setting method shall be hydraulic , with pressure applied to one of thetwo strings. Generally on short string.

M-1-SS-5705 4.1.2.1

4.2.2. Maximum setting pressure should be 3.500 psi. M-1-SS-5705 4.1.2.13



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4.3. Retrieving Method

4.3.1. Retrieving shall be by pulling on either or both the tubing strings. M-1-SS-5705-4.1.2.2

4.3.2. Shear ring/screws, of the releasing mechanism shall be inaccordance with tubing characteristics and completion design.

5. DUAL SELECTIVE COMPLETION PACKER Reference

5.1. When run in the Dual Selective Completion, packer shall have norelative setting motion of either string during setting sequence.

M-1-SS-5705

5.2. In addition to rotate, stroke capability of the mandrel are preferred.

Reference List :


‘Specification for Standard Retrievable Packers’ STAP-M-1-SS-5705



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PL. 3.11. TUBING JOINT


1.1. The tubing joint selection depends primarily from the materialselection.

A-1-M-1003

1.2. According to the specification STAP M-1-M 5006 ‘ConnectionProcedure Evaluation’, there are two service classes, I and II, termed Application Levels (AL). Application Level I applies to the most severeservice conditions.

M-1-M-5006P-1-M-7100 7.9.2

2. JOINT SELECTION Reference

2.1. Incoloy 825, Duplex (25%, 22%, Cr Cold Worked), 28% Cr

2.1.1. The tubing joint connections suggested are in order AMS 28, Vam ACE

2.2. Carbon steel - Martensi tic 13% Cr - Low al loy steel

2.2.1. To date three tubing connections have been qualified for the mostsevere conditions ALI. They are:

Coupled Connections

• AMS 28 ( manufacturer Dalmine)

• Vam ACE ( manufacturer Vallourec and Sumitomo)

Integral Connections

• Eni-Agip Division and Affiliates A-DMS (Dual Metal Seal)

Other connections like Hydril CS, PJD Dalmine and Antares MS havenot yet been subjected to the complete qualification programme asper STAP M-1-M- 5006 or API 5C5. They have however been usedsuccessfully for years with good results. They may be used for allservice condition where an Application Level II connection is required.

P-1-M-7100 7.9.2

Reference List :


‘Test Procedure for Connection Evaluation’ STAP-M-1-M-5006

‘Tubing Handling & Running Procedures’ STAP-A-1-M-1003



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Well testing s trings: A.L. I integral joint

Horizontal wells with build up> 20° / 100 ft: A.L. I integral joint

Wells w ith TVD > 4,500m: A.L. I integral joint

Gas Injection Wells:

Differential working Pressure ( psi)

0 - 4,000 A.L. II

4,000 - 8,000 A.L. IWater Injection Wells:


0 - 8,000 A.L. II

Gas / Oil Production Wells (TVD <<<< 4,500 MT. ):

NACE ? NO NO YES YES

Close proximity? YES NO YES NO


0 - 4,000 A.L. II A.L. II A.L. II A.L. II

4,000 - 8,000 A.L. I A.L. II(*) A.L. I A.L. I

over 8,000 A.L. I A.L. I A.L. I A.L. I

* A.L. I for Gas Producing Wells.

NACE: defines the condition of the partial pressure of hydrogen sulphide (H 2S) in the productionfluid to select the tubing connection. (NACE Standard. MR 01-75 - Sulfide Stess Cracking ResistantMetallic Materials for Oilfield Equipment).

CLOSE PROXIMITY: This proximity assessment should consider the potential impact of anuncontrolled condition on life and environment near the wellhead (API S 6A ).

Table PL 3.1 - Application Table For Carbon Steel, Martensi tic 13% Cr, Low Alloy Steel



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PL. 3.12. TUBING SAFETY VALVE

1. GENERAL NOTES Reference

1.1. All Eni-Agip Division and Affiliates completions shall incorporate aSSSV in the completion string to provide safety in the event of anuncontrolled well flow.

P-1-M-7100 8.2.1

1.2. Definitions

1.2.1. Surface controlled sub-surface safety valves (SCSSV’s) shall be usedaccordingly to the criteria listed below in Table PL 3.2

These are designed for tubing retrievable, wireline retrievable or annulus safety valve systems. They are controlled normally bysurface applied hydraulic pressure through a control line clamped tothe outside of the tubing string. Hydraulic pressure opens and thenretains the valve open. Removal of the pressure allows the valves toclose. These valve systems are fail safe and are preferred toSSCSSV’s.

P-1-M-7100 8.2.1

1.2.2. Working pressure (WP) is defined as the pressure that the wholebody can withstand

M-1-SS-5706E

1.2.3. Test pressure is the pressure at which all the pressure containingparts are tested, with the closing mechanism left open; usually TestPressure = 1.5 Working Pressure.

M-1-SS-5706E

1.2.4. Control Chamber Pressure is the control fluid pressure acting into thepiston chamber.

M-1-SS-5706E

1.3. Valve Type/Closure Mechanism Selection P-1-M-7100 8.2.5

1.3.1. This section gives recommendations on the choice of valve with thecorresponding type of closure mechanism. (Refer to Table PL 3.3)

P-1-M-7100 8.2.5

1.4. Working Pressure

1.4.1. The working pressure can be calculate as WP= Static Bottom Hole

Pressure (SBHP) or as WP= Maximum Static Tubing Head Pressurex Safety Factor (STHP x SF)

M-1-SS-5706E

1.4.2. The Safety Factor is determined as SF=1.1 for Gas Wells SF=1.3 for Oil Well



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Well Type Criteria

Oil Producer • All new offshore development.• All wells onshore which can sustainnatural flow.

• All old wells in above categories whichare to be recompleted.

• All isolated wells.

Gas producer • All new offshore development.

• All old wells being recompleted.

Gas storage • All wells.

Gas injection • All wells.

Water injection • All wells.

Artificial lift • All wells on gas lift, tubing and annulus.

• Electrical submersible pump, tubing andonly annulus if used for gas venting.

H2S in produced fluids • All wells.

Table PL 3.2 - Criteria for Use of SCSSV's

Type of Valve Applications

Tubing Retrievable Flapper Valve • Offshore platform wells.• Subsea wells.

• Wells with the presence of H2S or CO2.

• Wells with surface flowing temperaturegreater than 130°C.

• Wells with shut-in surface.

Wireline Retrievable Surface ControlledFlapper Valve

• As on insert valve for tubing retrievableSCSSV’s.

Storm Chokes • As a backup to the WRSV above whenthere is a control line failure. Set in the

next lowest wireline nipple. Annular Safety Systems • Gas lift wells.

• ESP wells with gas venting.

• Jet pump wells, under the pump.

Wireline Retrievable Injection Valves • All waste wells.

Table PL 3.3 - SSSV Closure Mechanism Applications



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2. SEALING SYSTEM Reference

2.1. Standard Condition (no H2S, no CO2)M-1-SS-5706E

2.1.1. Working pressure < 5,000psi

2.1.1.1. Piston (dynamic seal) shall be No-Elastomer.

2.1.1.2. Flapper seal shall be No-Elastomer.

2.1.1.3. Static seal shall be Metal to Metal.

2.1.1.4. Metal to Metal stop seals are not required.

2.1.2. Working pressure > 5,000psi and < 10,000psi


2.1.2.2. Flapper seal shall be Metal to Metal.


2.1.2.4. Metal to Metal stop seals are required.

2.1.3. Working Pressure > 10,000psi

2.1.3.1. Piston (dynamic seal) shall be Metal seal




2.2. Corrosive Condition (H2S/CO2) M-1-SS-5706E

2.2.1. Working pressure < 5,000psi


2.2.1.2. Flapper seal shall be No-Elastomer.





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2.2.2. Working pressure > 5,000psi

2.2.2.1. Piston (dynamic seal) shall be Metal seal.




2.3. Equalizing system

2.3.1. The equalizing system is not a standard requirement. M-1-SS-5706E

2.4. Actuation system

2.4.1. Rod piston design is recommended. M-1-SS-5706E

2.5. Valve types

2.5.1. General

2.5.1.1. Flapper Valve type is the recommended design.

2.5.2. Tubing Retrievable (Flapper Type)

2.5.2.1. A tubing retrievable design shall be applied in the following cases:

• Offshore wells (platform or subsea)

• Wells with corrosive fluid (H2S/CO2)

• Wells with flowing tubing head temperature greater than 130°C

• Wells with Shut In Head Pressure greater than 350 bar

• Wells with asphaltene, scales or hydrate deposition

• Wells with sand production, storage wells.

2.5.3. Wireline Retrievable (Flapper Type)

2.5.3.1. As back up to 2.5.2.1. P-1-M-7100 8.2

2.5.4. Storm Choke

2.5.4.1. As back up to 2.5.2.1. or 2.5.3.1.

2.5.5. Injection Valve

2.5.5.1. Disposal wells



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3. APPLICATION Reference

3.1. Production Oil Wells

3.1.1. The safety valve shall be always foreseen in the completion string inoil producer wells

P-1-M-7100 8.2

3.2. Production Gas Wells

3.2.1. The safety valve shall be always foreseen in the completion string ingas producer wells

P-1-M-7100 8.2

3.3. Gas Storage and Gas In jection Wel ls

3.3.1. The safety valve shall be always foreseen in the completion string ingas storage and gas injection wells

P-1-M-7100 8.2

3.4. Water Injection Wells

3.4.1. The safety valve shall be always foreseen in the completion string inall offshore application

P-1-M-7100 8.2

3.4.2. The safety valve shall be always foreseen in the completion string inwells where the water injection is placed in the oil or gas zone

P-1-M-7100 8.2

3.5. Artificial lift wells

3.5.1. The safety valve shall be always foreseen in the production string ingas lift application and in Electric Submersible Pump application.

P-1-M-7100 8.2

4. SELECTION CRITERIA Reference

4.1. General

4.1.1. Radius of exposure ROE (for 100ppm or for 500ppm) is defined in theStandard

M-1-SS-5706E

4.1.2. Close Proximity should consider the potential impact of an

uncontrolled condition on life and environment near the wellhead

4.2. Working Pressure Select ion

4.2.1. The use of SBHP or STHP x SF as WP ids defined by the Tab 1 inthe Standard

M-1-SS-5706E

Reference List :


‘Engineering Criteria for SCSSV’ STAP-M-1-SS-5706E



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PL. 3.13. ANNULUS SAFETY VALVE


1.1. Definitions

1.1.1. Working pressure (WP) is defined as the maximum pressure that theclosing mechanism can withstand

M-1-SS-5706E

1.1.2. Test pressure is the pressure at which all the pressure containingparts are tested, with the closing mechanism left open; usually TestPressure = 1.5 Working Pressure

M-1-SS-5706E

1.1.3. Control Chamber Pressure is the control fluid pressure acting into thepiston chamber

M-1-SS-5706E

1.2. Working Pressure

1.2.1. The working pressure can be calculate as WP= Static Bottom HolePressure (SBHP) or as WP= Maximum Static Tubing Head Pressurex Safety Factor (STHP x SF)

M-1-SS-5706E

1.2.2. The Safety Factor is determined as SF=1.1 for Gas Wells SF=1.3 for Oil Well

2. VALVE TYPES Reference

2.1. An annular safety system design shall be applied in the followingcases: Gas lift wells, ESP wells where the gas venting is foreseen,Jet Pump application with the safety valve located below the pumpand operate by the jet pump power fluid.

P-1-M-7100 8.2

3. APPLICATION Reference

3.1. Artificial lift wells

3.1.1. The safety system shall be always foreseen in the annulus in gas liftapplication and, in Electric Submersible Pump application where thegas venting is foreseen.

P-1-M-7100 8.2

4. SELECTION CRITERIA Reference

4.1. General

4.1.1. NACE defines the condition of the partial pressure of hydrogensulphide (H2S) in the production fluid to select the downhole safetyvalve.

NACE Std MR01-75M-1-SS-5706E



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4.1.2. Radius of exposure ROE (for 100ppm or for 500ppm) is defined in the AGIP STAP M-1-SS-5706.

M-1-SS-5706E

4.1.3. Close Proximity should consider the potential impact of anuncontrolled condition on life and environment near the wellhead

M-1-SS-5706E

4.2. Working Pressure Select ion

4.2.1. The use of SBHP or STHP x SF as WP ids defined by the Tab 1 andFig 1 of AGIP STAP M-1-SS-5706

M-1-SS-5706E

Reference List :

‘Completion Design Manual’ STAP-M-1-M-5001




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PL. 3.14. LANDING NIPPLES AND SLIDING VALVE

1. TUBING HANGER NIPPLE Reference

1.1. The maximum diameter nipple which is compatible with the ratedpressure of the Christmas tree is selected.

P-1-M-7100 8.4.2

2. INTERMEDIATE DOWN HOLE EQUIPMENT Reference

2.1. The intermediate nipples, installed between the SCSSV and the firstpacker, are used to install a back-up DHSV or to re-establish thesafety barrier or to test the tubing string

2.2. A Sliding Sleeve Door (SSD) shall be installed above the packer when a circulation or the installation of a jet pump is foreseen.

2.3. For Selective Completion a SSD is foreseen always in every layer except for the deepest

3. TAIL PIPE Reference

3.1. A Nipple below the packer shall be always present

3.2. A Perforated Pipe can be foreseen on the tail pipe

3.3. In case a perforated pipe is foreseen an addition nipple and aproduction tube shall be present below.

3.4. A Wire Line Entry Guide shall be always present and positioned (if possible) at least 15m from top of perforation.

3.5. In dual completion, Wire Line Entry Guide on short string, should bepositioned (if possible) at least 10 m below bottom perforations.

4. NIPPLES SELECTION Reference

4.1. It is a rule that if the spacing between two successive nipples is <30m, a tapered nipple will be used.

P-1-M-7100 8.4.2


5.1. Small diameter tubes for control or injection line applications aremanufactured either as seamless or seam-welded and sunk. Theyare usually available in a full range of materials and sizes.

P-1-M-7100 8.3.3

5.1.1. The standard size for both applications, control and injection line, is1/4” OD and the wall thickness chosen from among the following sizes

according to the pressure requirements:

• 1/4” OD x 0,035” wall thickness

• 1/4” OD x 0,049” wall thickness

•••• 1/4” OD x 0,065” wall thickness.

P-1-M-7100 8.3.3



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6. WORKING PRESSURE Reference

6.1. The working pressure (WP) is defined as follows:WP = Safety Valve WP + Valve Opening Pressure

Safety Valve WP is as specified by the manufacturer.

Valve Opening Pressure, provided by the manufacturer, is thepressure required to overcome the closing force of the spring plusresistance due to friction effects. Usually it ranges between 1,500 to2,000psi depending on the manufacturer.

M-1-SS-5706EP-1-M-7100 8.3.3

6.2. Working pressure is defined as follows:

hdfr PPBHSPWP −+=

where:

WP = BHSP + Pfr - Phd

BHSP = Bottom hole static pressure.

Pfr = Friction losses.

Phd = Hydrostatic pressure of injection fluid.

P-1-M-7100 8.3.3

Reference List :





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PL. 3.15. CHRISTMAS TREE


1.1. Eni-Agip divide wellhead equipment into two classifications:

Class A Equipment designed to operate up to 5,000psi WP

Class B Equipment designed to operate up to 10,000psi WP

The selection of the wellhead system pressure rating will be basedupon the max-anticipated surface pressure.

M-1-SS-5701-EP-1-M-6100 8

1.2. Crossover components/equipment shall be designed to operate to thehigher WP.

1.3. All equipment shall be designed to operate under the service

condition as defined in API 6A § 4.2 17th edition.

2. PRESSURE RATING Reference

2.1. Definition of Working Pressure for Christmas-Tree equipment isbased on following criteria: WP = Static Bottom Hole Pressure (SBHP ) or WP = Max Static Tubing Head Pressure x S.F. (STHP xSafety Factor) For gas-well S.F. = 1,1

For OIL-WELLS.F.= 1.3 ( as indication )

M-1-SS-5701E

2.2. Max Working Pressure (WP.) is defined the maximum operatingpressure that the equipment can withstand.

2.3. Test Pressure is the pressure at which the equipment are tested:

Usually Test Pressure = 1,5 Working Pressure.

3. CONFIGURATION Reference

3.1. Single Completion:

Typical Christmas tree Configuration:

3.1.1. Land: Conventional (Individual Valve) - CLASS -A, -B , -C

Components:• Tubing Head Spool

• Tubing Head Adapter (T.H.A.) With Manual Master Valve.

• Actuated Master Valve.

• Studded Cross

• Swab Valve

•••• Wing Valves.



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3.1.2. Off-Shore , Solid Block, Class -A , -B

Components:1. Tubing Head Spool

2. Solid block with:

• Manual master valve.

• Actuated master valve.

• Swab valve.

• Studded outlet for wing valves.

3. Marine protection for all components.

3.2. Dual Completion

Typical ChristmasTree configuration.

3.2.1. Land And Off-Shore, Solid Block Splitted:

Components:

• Tubing Head Spool

• Tubing Head Adapter with two manual master valves.

• Solid block incorporating two actuated master valves and twoswab valves and two studded outlets for wing valves.

•••• For off-shore application equipment should have marineprotection

4. ACTUATORS Reference

4.1. Second master valve shall be equipped with a hydraulic gate valveactuator (SSV - Surface Safety Valve).

4.2. In hydraulically operated actuators, Back seat seal shall be provided.

4.3. Actuator shall be designed to be disconnected from the valve ‘online’.

4.4. Heat sensitive lock open device shall be installed during wire-line

operations.

4.5. Materials wetted by well fluid shall be conform to the valve materials.



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5. MATERIALS Reference

5.1. Material selection shall withstand the operating conditions. (WP,WT.and corrosive environment.

5.2. For corrosive environment, detailed material selection shall complywith wellcome user Manual 2.3

5.3. General service conditions are defined as:

Operating Temperature Range: -29oC to 82

oC as per API 6A

The steels which meet with this criteria are material standard (no sour service), class Dd as per API 6A as defined by NACE MR-01-75

P-1-M-6100 8.2.1

6. SEALS Reference

6.1. Seals selection is based on following criteria:

6.2. Metal-to-metal seals shall be used in the applications outlined in thefollowing sections.

P-1-M-7100 5.4.3

6.3. Metal-to-metal seals shall be used in the applications outlined in thefollowing sections.

The following criteria is applicable to the various conditions listed inthe following tables:

a) Between producing strings/casing/tubing hanger and tubing

hanger seal flange.

b) Between tubing hanger and tubing spool.

c) On production casing or production liner.

d) On control line connections.

These designations A, B, C and D will be used in the tables below.

P-1-M-7100 5.4.3



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Oil and Gas Producers

These tables apply equally to onshore and offshore wells.

Sweet Service Wells (with top hole temperature less than 100°C) [ ! = YES " = NO ]

Sealing WP, psi A B C D

5,000 ! " " !

10,000 ! ! " !

>10,000 ! ! " !

Sweet Service Wells (with top hole temperature exceeding 100°C)


5,000 ! ! " !

10,000 ! ! " !

>10,000 ! ! ! !

H2S Service Wells


5,000 ! " " !

10,000 ! ! " !

Gas Injectors


5,000 ! " " !

10,000 ! ! " !

Water Injectors


5,000 ! " " !

10,000 ! ! " !

Artif ic ial Li ft Wells (both onshore and offshore wells)


5,000 ! "(1) " !

10,000 ! ! " !

(1) If H2S is present it will be a YES.



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6.4. Tubing Head Spool, Casing Pack off:

• Metal-seal for christmas tree W.P. ≥ 15,000psi.• Elastomer seal with metal anti-extrusion ring for christmas treeW.P. =10,000psi.

• Elastomer seal for all other applications.

6.5. Control line transfers:

• Metal to Metal seals in all application.

6.6. Anchor screws and alignment screws ( if present ):

• Elastomer for class A.

• Thermoplastic seal with Metal back-up ring is requested for class-B and C.

7. TUBING HANGER Reference

7.1. Tubing Hanger for dual completion shall be solid block type.

7.2. Tubing Hanger shall have a preparation to accommodate a metal sealon the well bore.

7.3. Tubing Hanger shall have a preparation for one or more control line’smetal seal.

7.4. All metal seal shall be made to guarantee the sealing even inpresence of small misalignment between the connected components.

8. TUBING HEAD ADAPTER SEAL FLANGE Reference

8.1. T.H.A. shall have on bottom an integral counter bore to accommodatethe metal seals of Tubing Hanger and Control lines.

8.2. T.H.A. shall have a lateral outlet for Control Line connection.

8.3. Outlet connections for WP. ≥ 15,000 psi shall be “Autoclave” type.

Reference List :



‘Specification For Surface Wellhead and

Christmas Tree Standard Equipment’ STAP-M-1-SS-5701E



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PL. 3.16. WORKOVER AND COMPLETION PROGRAMME


1.1. The Completion programme will provide details of the operation andtake the form of a step by step instruction schedule.

1.2. This should be used in conjunction with the relevant AGIP manuals, API RP and specialist service company instructions.

2. PROGRAMME CONTENT Reference

2.1. Well history summary

2.1.1. For a new well this should include a description of the well, type of well and the purpose for which it will be used.

2.1.2. For a suspended well this should include description and date of lastoperation, details of any problem encountered, depths anddescription of barrier plugs and well fluids.

2.1.3. For a workover operation this should include well history since initialcompletion and detailed reasons for present workover operation.

2.2. Reservoir parameters

2.2.1. Fluid type

2.2.2. Bottom hole pressure

2.2.3. Bottom hole temperature

2.3. Well schematic

2.3.1.1. Casing data

2.3.1.2. Cement depth

2.3.1.3. DV, liner, tie-back data

2.3.1.4. Well path data

2.4. Production casing data

2.4.1. Size

2.4.2. Grade

2.4.3. Weight

2.4.4. Thread



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2.5. Annulus details

2.5.1. Actual pressure

2.5.2. Fluids

2.5.3. Maximum allowable pressure

2.6. Completion and Packer fluids

2.6.1. Type

2.6.2. Density

2.6.3. Storage volume

2.6.4. Filtration requirement

2.6.5. Corrosivity control

2.6.6. Displacement procedure

2.6.7. Spacer composition

2.6.8. Recovery / disposal

2.7. Bop stack

2.7.1. Size and pressure

2.7.2. Type of closure

2.7.3. Distance RT- closing rams

2.7.4. Kill and choke line data

2.8. Rig data

2.8.1. Dynamic load

2.8.2. Set back capacity

2.8.3. Mud pit capacity

2.8.4. Mud pumps pressure and rate



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2.9. Well Killing

2.9.1. Main steps of killing procedures following bulheading, circulating, Etuor lubrication method.

2.10. Packer unsetting and complet ion pul l out

2.10.1. Details on Packer unsetting operations

2.10.2. Max overpull allowable

2.10.2.1. Steps of operations and safety precautions to be followed whenpulling string out of hole.

2.10.2.2. Equipment end procedures to be followed in case of special alloy tbg,to avoid damage.

2.11. Pipe tool recovery

2.11.1. Packer milling tool characteristics

2.11.2. Details of BHA forecasted for milling operations

2.11.3. Steps and suggestions for milling operations

2.11.4. Planning of expected fishing operations.

2.12. Level abandoning

2.12.1. Purpose of level abandoning

2.12.2. Method of abandoning

2.12.3. Detailed steps, sequence of operations and equipment required

2.13. Well preparations

2.13.1. Casing cleaning, sequence of operations

2.13.2. Completion and/or packer fluid, general information handling and

filtration instructions.



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2.14. Well bore completion

2.14.1. Perforating:

• Instruction related to general operating procedures and safety

• Reference logs for correlation

• Gun size

• Charge type

• Shot density and phase

2.14.2. Sand control:

• Operating procedures

• Gravel packing equipment and accessory• Contractor detailed step procedure

2.15. Well completion

2.15.1. Completion schematics:

• Well head component assembly

• Down hole completion tools

2.15.2. Detailed descriptions of all components(tbg, safety valve, landingnipples injection valves, packers, christmas tree etc.) including the

main following data:

• Manufacturer

• Description

• Sketches

• Minimum I.D.

• Maximum O.D.

• Materials

• Running setting and testing procedures

2.16. Well clean up

2.16.1. Surface facilities lay out

2.16.2. Surface facilities pressure testing programme

2.16.3. Sampling instructions

2.16.4. Clean up procedures



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2.17. Special operat ion detai l

2.17.1. Hydraulic frac, job procedures

2.17.2. Stimulation job procedures

2.17.3. Coiled tubing job procedures

2.17.4. Wire line job procedures

2.17.5. Well testing job procedures

2.18. Safety instructions

2.18.1. General safety instructions

2.18.2. Barrier policy:

• Locations plugs

• Plugs type

• Testing procedures

2.19. Cost prevision

2.19.1. Budget split in class of cost



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SECTION 2 OF BP&MR - OPERATIONS (OP)

SECTION 2

OPERATIONS (OP)



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INDEX

OP1. MOVING AND POSITIONING 6

OP2. DRILLING OPERATIONS 7

OP. 2.1. CONDUCTOR PIPE 71. CONDUCTOR PIPE INSTALLATION 72. FLOATING RIGS 9

OP. 2.2. DIRECTIONAL DRILLING 12

1. SURVEYING POLICY 122. GENERAL SURVEYING REQUIREMENTS 123. CONSIDERATIONS FOR SURVEY TOOLS SELECTION 134. QUALITY CONTROL (QC) 145. ANTICOLLISION 166. WELL SITE PROCEDURES 19

OP. 2.3. TRIPPING AND STRING COMPOSITION 251. BEFORE TRIPPING 252. WHILE TRIPPING 263. STRING COMPOSITION 28

OP. 2.4. MUD SERVICES 311. OPERATIONS & MUD CHARACTERISTICS 31

OP. 2.5. OPEN HOLE LOGGING 331. GENERAL NOTES 332. WELL PREPARATION 333. LOG FISHING 344. SAFETY 34

OP. 2.6. CASING/LINER RUN 351. CASING 352. CORROSION RESISTANT ALLOY (CRA) CASING OPERATIONS 383. LINERS 43

OP. 2.7. CEMENTING 461. CASING CEMENTING 46

2. LINER 493. POST-CEMENTING OPERATIONS 504. SQUEEZING 50

OP. 2.8. WELLHEAD 521. BASE FLANGE 522. CASING SPOOL 533. MISCELLANEOUS 544. UNDERWATER WELL HEAD. 555. COMPACT WELLHEAD 576. MUDLINE SUSPENSION 57



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OP. 2.9. WELL CONTROL 59

1. PERSONNEL 592. RECORDING 593. PRIMARY CONTROL 604. SECONDARY CONTROL 615. KILLING PROCEDURE 626. STRIPPING PROCEDURES 627. EQUIPMENT REQUIREMENTS (LAND RIGS, JACK-UPS AND FIXED

PLATFORMS) 638. EQUIPMENT REQUIREMENTS (FLOATERS) 649. BOP CONTROL SYSTEM (LAND, JACK-UPS AND FIXED PLATFORMS) 6510. BOP CONTROL SYSTEM (FLOATERS) 6611. CHOKE MANIFOLD (ALL) 6712. INSIDE PIPE SHUT-OFF DEVICES 67

13. AUXILIARY CONTROL EQUIPMENT 6814. DIVERTER EQUIPMENT 6915. MISCELLANEOUS 7016. BOP AND RISER RUNNING (FLOATERS) 7117. BOP AND CASING TESTS 7118. BOP AND CASING TESTS (FLOATERS) 7419. DIVERTER TEST (BEFORE START OF OPERATIONS) 7620. FREQUENCY OF BOP TESTS 7621. DRILLS 7722. TIMING 8023. HORIZONTAL WELLS 80

OP. 2.10. LOT 82

1. GENERAL 822. STANDARD PROCEDURE 82

OP. 2.11. CORING 851. GENERAL GUIDELINES 85

OP. 2.12. DRILLING PROBLEMS (STUCK PIPE, FISHING, MUD LOSSES, SHALLOW

GAS, HANG OFF, H2S) 871. STUCK PIPE 872. OIL PILLS 903. ACID PILLS 914. FREE POINT LOCATION 925. BACK-OFF PROCEDURE 936. FISHING 95

7. MILLING PROCEDURE 988. JARRING PROCEDURE 989. LOST CIRCULATION 9910. SHALLOW GAS 10411. HANG-OFF 10812. H2S DRILLING PROCEDURES 110



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OP. 2.13. WELL ABANDONMENT 113

1. GENERAL INFORMATION 1132. TEMPORARY ABANDONMENT 1143. SAND PLUG 1154. CASING PATCH 1165. PERMANENT ABANDONMENT 116

OP3. COMPLETION AND WORKOVER OPERATIONS 122

OP. 3.1. GENERAL 1221. BOP STACK AND TESTING 1222. WELL CONTROL 1233. FLUID LOSS CONTROL 124

OP. 3.2. WELL PREPARATION 1261. CASING CLEANING 1262. COMPLETION AND PACKER FLUIDS 1263. BRINE 1274. CMT LOGGING 128

OP. 3.3. WELLBORE COMPLETION 1291. PERFORATING 1292. SAND CONTROL 1313. CASING MILLING 132

OP. 3.4. COMPLETION PULL OUT 1341. WELL KILLING 1342. PACKER UNSEATING AND COMPLETION PULLING 136

OP. 3.5. PIPE/TOOL RECOVERY 1381. PACKER MILLING 1382. FREE POINT 1393. BACK OFF 1394. TUBING PUNCHER 1405. TUBING CUTTER 1416. WASHING OVER 1417. FISHING 142

OP. 3.6. WELL COMPLETION 1441. TUBING/PACKER INSTALLATION PROCEDURE 1442. HYDRAULIC LINE INSTALLATION 146

3. ELECTRIC LINE INSTALLATION 1474. SUCKER ROD PUMP INSTALLATION 1475. ESP SYSTEM INSTALLATION 1486. WELL HEAD INSTALLATION AND TESTING 1497. PACKER(S) SETTING 150

OP. 3.7. STIMULATION 1511. MATRIX TREATMENT 1512. HYDRAULIC FRACTURING 152



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OP. 3.8. COILED TUBING OPERATIONS 154

1. RIG UP, TESTING AND DEPLOYMENT 1542. GAS LIFTING 1553. WELL CLEANING 1564. CEMENTING 1575. ACIDISATION 158

OP. 3.9. WELL TESTING 1591. GENERAL 1592. TESTING WITH DOWNHOLE TEST TOOLS 1603. WELL TESTING THROUGH A COMPLETION STRING 1604. SURFACE DATA ACQUISITION 160

OP. 3.10. WIRELINE OPERATIONS 1621. GENERAL 1622. SURFACE EQUIPMENT 1663. WIRE SELECTION 1704. TOOLSTRING SELECTION 1705. RIG UP/DOWN OPERATIONS 1736. NDT PROCEDURES 1837. SCSSV TEST PROCEDURES 189

OP4. MATERIALS AND TRANSPORT 190

OP. 4.1. WAREHOUSE MATERIALS 1901. GENERAL 1902. TUBULARS 190

3. OTHER MATERIALS 190

OP. 4.2. RIGSITE MATERIALS 1921. MINIMUM STOCKS 1922. TUBULARS 1923. MATERIAL CARE 1954. EXPLOSIVES 1955. RADIOACTIVE SOURCES 196

OP. 4.3. TRANSPORTATION 1991. PERSONNEL 1992. MATERIALS 200

OP. 4.4. CORROSION PREVENTION & INSPECTION 202

1. CORROSION PREVENTION 2022. NDT 202

OP5. WASTE TREATMENT AND DISPOSAL 205

OP. 5.1. GUIDELINE 2051. GENERAL 2052. ONSHORE 2063. OFFSHORE 206



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OP1. MOVING AND POSITIONING

This section is no longer deemed applicable to Eni-Agip’s operations in today’s oil and gasindustry as it not a core activity but is now provided by contractors specialised in rig movingand positioning.

This particular section, however, remains in the index so as not to disrupt the numbering of the remaining sections as this is familiar to users of the manual and the audit checklist. Thissection may be removed at a later date when an opportunity arises.



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OP2. DRILLING OPERATIONS

OP. 2.1. CONDUCTOR PIPE

1. CONDUCTOR PIPE INSTALLATION Reference

1.1. The outside diameter and the wall thickness of conductor pipeshould be chosen according to previous experiences in the areaand the selected casing profile.

P-1-M-6140 4.1

1.2. 30” OD x 1” wall thickness Fe42C has been selected as the Eni- Agip Division and Affiliate’s standard for world-wide explorationand development drilling activities, only if this CP is unsatisfactoryshould alternatives be considered.

P-1-M-6140 4.1

1.3. CP can be installed either by driving with a pile hammer or by pre-drilling a hole and cementing.

P-1-M-6140 4.1

1.4. Using Pile Hammers

1.4.1. The most common used system is the ‘Delmag - D44 or D46’which has a hammer weight of 18t with a variable delivery fuelpump, refer to table in P-1-M-6140 for the specifications of other types of Delmag Hammers.

P-1-M-6140 4.1.1

1.4.2. Conductor pipe joints installed on land rigs, are usually connectedby welding bevelled prepared ends of the pipes together.

P-1-M-6140 4.1.3

1.4.3. On a Jack-up, to reduce the time of the operations and when it ispracticable, driveable threaded quick connectors (i.e. the RL-4)and driveable squnch joint connectors such as the Fast ReleasingJoint (i.e. the ALT-2) should be used.

P-1-M-6140 4.1.3

1.4.4. When the driving depth of the conductor pipe is not specified in theDrilling Programme, the final depth of the driving is the ‘refusaldepth’.

Local experience could dictate a different refusal value. The drivingdepth can be pre-determined by conducting soil-boring analysis.

The refusal value generally used is 1,000-1,100 blows/metre.

P-1-M-6140 4.1.3



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1.4.5. The driving depth of the conductor pipe which is specified in theDrilling Programme is established with the following formula:

Hi = [df x (E+H) - 103 x H]/[1.03 - df + 0.67 x (GOVhi - 1.03)]where:

Hi = Minimum driving depth (m) from seabed

E = Elevation (m) distance from bell nipple and sealevel

H = Water depth (m)

df = Maximum mud weight (kg/l) to be used

GOVhi = integrated density of sediments (kg/dm3/10m)

If the refusal depth does not meet this value, internal washing may

be required. CP internal washing might be necessary several timesbefore reaching the planned depth.

P-1-M-6140 4.1.3

1.5. Drilling and Cementing CP

1.5.1. Run a 26" bit + float valve + 36" Hole Opener + 1 x 9" Monel DC +1 x 9" Spiral DC + 5" HWDP + 5" DPs down to the seabed andmeasure the water depth.

P-1-M-6140 4.1.5

1.5.2. Space out in order to avoid pulling the bit above the mud line at thefirst connection and drill to the depth of the first two joints using

high viscosity mud (80-120 seconds Funnel viscosity) and at a veryslow pump rate.

P-1-M-6140 4.1.5

1.5.3. Drill the remaining 36" hole down to the planned depth (with minWOB and at a higher pump rate) pumping seawater and a highviscosity mud cushion (at least 20-30 bbls every connection).Pump mud at a low flow rate if the well does not take fluid.

P-1-M-6140 4.1.5

1.5.4. At TD circulate the hole clean, displace the hole with gel mud (50%excess over open hole volume) and make a wiper trip to the seabed. Do not pull the bit above the mud line.

P-1-M-6140 4.1.5

1.5.5. Run back to bottom. If any fill is found, repeat the previous stepotherwise displace the hole with gel mud (100% excess over theoretical hole volume). Take a directional survey and pull the 26"bit + 36" HO.

P-1-M-6140 4.1.5

1.5.6. Run the 30" x 1" thick CP and cement it in the hole using an inner string and sealing adapter (refer to the Casing Running andCementing section).

P-1-M-6140 4.1.5



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1.5.7. Install two pad eyes on the CP just above the spider deck leveland anchor the conductor pipe with four slings to the rig

substructure, if required.

P-1-M-6140 4.1.5

1.5.8. Cut the 30" CP at the specified depth below rotary table accordingto the Drilling Programme and make up the diverter assembly.

P-1-M-6140 4.1.5

2. FLOATING RIGS Reference

2.1. Use of TGB

2.1.1. The following procedure is including TGB, but the most usefulprocedure for setting the CP is with PGB only.

2.1.2. To overcome problems encountered when installing the TGB invery soft seabed conditions, standard TGB should be modified withextended skirt and additional side plates.

2.2. Operational Sequence

2.2.1. Set TGB over moonpool, make up running tool on DP and engageTGB; make up guidelines and run TGB to seabed, checkingpenetration with ROV.

2.2.2. Put PGB (equipped with 2 slope indicators) in moonpool on skidbeams.

2.2.3. Make up drilling BHA; paint bit and HO white.

2.2.4. Make up Utility Guide Frame above HO and attach to guidelines.RIH with BHA to above TGB; space out before entering TGB suchthat bit will remain in hole when making the first connection.

2.2.5. Run TV camera/ROV to observe entry into TGB; record thedistance between RKB and seabed, air gap and water depth onDaily Drilling Report.

2.2.6. Drill hole to the planned depth, according to the CP length andplanning an adequate rat hole.

2.2.7. Use very low pump rate to minimise washouts and cratering.

2.2.8. Pump water and high viscosity mud pills at each connection.

2.2.9. At TD, circulate hole clean with water and fill with gel mudpumping, at least, 50% excess on theoretical volume.



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2.2.10. Check for hole verticality.

2.2.11. POOH (don’t pull above TGB) and wait, at least, 1hr; meanwhileretrieve survey tool and check for result: if inclination exceeds 1.5°move off the Unit, at least 10m, and restart drilling.

2.2.12. Run back to bottom. If any fill is found, ream or wash with water,displace hole with gel mud and go back to previous step, otherwisePOOH.

2.2.13. Skid PGB on spider beams under Rotary Table.

2.2.14. Run CP through PGB. Make up housing to the last joint.

2.2.15. Run 5” DP cement stinger inside CP to within 15m from the floatshoe.

2.2.16. Pick up the Running Tool from the derrick and make up to cementstinger and to the housing.

2.2.17. Lower the housing to moonpool and connect to PGB Pick up theentire assembly and skid back the spider beams. Lower theassembly to waterline. Fill the casing with water and close thevalve (or plug) on Running Tool.

2.2.18. Run CP on H.W., filling on each stand.Lower and land the PGB on the TGB.

If the TGB was run in a soft seabed, do not land PGB on TGB buthold the PGB approximately 1m above the TGB (with motioncompensator).

2.2.19. Check with TV/ROV the angle of PGB before cementing. If itexceeds 1.5°, POOH CP on the moonpool and move off the Unit atleast 10m and restart drilling.

2.2.20. Break circulation gradually using seawater and circulate minimum

amount to avoid washing out at seabed.

2.2.21. Cement CP as per cementing program, observing returns atseabed.

2.2.22. Displace cement with seawater, living approximately 5m of cementinside CP.



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2.2.23. Observe by TV the position of PGB; if PGB is stable, check for back flow and back off the running tool. If PGB is not stable or has

not been landed on the TGB, support the casing with the runningstring and wait on cement before releasing the running tool.

2.2.24. POOH cement stinger up to the Housing and wash the same withseawater, then POOH completely.

2.2.25. Run with jetting head and wash guideposts.

2.3. Pilot Hole

2.3.1. When drilling a pilot hole use the universal guide frame (UGF) ontop of the TGB to provide guidance and centralisation of the bitover the first 10-20m.

Additional centralises lugs may have to be welded on thecircumference of the guidance section of the UGF for this purpose.

Reference List :




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OP. 2.2. DIRECTIONAL DRILLING

1. SURVEYING POLICY Reference

1.1. All development wells will be surveyed from the wellhead to, atleast, the lowest hydrocarbon bearing zone.

P-1-M-6120 4.1

1.2. All exploration wells will be surveyed from the surface conductor shoe to TD.

P-1-M-6120 4.1

1.3. Surveying tool selection will be based on the anti-collisionrequirements, surveying equipment accuracy, target size anddepth.

P-1-M-6120 4.1

1.4. The basic surveying AGIP minimum requirements for vertical and

deviated wells are listed in Table OP 2.3 and Table OP 2.4

2. GENERAL SURVEYING REQUIREMENTS Reference

2.1. All magnetic surveys will have to be reported after being correctedfor magnetic declination. Magnetic declination must be specified

P-1-M-6120 4.4

2.2. For other surveys, ensure that magnetic declination is consideredwhile aligning.

P-1-M-6120 4.4

2.3. Gyro survey output does not need to be corrected for magneticdeclination.

P-1-M-6120 4.4

2.4. The depth of a survey is the survey instrument depth not the bitdepth. This applies to MWD and survey tools.

P-1-M-6120 4.4

2.5. Azimuth will be referenced to true North. P-1-M-6120 4.4

2.6. Bottom hole location will be extrapolated from the last survey. Thiswill normally not be more than 30m. To confirm the bottom holelocation the dipmeter can be used as it can survey down to around5m from TD if hole conditions allow.

P-1-M-6120 4.4

2.7. For drilling purposes ‘depth’ will always be quoted as drilled depthand not confused with wireline depth.

P-1-M-6120 4.4



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2.8. Approved Surveying Tools

2.8.1. Magnetic Survey Tool List

MSS Magnetic single shot (film)

MMS Magnetic multishot

EMS Electronic magnetic multishot

MWD Measurement while drilling

HD High resolution dipmeter

P-1-M-6120 4.2.9

2.8.2. Gyroscopic Survey Tool List

GSS Gyro single shot (film)

GMS Gyro multishot

SRG Surface reading gyro

NSG North seeking gyro (FINDER)

GCT Guidance continuous tool

FINDS Ferranti Inertial Navigation System

P-1-M-6120 4.2.10

2.9. Eni-Agip Division and Affiliates standard survey calculation methodwill be Minimum Radius of Curvature.

This method is considered the most accurate representation of well bore position, provided surveys are taken with the frequencydetailed in the surveying policy.

P-1-M-6120 4.4.3

2.10. The horizontal and vertical error of survey tools will be documentedfor future reference.

The specification is given in terms of a coefficient in m/1,000m.

The current values are given in Table OP 2.3 for horizontal andTable OP 2.4 for vertical wells

P-1-M-6120 4.4.4

3. CONSIDERATIONS FOR SURVEY TOOLS SELECTION Reference

3.1. Survey programme for vertical holes

3.1.1. TOTCO will be acceptable only on surface holes if inclination isless then 1.5°.

P-1-M-6120 4.7

3.1.2. MSS is the standard. MWD will be run as the survey tool of choice,if economically and technically justified.

P-1-M-6120 4.7

3.1.3. If MWD is used at the recommended frequency and the wellpath isclear of other wells, cased hole surveys may be omitted (if it is notdictated by local condition, legislation or third parties).

P-1-M-6120 4.7



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3.2. Survey Programme For Deviated Holes

3.2.1. TOTCO will be acceptable only on surface holes if inclination isless then 1.5°.

P-1-M-6120 4.8

3.2.2. MWD is the standard. MSS will be run as the survey tool of choice,if economically and technically justified.

P-1-M-6120 4.8

3.2.3. In cased holes GMS is the standard. The FINDS tool is the mostaccurate survey tool available. Platform planning is greatlyimproved by its use. If anti-collision is a critical concern theNSG/GCT or the FINDS will be used.

P-1-M-6120 4.8

3.2.4. GSS will not be run below 400m. P-1-M-6120 4.6.2

3.2.5. Magnetic based surveying instruments will not be used as theprime source of CW location calculation within 8m of any TW(centre to centre distance). A gyro based surveying tool will beused as the primary survey instrument until magnetically calculatedazimuths agree with the gyro tool.

P-1-M-6120 5.3.4

3.2.6. The accuracy of the surveying tool used on a well will be such thatthe total horizontal uncertainty at target depth is reasonable,compared to the target size. The smaller and the deeper thetarget, the more stringent the survey requirements.

P-1-M-6120 4.5.3

4. QUALITY CONTROL (QC) Reference

4.1. Magnetic Survey Tools (at Rig-site)

4.1.1. All magnetic tools will be run in non-magnetic BHA environments. P-1-M-6120 4.6.1

4.1.2. Magnetic azimuth values will be considered invalid when thesurvey instrument is within 8m of an adjacent casing shoe.

P-1-M-6120 4.6.1

4.1.3. Magnetic instruments must be run inside a sufficient length of NMDC.

P-1-M-6120 4.6.1

4.1.4. Non-magnetic stabilisers will be the only type permitted for usebetween NMDC's. Ferrous steel stabilisers are unacceptable.

P-1-M-6120 4.6.1

4.1.5. When magnetic influence is expected from adjacent casing (or when the well is separated less than 8m horizontally from anadjacent casing string), provision will be made to run a gyro basedsurvey tool on top of the MWD.

P-1-M-6120 4.6.1

4.1.6. Magnetic Single Shot shall be checked and tested, at surface,before running.



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4.1.7. Under particular operative conditions (high inclination angles, highMW, low tolerance), sinker bars should be used and the survey

barrel may need pumping down.

4.1.8. During tool running, reciprocate (if wire line) and rotate (if dropped)the string until a minute before shooting.

4.1.9. While running wire line survey, keep on top of string a Kelly Cockin open position (with thread protector on) and keep available aremote controlled hydraulic wire cutter on rig floor.

4.2. Gyroscopic Survey Tools (at Rig-site)

4.2.1. The landing slug will be checked to confirm seating on each run P-1-M-6120 4.6.2

4.2.2. Survey repeatability should be within 0.5° inclination and 2°azimuth (above 10° inclination).

P-1-M- 6120 4.6.1

4.2.3. Gyroscopic tools require accurate alignment of the instrument onthe foresight/reference azimuth.

P-1-M-6120 4.6.2

4.2.4. GSS will not be run below 400m. P-1-M-6120 4.6.2

4.2.5. GMS drift rate will not exceed 10°/hr. P-1-M-6120 4.6.2

4.3. MWD

4.3.1. A shallow depth functional test of the tool in the string will beperformed on each trip into the hole.

P-1-M-6120 4.6.1

4.3.2. A check survey will be taken immediately off bottom before startinga new bit run for comparison with the previous run.

P-1-M-6120 4.6.1

4.3.3. Repeat surveys at the same point and orientation must agreewithin 0.5° for inclination and 5.0° for azimuth.

P-1-M-6120 4.6.2

4.3.4. If MWD has been used at the recommended frequency as in Table

OP 2.1 and Table OP 2.2, the Gyro survey after casing set, maybe omitted (if not dictated by local condition, legislation or thirdparty).



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5. ANTICOLLISION Reference

5.1. Policy

5.1.1. All development wells will be surveyed from the wellhead to, atleast, the lowest hydrocarbon-bearing zone using the minimumguidelines specified in this section.

Anti-collision procedures will be implemented, in all cases where isa potential collision risk according to the policies outlined in thismanual.

P-1-M-6120 5.1

5.1.2. The prime reasons for specifying an anti-collision policy are to:

• Ensure a consistent method is used to evaluate and reduce

collision risks between wells.• Establish a common procedure for developing multi-well sites,

which takes into account actual well trajectory and trajectoriesof already existing wells.

• Establish a common procedure that discriminates betweeninterference from completed/producing wells andplugged/abandoned/uncompleted wells.

P-1-M-6120 5.1

5.1.3. The contractor’s software must be verified and then accepted byEni-Agip Division and Affiliates prior to the work commencing.

P-1-M-6120 3.4.1

5.1.4. The Anti-Collision Model currently used by Eni-Agip Division and

Affiliates is based on an Ellipsoid of Uncertainty concept whichdescribes the location of the well bore at any depth in terms of aprobability volume determined from the errors in the equipmentused to survey the well.

P-1-M-6120 5.2.1

5.1.5. The ROU is the radius of a sphere, at a specific vertical depth,which has the probability of containing the well path. It is acumulative calculation based on the product of the HorizontalUncertainty Factor of the survey instrument used to that point andthe surveyed depth to that point.

In field site calculations, the ROU will be increased by an amountdepending on the ‘Dogleg Potential’ along a projection from thelast survey point to a lower depth of interest (e.g. TD of the sectionor the expected closest approach to another well).

P-1-M-6120 5.2.2



PAGE 17 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


5.2. Anti-Collision Requirements

5.2.1. Software Capabilities

5.2.1.1. The software package should be available on rigsite to allow 'realtime' control by the rig personnel.

P-1-M-6120 5.3.1

5.2.2. Projection Technique (with Rotary Assemblies) P-1-M-6120 5.3.2

5.2.2.1. The projection will be made on CW accounting for the expectedclosest approach to the TWs. The trend observed in the finalsurveys of a rotary assembly will be used to establish the expectedtrajectories.

P-1-M-6120 5.3.2

5.2.3. Projection Technique (with Steerable Assemblies). P-1-M-6120 5.3.3

5.2.3.1. The projection will be made on CW accounting for the expectedclosest approach of the TWs. With Steerable assemblies, it will bepossible to assume a trend based on a maximum Dogleg Potentialof the assembly in a desired direction.

P-1-M-6120 5.3.3

5.3. Worst Case Projection Technique P-1-M-6120 5.3.4

5.3.1. In the worst case condition (e.g. when the projected dogleg isunknown or cannot be extrapolated for certain) an additionaluncertainty factor, due to the maximum Dogleg Potential of theassembly, will be added to the applicable ROU.

P-1-M-6120 5.3.4

5.4. Considerat ions In Planning A New Mul ti -Well Si te

5.4.1. Well to slot allocation should avoid crossing of well trajectorieswhenever possible.

P-1-M-6120 5.4

5.4.2. Spacing of wells for the surface vertical phases will not besubjected to SR < 1 limit, in case drilling is planned/performedfrom a multiwell site where all the surface phases have to bedrilled subsequently at one time.

P-1-M-6120 5.4

5.4.3. Anti-collision procedures will apply, for the surface vertical phase,in case drilling is planned/performed from a multiwell site whereproduction from adjacent wells is ongoing or during any productionwhile there is drilling activity.

P-1-M-6120 5.4

5.5. In ter ference with completed/producing wel ls and new wel ls P-1-M-6120 5.5.1

5.5.1. Proximity calculation and projection are done regularly at thewellsite while drilling the CW in order to confirm the CW positionwithin the zone X.

P-1-M-6120 5.5.1-c

5.5.2. While drilling within zone X to assure adequate quality andfrequency of the surveys, MWD will be used.

P-1-M-6120 5.5.1-c



PAGE 18 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


5.5.3. When the distance between TW and CW is projected to fall withinthe zone X, the Drilling Supervisor (rigsite) will be responsible toensure appropriate action is taken to shut-in TWs, before drilling

operations proceed.

P-1-M-6120 5.5.1-i

5.5.4. The Eni-Agip Division and Affiliate's SDE will confirm anti-collisioncalculations made at the rig-site on a survey by survey basis whenthe separation is inferior to the threshold of danger (i.e. be within

zone X).

P-1-M-6120 5.5.1-j

5.5.5. If the separation is projected to fall within zone Y during drillingoperations, drilling operations will be stopped.

Documented approval will be required from the DM for correctiveprocedures before drilling is allowed to proceed.

P-1-M-6120 5.5.1-k


P-1-M-6120 5.5.1-n

5.6. In ter ference between exis ting, non-completed/P&A wel ls and

new wells


P-1-M-6120 5.5.2-c

5.6.2. Proximity calculation and projection are conducted regularly at the

wellsite while drilling the CW in order to confirm the CW positionwithin the zone Y.

P-1-M-6120 5.5.2-d

5.6.3. While drilling within zone Y to assure adequate quality andfrequency of the surveys, MWD will be used.

P-1-M-6120 5.5.2-d

5.6.4. The Eni-Agip Division and Affiliates SDE will confirm anti-collisioncalculations made at the rig-site on a survey by survey basis whenthe separation is inferior to the threshold of alert (i.e. within zone

Y).

P-1-M-6120 5.5.2-f

5.6.5. If the separation is projected to fall within zone Z during drilling

operations, drilling will be stopped. Documented approval isrequired from the DM for corrective procedures before drilling isallowed to proceed.

P-1-M-6120 5.5.2-g

5.6.6. The DSR (rig-site) will be responsible for suspending drillingoperations immediately when the separation is projected to fallwithin zone Z.

P-1-M-6120 5.5.2-h



PAGE 19 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


5.7. Plugging of completed target wells

5.7.1. Any TW which separation is projected to be less than thethreshold of danger (i.e. within zone X) above the sub-surfacesafety valve (SSSV) depth less 30m, must have the SSSV closedand the well de-pressurised.

P-1-M-6120 5.6-a

5.7.2. Any TW which separation is projected to be less than thethreshold of danger (i.e. within zone X) below the SSSV depthless 30m compared to the planned CW, is to be plugged at least150m below the lowest depth in zone X for the TW.

P-1-M-6120 5.6-b

5.7.3. After installation of the plug, all TW pressures will be bled down to

zero, or circulated to the appropriate kill weight fluid before drillingcommences on the CW.

P-1-M-6120 5.6-c

5.7.4. Target wells will be only brought on line when the separation isgreater than the threshold of danger (i.e. outside zone X) andincreasing steadily.

P-1-M-6120 5.6-d

5.8. Suspension of Current Well

5.8.1. When the separation to any TW is projected to be less than theapplicable threshold, the Drilling Supervisor will be advised anddrilling of the CW will be stopped.

P-1-M-6120 5.7-a

5.8.2. Operations will only resume after the proposed corrective actionshave been approved by the DM.

P-1-M-6120 5.7-c

5.8.3. A well planned or drilled with separations less than the threshold

of separation (i.e. within zone Z) is unacceptable under anycircumstance.

P-1-M-6120 5.7-d

6. WELL SITE PROCEDURES Reference

6.1. Magnetic based surveying instruments will not be used as primesource of CW location calculation within 8m of any TW (centre tocentre distance).

P-1-M-6120 5.8

6.2. When magnetic influence is suspected, gyro surveys will be run tocheck the magnetic surveys until such time as the magnetic andgyro survey tool azimuths agree within 2° azimuth for at least twoor more consecutive surveys.

P-1-M-6120 5.8

6.3. When proximity is critical with a steerable assembly, the MWD willbe placed on top of mud motor to ensure the survey is as close aspossible to the bit.

P-1-M-6120 5.8

6.4. When there is any doubt about the accuracy of a magnetic basedsurvey it will be double-checked with a gyro-based tool beforedrilling ahead.

P-1-M-6120 5.8



PAGE 20 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


6.5. Proximity calculations will be done at regular intervals dependingon the risk of collision, but in any case, at least twice daily whiledrilling.

P-1-M-6120 5.8

6.6. Only the most experienced Directional Contractor personnel will beutilised when proximity situations are expected to be of concernduring drilling operations. If drilling conditions call for additionalpersonnel to cover 24hrs basis service, actions will beimplemented accordingly, agreed with the Contractor

P-1-M-6120 5.8.6

6.7. The following precautions will be observed when CWs are withinzone X or zone Y depending on the type of TW(producing/completed well or not completed/plugged & abandonedwell):

a) Proximity calculations and projections are to be performed on

each survey.

b) Mud returns, will be monitored regularly for the presence of cement or gas.

c) A ditch magnet will be installed on the flowline and monitoredregularly for abnormal presence of metal tailings.

d) Wherever practicable the annuli on TW's will be pressured upand monitored regularly for sudden changes in pressure.

e) The drilling operation will proceed at controlled ROP to reducethe potential for damage should a collision occur.

f) The drilling operation will proceed with due caution andparticular attention being paid to sudden changes in ROP,drilling torque or other irregularities.

g) The directional driller will be on the drill floor at all times tomonitor drilling parameters.

h) Unless required for directional control, the use of drillingmotors will be avoided while drilling in this situation. If motor use is unavoidable then a low torque motor will be thepreferred option.

i) Whenever possible use PDC bits instead of tricone bits.

j) The DS will ensure that the most experienced personnel will beassigned for the tasks outlined above (as recommended by theDrilling Contractor Supervisor). The DS will be notifiedimmediately when any indications of collision are suspected or observed.

k) A stock of 100m3 of drilling mud should be available for

emergency filling up.

l) Well control drills to be intensified.

P-1-M-6120 5.8

Reference List :

‘Directional Control & Surveying Procedures Manual’ STAP-P-1-M-6120



S E C T I ON

2 OF B P &

MR

- OP E RA T I ON S

( OP )

FREQUENCY AND TYPE OF SURVEYS Vert i


Type of instrument



Frequency

30” C.P. Tocto(template)

BottomGMS/SRG 30m

MSS

Tocto At shoe

20” -13”3/8

Surface CSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

13” 3/8

intermediateCSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30m

MWD

MSS150M

(and each trip)

9” 5/8 CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

7” CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

5” Liner MSS/MWD


NSG/GCT30m

MWD

MSS150M

(and each trip)


wells and good survey have been taken in open hole.2. If SDD ( Straight Drilling Device) is in use to keep the well in vertical condition, we can sup

and the others survey records should be omitted.

T a b l e OP 2 .1 -F r e q u en c y an d T y p e s of S ur v e y s f or V er t i c

al W el l s



S E C T I ON

2 OF B P &

MR

- OP E RA T I ON S

( OP )

FREQUENCY AND TYPE OF SURVEYS Devia


Type of instrument



Frequency

30” C.P. Tocto BottomGMS/SRG 30m

MSS

Tocto At shoe

20” -13”3/8

Surface CSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

13”3/8

intermediateCSG

MWD

MSS

30

150GMS/SRGNSG/GCT

30m

MWD

MSS150M

(and each trip)

9” 5/8 CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

7” CSG MWD

MSS

30

150GMS/SRGNSG/GCT

30mMWD

MSS150M

(and each trip)

5” Liner MSS/MWD


NSG/GCT30m

MWD

MSS150M

(and each trip)


wells and good survey have been taken in open hole.2. Records after casing set may be omitted if a cross-check with a second MWD tool or equiva

T a b l e OP 2 .2 -F r e q u en c y an d

T y p e s of S ur v e y s f or D ev i a t e d W el l s



PAGE 23 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


Tool Type Inclination RangeError

(M / 1,000M)0°/10° 4

10°/20° 7

GSS/SRG/MS 20°/30° 11

30°/45° 18

45°/60° 30

0°/20° 2

20°/30° 3.5

NSG/GCT 30°/45° 7.5

40°/60° 15.6

FINDS 0°/90° 0.5

0°/10° 9

10°/20° 13

MSS/MMS 20°/30° 20

30°/45° 45

45°/60° 55

60°/80° 60

0°/10° 210°/20° 2.2

EMS 20°/30° 2.6

30°/45° 3.5

45°/60° 4.4

60°/90° 5.2

0°/10° 2.6

10°/20° 3.3

MWD 20°/30° 4.3

30°/45° 6.3

45°/60° 8.5

60°/90° 10.5

Table OP 2.3 - Survey Tool Horizontal Uncertainty Factor



PAGE 24 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


Tool Type Inclination RangeError

(M / 1,000M)

Finds 0°/90° 0.5

0°/10° 2.5

10°/20° 3.7

Magnetic 20°/30° 5.5

30°/45° 10

45°/60° 15.3

60°/80° 17.3

0°/10° 2.2

10°/20° 2.7

Gyro 20°/30° 3.5

30°/45° 5.7

45°/60° 7.8

Table OP 2.4 - Survey Tools Vertical Uncertainty Factor



PAGE 25 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


OP. 2.3. TRIPPING AND STRING COMPOSITION

1. BEFORE TRIPPING Reference

1.1. The Company Drilling and Completion Supervisor shall be presenton the rig floor at the beginning of every trip to check for fill-up.

P-1-M-6140 7.1-1

1.2. Before the start of tripping out of the hole with drill pipe, thefollowing criteria must be followed, unless authorised by CompanyDrilling and Completion Manager/Drilling Superintendent:

• Bottoms up must be circulated.

• No loss of circulation must be recorded.

• No indication of on influx.

• The mud density going into and coming out of the hole shall

not differ more than 24g/l (0.2ppg).

P-1-M-6140 7.1-2

1.3. A flow check shall be taken at the following points:

• Immediately above off bottom.

• At the lowest casing shoe (regardless of the fill-up status).

P-1-M-6140 7.1-3

1.4. Prior to the start of tripping out, make sure that mud is conditionedin order to have the minimum gel strength value within the desiredvalues.

P-1-M-6140 7.1-4

1.5. A short trip shall be performed before tripping out of

overpressurised zones, unless advised otherwise by the CompanyDrilling Manager and/or Superintendent.

The following procedure shall be carried out for a short trip:

• Pull 5 to 10 stands at normal speed, making sure the hole istaking the proper amount of mud (no swabbing). Use the triptank accurately.

• Run back to bottom.

• Perform a flow check on the bottom.

• Circulate and check bottoms up.

• If an influx is detected, increase the mud weight as

necessary.

• A second short trip may be required.

P-1-M-6140 7.1-25

1.6. Prior to pulling out of hole, the drill pipe should be slugged with aheavy pill. The volume and density of the pill should be determinedby Company Drilling and Completion Supervisor based on thefollowing factors:

• Density of mud in the hole.

• Mud rheology.

• Capacity of the drill pipe.

• Hole depth

P-1-M06140 7.1-6



PAGE 26 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


1.7. As a general rule, it is preferable to pump a small volume pill of high density than a large volume pill of low density.

P-1-M-6140 7.1-6

1.8. Under the following circumstances, the use of slug pill should beavoided:

• Shallow hole.

• Possibility of damaging the reservoir with weighting agent.

When an increase in mud weight should be avoided in order toprevent mud losses and/or fracturing the formation.

P-1-M-6140 7.1-6

1.9. As a general rule, if the hole fails to take enough mud, run the drillstring to bottom and circulate bottoms up.

P-1-M-6140 7.1-10

1.10. A suitable safety valve, threaded (or with proper connections) to fiteach pipe connection included in the string, must be on the rigfloor, in the open position ready for use with proper fittings andhandling devices. The closing/opening wrench must be readilyavailable for immediate use.

P-1-M-6140 7.1-14

1.11. Before each trip, the rotary slips shall be inspected for worn or broken inserts and any replacements made. Replacement insertsshould be available on the rig at all times.

P-1-M-6140 7.1-5

1.12. Fill and make test on trip tank.

Always use the trip tank (in and out) and accurately recordvolumes to make sure the hole is taking/giving the proper amountof fluid. If any discrepancy is observed, the Driller shallimmediately inform the Tool Pusher and Company Drilling andCompletion Supervisor.

P-1-M-6140 7.1-9

2. WHILE TRIPPING Reference

2.1. A flow check shall be taken at the following points:

• Immediately above off bottom.

• At the lowest casing shoe (regardless of the fill-up status).

P-1-M-6140 7.1-3

2.2. The ‘Wiper rubber’ should be used when pulling or running the drillpipe to prevent any objects falling into the hole. Do not install thewiper rubber while tripping out the first 10 stands in order toobserve the fluid level

P-1-M-6140 7.1-7

2.3. Always use the trip tank (in and out) and accurately recordvolumes to make sure the hole is taking/giving the proper amountof fluid. If any discrepancy is observed, the Driller shallimmediately inform the Tool Pusher and Company Drilling andCompletion Supervisor.

P-1-M-6140 7.1-9



PAGE 27 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


2.4. The trip (or fill-up) sheet shall be filled in on the rig floor whiletripping. The Driller shall submit the trip sheet to the Company

Drilling and Completion Supervisor at the end of the trip or whenrequested.

P-1-M-6140 7.1-12

2.5. Any time a trip is interrupted, the hand tight installation of a safetyvalve is recommended.

P-1-M-6140 7.1.15

2.6. If possible, and if required by hole conditions, rotate the stringwhen tripping to prevent sticking while standing back pipe.

P-1-M-6140 7.1.17

2.7. Use ‘pipe spinner’ or ‘chain’ under the following(circumstances:

• Tripping out core barrel

• Caving problems are encountered

• Tripping out from thief zones

• Tripping out from ‘kick off’ zones (deviated holes, sidetrack,etc.).

• Handling BHA

• Pulling string with an expected washout.

• Pulling a broken string or fish.

P-1-M-6140 7.1-18

2.8. The standard break out technique should be adopted in order tohave all the tool joints in the drill string broken out and doped

alternatively.

P-1-M-6140 7.1-19

2.9. In case of drag when tripping out, do not exceed a reasonablevalue of overpull usually

1/3 of string weight. This value should be

adjusted to hole conditions, drill string design and stabilisation andhole profile (vertical, side track, directional). If necessary, work thepipe (i.e. rotate) and/or install a Kelly and circulate to pass throughthe tight spot.

P-1-M-6140 7.1-21

2.10. If drag is encountered when tripping in, install the Kelly andwash/ream the free zone. Never attempt to push the bit through aledge. No weight should be placed on the bit during reaming.

Torque, and sometimes pressure, are the only guide parametersto perform this operation. While reaming pay attention in order toavoid making a new hole

P-1-M-6140 7.1-22

2.11. Report, in details, depths and over pulls of troublesome zones on“IADC” and Company “Daily Drilling Report”.

P-1-M-6140 7.1-23

2.12. Torque all joints to the API recommended value. P-1-m-6140 7.1-24



PAGE 28 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


2.13. Gauge accurately the residual diameter of the bit and stabilisers inorder to plan a subsequent reaming operation or change the

drilling string design if a PDC or diamond bit is scheduled. It isrecommended to use a three-point gauge ring if available.

P-1-M-6140 7.1-26

2.14. The blind or shear rams must be closed every time tools are out of the hole.

P-1-M-6140 7.1-27

3. STRING COMPOSITION Reference

3.1. Preliminary

3.1.1. Each string component run in hole for the first time shall beappropriately drifted.

3.1.2. The string shall be drifted every time the use of a dart or a settingball is programmed.

3.1.3. A detailed sketch of every tool running in hole shall be prepared.

3.1.4. A BHA scheme, including the following data, shall be prepared andavailable on rig floor (see example in Table OP 2.5):

• Outside diameters

• Inside diameters

• Partial length

• Progressive length

• Serial numbers

• Partial weight

• Progressive weight

• Bit total flow area

• Position of TOTCO ring

3.1.5. BHA components without serial number and/or NDT report shallnot be run in hole.

3.1.6. As general rule, the number of drill collars must be calculated inorder to have neutral point at about

2/3 of the total drill collars

length.

Anyway drill pipes must never work in compression.

3.1.7. Verify that specific dope types are used for DC and DP threads.

3.1.8. Verify that correct make up torque for each connection is applied.

3.1.9. Verify that correct type of tongs are used for each DC diameter.

3.1.10. Periodically verify the exact calibration of the tong dynamometer.



PAGE 29 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


3.2. Stabilisers

3.2.1. Even new, stabilisers OD shall be verified with a three point

calliper.

3.2.2. Check for fishing neck proper length.

3.3. Drilling Jar

3.3.1. Drilling jar shall be positioned either in tension or in compression (if allowed by tool specifications).

Avoid running the drilling jar in correspondence of the neutralpoint.

When calculating the forces on the jar, pump extension force willbe considered.

M-1-M-5003 4.6.5M-1-M-5003 4.6.6

3.3.2. Every trip look for hydraulic oil leakage and replace jar if any.

3.3.3. Jar pre-setting value must be checked prior to run in hole, to verifyif the margin of overpull is sufficient to operate the jar.

3.3.4. After a certain amount of rotating hours drilling jar will be replaced.Never exceed the maximum rotating hours value (as toolspecification) before service the jar.

M-1-M-5003 4.3.6

3.3.5. Replace the jar as soon as possible after jarring or bumping hasbeen carried out.

M-1-M-5003 4.5.8

3.4. Shock absorber

3.4.1. Shock absorber (if used) must be positioned nearest the bitwithout interfere with packed hole assembly (above the thirdstabiliser).

Bit + NB + SHDC + STAB + 1 DC + STAB + Shock Tool +1 DC+STAB+.

3.4.2. With shock tool on surface apply torque with two tongs to verify the

tool torque transmission efficiency.

3.4.3. At every trip look for hydraulic oil leakage and/or excessive axialclearance and replace tool if any.

3.4.4. After a certain amount of rotating hour’s shock absorber will bereplaced. Never exceed the maximum rotating hours value (as toolspecification) before service the shock absorber.

Reference List :


‘Drilling Jar acceptance and Utilisation Procedures’ STAP-M-1-M-5003



PAGE 30 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


TypeSerial

number

OD

Inc

ID

Inc

Partial

length

mts

Total

length

mts

Partial

weight

Ton

Total

weight

Ton

Make-up

torque

Kgm

Notes

DP "S135"

DP"E75"

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

HWDP

X/O

DC

DCJAR

DC

X/O

DC

DC

DC

DC

DC

DC

STAB

DC

SHOCK T.

STAB

MONEL

STAB

SHDC

NB

BIT TFA:

Table OP 2.5 - BHA Scheme Example



PAGE 31 OF 206ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090


OP. 2.4. MUD SERVICES

1. OPERATIONS & MUD CHARACTERISTICS Reference

1.1. Mud characteristics

1.1.1. No variation from the mud programme is permitted withoutprevious discussion with and approval of the Company Shore BaseDrilling office.

P-1-M-6140 6.1-d

1.1.2. Mud weight and funnel viscosity shall be recorded at least every30mins at the flow line and suction pit.

P-1-M-6140 6.2

1.1.3. When circulating gas cut mud and/or bottoms up, the followingdata shall be recorded:

• Mud weight

• Salinity

• Maximum gas

• Pit level

• Interested volume

• Depth and time.

P-1-M-6140 6.2

1.1.4. The Mud Engineer shall check mud weight at the shakers anddownstream of the degasser continuously when circulating gas cutmud and/or bottoms up.

P-1-M-6140 6.2

1.1.5. Rheology shall be checked three times a day or more frequently if requested by Company Drilling and Completion Supervisor.

P-1-M-6140 6.2

1.1.6. Any addition of oil to the water base mud system shall bepreviously approved by Company Drilling Office.

P-1-M-6140 6.2

1.2. Safety Actions

1.2.1. The active mud pit level shall be monitored by the mud engineer or by the derrick man at least every 30 minutes.

P-1-M-6140 6.2

1.2.2. An automatic pit level device shall be installed and operational, atall times, on all mud pits and on the trip tank. A pit volume recorder shall be continuously working on the rig floor and on the MudLogging Unit.

P-1-M-6140 6.2

1.2.3. Gas detectors shall be operational at all times. P-1-M-6140 6.2

1.2.4. The degasser shall be used whenever gas presence in the mud isindicated by the gas detector.

P-1-M-6140 6.2



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1.2.5. If H2S is present safety precautions will be adopted as specified in(STAP-P-1-M-6150).

P-1-M-6140 6.2

1.2.6. On offshore rig a ventilation room that provides at least onecomplete air change cycle every two minutes will be installed in themud pit room.

P-1-M-6140 6.2

1.3. Oil-Base Mud

1.3.1. To avoid pollution, precautions shall be in place (drains from therig floor and shale shakers, cuttings treatment, etc.) in order toavoid environmental spillage.

P-1-M-6140 6.3-a

1.3.2. Well control is affected by the use of oil based mud as it cancreate hazards while handling drilling gas and gas kicks. Since agas influx may dissolve completely into the drilling fluid, smallinfluxes of gas are more difficult to detect. Gas expansion and pitgain do not occur as the influx is circulated toward the surface.Detection may be delayed until the influx is only a few hundred feetfrom the surface when the well suddenly starts to flow. Usuallythere is little time for the rig crew to react to divert the flow.

P-1-M-6140 6.3-g

1.3.3. The basic guidelines when drilling with oil based mud’s are thefollowing:

• When drilling or coring known gas formations, be aware of potential for gas break out and sudden unloading.

• When back on bottom after tripping with gas formationsexposed to the open hole, be alert to sudden unloading of thehole as bottoms up near surface.

• A suspected but not detected influx shall be circulated to apredetermined distance below the BOP stack (e.g., 500ft), theannular or upper pipe rams will then be closed and bottomsup circulated out through the choke, under control to themud/gas separator.

P-1-M-6140 6.3-j

Reference List :




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OP. 2.5. OPEN HOLE LOGGING


1.1. The Company Well site Geologist is responsible for log quality.The Company Drilling and Completion Supervisor still retain overallresponsibility particularly related to operating efficiency and safetyand shall support the Company Well Site Geologist to ensureoverall log quality.

P-1-M-6140 13.1.1-6

1.2. The Company Drilling and Completion Supervisors must be surethe Logging Engineer has dimensional drawings of all tools run inhole, has appropriate overshot for all tools and appropriatecrossovers are available on the rig floor for a possible fishingoperation of logging tools.

P-1-M-6140 13.1.1-10

1.3. The Logging Engineer shall immediately inform the CompanyDrilling and Completion Supervisor of any obstacle or difficultyencountered while running or pulling out of the hole.

P-1-M-6140 13.1.1-7

1.4. The weak point in the logging string shall be checked and changedregularly to avoid its premature breaking when running tools under normal hole conditions.

P-1-M-6140 13.1.1-9

1.5. During wireline operations, the mud level shall be continuouslymonitored with the trip tank, particularly, while pulling out loggingtools.

P-1-M-6140 13.1.1-4

2. WELL PREPARATION Reference

2.1. Prior to logging, the hole shall be circulated clean and the mudconditioned.

P-1-M-6140 13.1.1-1

2.2. Check that the mud samples have been collected, properlylabelled and given to the Logging Engineer for resistivitymeasurements.

P-1-M-6140 13.1.2-3

2.3. After logging and prior to running casing, a wiper trip shall becarried out to condition the hole.

P-1-M-6140 13.1.1-2

2.4. If there is a long logging period or before a RFT, an intermediatewiper trip shall be run if deemed necessary by the CompanyDrilling and Completion Supervisor.

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3. LOG FISHING Reference

3.1. The weak point in the logging string shall be checked and changedregularly.

P-1-M-6140 13.1.9

3.2. The normal procedure to attempt to free a stuck tool is to pulltension on the wire up to just below the breaking strain of the weakpoint, or as advised by the Logging Engineer

P-1-M-6140 13.1.6

3.3. The Company Drilling and Completion Supervisors must be surethe Logging Engineer has dimensional drawings of all tools run inhole, has appropriate overshot for all tools and appropriatecrossovers are available on the rig floor for a possible fishingoperation of logging tools.

P-1-M-6140 13.1.1.10

4. SAFETY Reference

4.1. Explosives sources P-1-M-6140 13.1.4

4.2. Radioactive sources P-1-M-6140 13.1.5

Reference List :

‘Drilling Procedures Manual‘ STAP-P-1-M-6140



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REVISION

STAP-P-1-M-6090


OP. 2.6. CASING/LINER RUN

1. CASING Reference

1.1. General Notes

1.1.1. The Company Drilling Engineer should be present on the rig,whenever possible, for the intermediate casing operations and toassist the Drilling Supervisor during critical phases, providingtechnical assistance.

P-1-M-6140 12.1.2

1.1.2. Whatever the diameter, all production casing connections musthave metal-to-metal seals.

1.2. Preparation

1.2.1. Casing shall be accurately measured and drifted. Each joint shallbe drifted with on API drift or a specially built drift in case of non-standard casing.

P-1-M-6140 12.1.2-2

1.2.2. The joints will be counted and each joint numbered. P-1-M-6140 12.1.2-3

1.2.3. The joints to be excluded from the string will be clearly marked. Aspecial mark for defective joints will be used and specified in themanifest for back loading.

P-1-M-6140 12.1.2-4

1.2.4. Crossover joint thread connections should be drifted and checked

for thickness and correct thread type.

P-1-M-6140 12.1.2-5

1.2.5. Threads should be cleaned with a high-pressure stream of water or an evaporating solvent such as Varsol, otherwise manuallycleaned on API connections.. Diesel left in the thread roots canprevent the thread compound from forming an effective seal.

P-1-M-6140 12.1.2-6

1.2.6. Casing shall be visually inspected to check hooks used in the boxand pin ends while handling did not damage it.

A-1-M-1000 3.5.2P-1-M-6140 12.1.2-7

1.2.7. Casing shall be accurately measured and drifted. Each joint shall

be drifted with on API drift or a specially built drift in case of non-standard casing.

P-1-M-6140 12.1.2-2

1.2.8. Ensure that the cement plugs are compatible with the insidediameter of the casing string.

P-1-M-6140 12.1.2-15

1.2.9. The float equipment and casing accessories will be inspected. P-1-M-6140 12.1.2-9

1.2.10. The joints between shoe and collar couplings should be looseotherwise spare couplings should be ordered to provide a meansof thread locking both sides of the couplings.

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1.2.11. Ensure that the cement plugs are compatible with the insidediameter of the casing string.

P-1-M-6140 12.1.2-15

1.2.12. Casing power tongs and associated equipment shall be visuallyinspected to ensure it is of proper size and condition.

P-1-M-6140 12.1.2-16

1.2.13. The drill line shall be cut and/or slipped prior to running casing,regardless of its condition.

P-1-M-6140 12.1.2-17

1.2.14. Links, elevators, hook assembly and draw work brakes shall beinspected by Magnaflux prior to running heavy strings.

P-1-M-6140 12.1.2-18

1.3. Preliminary Operations

1.3.1. After open hole log, a trip to bottom is recommended to conditionthe hole and mud. The Mud Engineer shall check and, if necessary, adjust the mud properties. Plastic viscosity, yieldstrength and weight shall be kept as low as possible.

P-1-M-6140 12.1.4-1

1.3.2. Retrieve the wear bushing. P-1-M-6140 12.1.4-5

1.3.3. Replace the upper pipe rams with the correct size of rams for thecasing to be run. A pressure test of the bonnet and rams sealsshall be performed when the pipe rams are changed

P-1-M-6140 12.1.4-4

1.3.4. Do not lay down the BHA unless unavoidable. Before running 7"casing, breakout BHA and 5" DP. While waiting on cement laydown the BHA and 5" DP.

P-1-M-6140 12.1.4-6

1.3.5. Calculate the maximum allowable overpull while running casing. P-1-M-6140 12.1.4-10

1.3.6. Check the length of elevator links several days in advance for fitness with equipment i.e. spider, circulating/cementing heads,circulating casing packer.

P-1-M-6140 12.1.4-13

1.3.7. Test the sealing adapter 30"-20" shoe for perfect fit. P-1-M-6140 12.1.4-17

1.3.8. Landing joints are to be inspected and selected to avoidinterference with wellhead. The coupling must be minimum a 2mfrom casing hanging point.

P-1-M-6140 12.1.4-11

1.3.9. Check casing clamp inside diameters to assure free passage of positive centralisers.

A-1-M-1000 6.6.1

1.3.10. Install centralisers as per the Drilling Programme when the casingis on the pipe rack, in order to avoid time wasting during casingrunning

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1.3.11. Check shoe and collar integrity. P-1-M-6140 12.1.4-16

1.3.12. Check subs, crossovers, stage collar, ECIP for correct threads,dimensions, etc.

P-1-M-6140 12.1.4-21

1.3.13. Visually inspect the casing internal surface on the pipe rack toensure that all joints are free from foreign matter.

P-1-M-6140 12.1.4-22

1.4. Running Procedures

1.4.1. A tested circulating sub, fitting the casing thread, equipped with aWECO connection, shall be readily available on rig floor at alltimes in open position and without thread protector.

P-1-M-6140 12.1.5-1

1.4.2. Use thread lock compound in all the connections on and below thefloat collar (or landing collar).

P-1-M-6140 12.1.5-4

1.4.3. Make-up torque must be in accordance with manufacturer’sspecification and corrected with the relative friction indices of thethread compound in use.

P-1-M-6140 12.1.5-8

1.4.4. After running 6 joints, make up the circulating head and test thefloat equipment pumping at the maximum displacement rate.Record pressure losses due to collar and shoe at various flowrates.

P-1-M-6140 12.1.5-6

1.4.5. Back-up tongs and make up joint analysers, including a torquelimitor, shall always be used when running metal-to-metal seals.

1.4.6. Rotary slips with safety clamp and side door elevator may be runto a weight equal to 60% of the rating for the elevators. Beyondsuch value, use slip power elevator and spider. Anyway slip power elevator and spider shall always be used when running casing inopen hole.

P-1-M-6140 12.1.5-9

1.4.7. The maximum casing running speed should be calculated for thewell specific mud properties and formation integrity. As a rule of

thumb, running speed should never exceed 0.6m/sec. (20sec/joint)inside casing and 0.3m/sec. (40sec/joint) in open hole

P-1-M-6140 12.1.5-11

1.4.8. While running the casing compare the actual string weight and pitlevel, with theoretical values previously plotted, in order to detectany possible abnormal condition.

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1.4.9. Intermediate circulation is generally not necessary, however it maybe advisable under the following circumstances:

• When the weight indicator shows excessive dragging or atendency to stick.

• When an excessive amount of mud cake, cuttings or shale isexpected.

• When it is anticipated that returns will be lost if excessivelyhigh pump pressure is required to break circulation at bottom.

• At the previous casing shoe.

P-1-M-6140 12.1.5-14

1.4.10. At the previous casing shoe depth fill up the string completely andcirculate the volume inside the casing. Check levels and start

circulation at a very low pump rate increasing gradually up to themaximum allowable displacement rate. Record the circulatingpressures at the various flow rates.

P-1-M-6140 12.1.5-19

1.4.11. With the casing at TD circulate the total hole volume, following theprocedure in step 1.4.10.

P-1-M-6140 12.1.5-17

2. CORROSION RESISTANT ALLOY (CRA) CASING OPERATIONS Reference

2.1. Preliminary Operations

2.1.1. Pre-job meetings for running CRA (Corrosion Resistant Alloys)must be held between the Eni-Agip Drilling Representative, theThread Inspector and the Casing Make up Supervisor to discussthe procedures and responsibilities of the operations and the makeup criteria

P-1-M-6140 12.2

2.1.2. Chrome tubulars are extremely susceptible to galling and to localcold working if improperly stressed or impacted during shippingand handling.

Excessive bending during lifting of single joints, or bundles of joints, can also cause unacceptable levels of stress to be imparted.

Improper handling can lead to an increase in hardness or change

in mechanical properties which may result in detrimental forms of corrosion such as sulphide stress corrosion cracking and unevencorrosion

P-1-M-7120 8.2

2.1.3. CRA casing should be set on racks to allow enough space for a360° revolution for cleaning and inspection.

P-1-M-6140 12.2.1-2

2.1.4. Ensure drift mandrels conform to API requirements or themanufacturer’s specification (Teflon drifts are recommended).

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2.1.5. Always have clean thread protectors on the connections whenmoving or handling pipe

P-1-M-6140 12.2.1-4

2.1.6. Ensure the accuracy of the torque/time/turn recorder when runningCRA casing

P-1-M-6140 12.2.1-6

2.1.7. Always use a stabbing guide to assure the connection is stabbedwith no thread or seal damage.

P-1-M-6140 12.2.1-7

2.1.8. Ensure that the correct sized and serviceable tubular safety clampis available for first few joints.

P-1-M-6140 12.2.1-8

2.1.9. Protect the areas CRA casing when is moved with wooden cover (‘V’ door, ramps, rack, etc.).

P-1-M-6140 12.2.1-9

2.1.10. Special CRC stop collars (without nails) are imperative for CRAcasing as well as ‘non marking jaws’ on the power tongs.

P-1-M-6140 12.2.1-11

2.2. Transportation

2.2.1. Chrome tubulars will be dispatched from the mill in specialtransport frames. These will be loaded into wooden crates for shipment. The tubulars will be covered by nylon sheets, andwrapped with Drilltec Econorap. The transport boxes are designedto prevent movement of, and contact between individual joints

during transportation. The wrapping will also minimise the risk of the tubing coming into contact with seawater during transportation.The transport frames will be removed from the wooden crates prior to shipment offshore.

A-1-M-1002 3.1.1P-1-M-7120 8.2.2

2.2.2. Proper thread protectors shall be in place during the transportation A-1-M-1002 3.1.3

2.3. Marine Transport P-1-M-7120 8.2.4

2.3.1. • The transport frames will be arranged on deck in order toprevent longitudinal movement.

• Protection, such as tyres or heavy rope, will be used toprotect the transport frames from other cargo.

• The transport frames will not be stacked more than threehigh.

• No other cargo will be placed on top of the transport frames.

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2.4. Road Transport

2.4.1. • The transport boxes will be properly loaded, and supportedalong their entire length.

• Chrome tubulars will not be removed from their transportframes until arrival on the installation.

• Security of the bolts on the transport frames will be checkedby a Company representative, or an approved designate,before lifting to ensure that the tubulars are secured, and soprevent movement of the tubulars within the transport frames.

• The transport frames will be secured using nylon straps.

• Any loose tubing should also be secured by nylon straps

P-1-M-7120 8.2.3

2.5. Handling at the well site

2.5.1. Chrome tubulars must not be allowed to contact other metallicmaterial, including supports and tubulars of the same material.

P-1-M-7120 8.2.5-1

2.5.2. Where metal impact or handling devices have inadvertently beenused the tubing joint will be set aside for further checking.

P-1-M-7120 8.2.5-3

2.5.3. Plastic supports will be used to support chrome tubulars andprevent rolling. Wood and rope are not recommended, as theytend to retain moisture, and may become contaminated with

chlorine or other chemicals harmful to chrome tubulars.

P-1-M-7120 8.2.5-5

2.5.4. The recommended stacking heights for various sizes of tubing are:

• 7” 29lbs/ft 6 rows

• 51/2” 17lbs/ft 8 rows

• 41/2” 12.6lbs/ft 9 rows.

A-1-M-1002 3.3.7P-1-M-7120 8.2.5-6

2.5.5. Chrome tubulars will have sufficient supports to accommodate theweight and number of pipe, and will be laid out with enough spacefor a full 360° revolution for cleaning and inspection purposes.

P-1-M-7120 8.2.5-7

2.5.6. The supports will be properly spaced to prevent bellying of thepipe, and so prevent water accumulation

P-1-M-7120 8.2.5-8

2.5.7. Plastic or Teflon drift must be used. Drifting cable must be coatedas well.

A-1-M-1002 3.4.1

2.5.8. If driftable open-ended protectors are provided then they will beinstalled (after cleaning as above), and the tubing drifted with theappropriate size drift.

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REVISION

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2.5.9. If closed end protectors are provided then they will be installedafter drifting the tubing

P-1-M-7120 8.2.5-11

2.5.10. The tubing will be drifted from end to end using a nylock drift to API spec. The drift dimensions will be as per (API RP 5A5):

• 7" 29lbs/ft 6.059" (153.9 mm)

• 51/2 " 17lbs/ft 4.767" (121.1 mm)

• 41/2" 12.6lbs/ft 3.833" (97.3 mm).

P-1-M-7120 8.2.5-12

2.5.11. The use of water steam cleaner is recommended for threadcleaning.

A-1-M-1002 3.4.2

2.5.12. As each row is laid out the thread protectors will be removed andcleaned and the threads cleaned and inspected by an approvedthread inspector, i.e.:

• Clean the threads using a steam jet.

• Do not use oil-based solvents and wire brushes.

• Dry the threads with compressed air.

• Apply a thin coating of Molycote to the clean threads.

P-1-M-7120 8.2.5-9

A-1-M-1002 3.4.2

2.5.13. If a joint is rejected for any reason, i.e. fails to drift, or if thethreads are damaged, the joint will identified with red paint. It willthen be repackaged and sent back onshore. A report detailing the

reason for rejection will be sent to the Workover Superintendent inthe Company office.

P-1-M-7120 8.2.5-15

2.5.14. The tubing will be measured from the end of the coupling to the pinthreads by the designated Company Representative and the entirelength corrected for make up loss. For shouldered connectionsmeasure the length from box end to the shoulder on the pin.

P-1-M-7120 8.2.5-16

2.5.15. Record the joint number as per stencilled description. Themeasurements will be recorded on the tubing tally form.

P-1-M-7120 8.2.5-17

2.6. Running

2.6.1. Before running any chrome tubulars, a pre-job meeting will be heldwith all relevant personnel, i.e. drill crew, tong operators, deckcrew, crane operator, etc. to ensure that they are aware of their responsibilities.

P-1-M-7120 8.2.7

2.6.2. Padding material will be fitted to the ‘V’ door and catwalk areas toprevent damage to the tubulars.

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2.6.3. The power tongs will be fitted with the correct size non-markingdies.

P-1-M-7120 8.2.7-2

2.6.4. Single joint and side door elevators will be fitted with non-metallicinserts.

P-1-M-7120 8.2.7-3

2.6.5. Confirm that the torque turn analyser has been correctly set-up. P-1-M-7120 8.2.7-4

2.6.6. Pick up lines to the single joint elevators will be arranged to allowthe joint to be stabbed to hang vertically over the hole, so that noundue pull will be exerted on one side during make up

P-1-M-7120 8.2.7-5

2.6.7. The tubulars will be transferred to the catwalk with threadprotectors installed. Nylon slings wrapped around the joints will beused for lifting purposes.

P-1-M-7120 8.2.7-6

2.6.8. Use single joint pick up elevators for handling tubulars onto the drillfloor.

P-1-M-7120 8.2.7-7

2.6.9. Tubing slips will be dressed with low stress dies. P-1-M-7120 8.2.7-8

2.6.10. Care will be taken when setting pipe in the slips to prevent shockloading and impact damage.

P-1-M-7120 8.2.7-9

2.6.11. After removing the thread protector the threads will be cleaned and

inspected (if not already done on the pipe deck).

P-1-M-7120 8.2.7-10

2.6.12. Any joints with damaged threads will be laid out, and clearlyidentified

P-1-M-7120 8.2.7-11

2.6.13. The elevator must be placed on the pipe only after the joint ismade-up.

P-1-M-6140 12.2.2-2

2.6.14. A safety clamp will be securely placed around the joint located inthe slips to prevent slippage (‘X’ line or flush coupling).

P-1-M-6140 12.2.2-3

2.6.15. A non-metallic (i.e. plastic) stabbing guide will be used to guide the

pin correctly into the box.

P-1-M-7120 8.2.7-13

2.6.16. The joint will be lowered slowly into the stabbing guide to allow theman on the stabbing board, and the man on the rig floor to guidethe pin into the stabbing guide. Throughout the stabbing operationthe pipe should be kept as vertical as possible.

P-1-M-7120 8.2.7-14

2.6.17. If the stabbing operation was unsuccessful both pin and boxthreads will be inspected for damage. If the box was damagedconsideration will be given to replacing it. If the pin was damagedthe joint will be laid out.

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2.6.18. After successfully stabbing the pipe the first four or f ive turns of themake up will be done by hand using a nylon strap wrench.

P-1-M-7120 8.2.7-16

2.6.19. The last turns will be made using a torque turn unit with a graphicaltorque turn analyser to confirm the correct make up value.

P-1-M-7120 8.2.7-17

2.6.20. The make up speed should be between 3 to 10rpm. Final make upshould be at 5RPM.

P-1-M-7120 8.2.7-18

2.6.21. The running speed will be limited to a maximum of 14 joints per hour.

P-1-M-7120 8.2.7-19

2.6.22. Handle one joint at a time with a crane for racking. If it is possiblea pick-up machine must be used to lift the pipe into the ‘V’ door.The travelling basket shall be internally coated.

A-1-M-1002 4.1.1

2.6.23. Protect CRA casing moving areas with wooden cover. A-1-M-1002 4.1.2

2.6.24. Do not use lift hooks to pick-up CRA pipe. The joints should belifted to the ‘V’ door by nylon slings.

P-1-M-6140 12.2.2-1 A-1-M-1002 4.1.3

2.6.25. Keep thread protectors on the Pin and Box until stabbing to avoidloose scale or debris interfering with the make-up.

P-1-M-6140 12.2.2-4 A-1-M-1002 4.2.1

2.6.26. Stabbing guide must be used A-1-M-1002 4.2.2

2.6.27. The use of single joint compensator is recommended as anadditional aid to stabbing.

A-1-M-1002 4.2.3

2.6.28. The make-up equipment shall consist of:

• Power tong with back-up

• A-Q torque

• JAM

A-1-M-1002 4.3.1

2.6.29. It is suggestible to start by hand the make up for CRA tubing’s or small size casing (5”-7”)

A-1-M-1002 4.3.4

2.6.30. All unused joint must be returned to the Base Shore properlycleaned, doped and with protector fully made-up.

A-1-M-1002 3.5.1

3. LINERS Reference

3.1. Preliminary

3.1.1. Check aluminium ball seat receptacle is compatible with droppingball.

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3.1.2. Check that the liner hanger slips operate properly and areundamaged prior to running in the hole (mechanical type).

P-1-M-6140 12.7.2-2

3.1.3. Make sure that the distance between casing plug top receptacleand running tool stinger is less then the length of drill pipe pumpdown plug.

A-1-M-1000 6.4.1.6

3.1.4. According to the liner hanger design being used, check the proper distance between setting tool stinger and casing plug receptaclefor the correct latch-in plugs

P-1-M-6140 12.7.2-3

3.1.5. Use long running tool polished stinger (3 m) for inclined or deepliners

For heavy liner or high angle wells, use a long stinger and packing(>3m) and packer extension sleeve (>6m).

P-1-M-6140 12.7.2-12 A-1-M-1000 6.4.1.8

3.1.6. Under normal conditions, the liner will be hung with a 100 to 150moverlap into the previous casing. If a smaller overlap is necessarydue to a particular situation, it shall never be less than 50m

P-1-M-6140 12.7.1-3

3.1.7. If the rat hole exceeds the overlap, set a cement/sand plug at adistance from the liner shoe setting depth shorter than the overlapitself.

P-1-M-6140 12.7.1-4

3.1.8. Drift the drill pipe and check the ID of all tools, subs, crossovers,

pup joints of the running string to ensure passage of the drill pipepump down plug and for dropping ball for hydraulic liner hanger.

P-1-M-6140 12.7.1-6

3.1.9. Visually inspect all tools and equipment for damaged components,dents etc. Record the shear pressure of all shear pins.

P-1-M-6140 12.7.1-7

3.1.10. The liner hanger OD and packer extension sleeve shall bechecked and the length measured.

P-1-M-6140 12.7.1-8

3.1.11. With a liner hanger assembly with a double plug cementingsystem, ensure the appropriate cementing head with dual drill pipedarts is used.

P-1-M-6140 12.7.1-10

3.2. Running & setting

3.2.1. Perform a circulating test at the liner hanger top to assure sealingof the packing elements (‘O’ ring or ‘V’ chevron).

P-1-M-6140 12.7.2-4

3.2.2. Under no circumstance shal l rotat ion be al lowed to the

running string; use a back-up tong for connection make-up, andlock the rotary table (mechanical type).

P-1-M-6140 12.7.2-5



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3.2.3. At every circulation before hanger setting keep circulating pressureat max. 80% of hanger slips setting value (hydraulic type).

P-1-M-6140 12.7.2-6

3.2.4. Record the exact liner and DP string weights including drag (hookload down and up) to calculate the exact neutral point for thesetting tool release (10-15t bearing).

P-1-M-6140 12.7.2-7

3.2.5. When the liner setting depth is reached, start reciprocating slowly.Break circulation pumping very slowly (100-300lpm), then increasethe flow rate to the desired value (observe for pressure surges toavoid formation fracture) and condition the mud as per theprogramme.

P-1-M-6140 12.7.2-8

3.2.6. Remove the Kelly, drop the setting ball, install the cementing headwith the swivel (drill pipe dart plug inserted) and indicating flag.Prepare the rig floor by-pass manifold with double lines and valvesfor direct and reverse circulations.

P-1-M-6140 12.7.2-9

3.2.7. After mud and hole conditioning, set the hanger following theprocedures provided by the manufacturer. If circulation time isgreater than 60min, set the hydraulic hanger before completing thecirculation and with bottom’s up above the liner head (minimumcirculating volume before dropping setting ball is the DP pluscasing capacity).

P-1-M-6140 12.7.2-10

3.2.8. Release the setting tool and pick up circa 3ft (1m) to ensure that ithas released (never pull the stinger out of the packing or dogsabove the packer's extension sleeve).

P-1-M-6140 12.7.2-11

3.2.9. For heavy liner or high angle wells, use a long stinger and packing(>3m) and packer extension sleeve (>6m).

P-1-M-6140 12.7.2-12

Reference List :


‘Casing Handling & Running Procedures’ STAP-A-1-M-1000

‘Best Practices for Handling & Running of CRA Casing’ STAP-A-1-M-1002



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REVISION

STAP-P-1-M-6090


OP. 2.7. CEMENTING

1. CASING CEMENTING Reference

1.1. General notes

1.1.1. Verify the mud pumps volumetric efficiency to ascertain thepractical value of litres/stroke during displacement.

P-1-M-6140 12.1.2

1.1.2. Cementing head shall have a minimum of two inlets with ballvalves. The pressure testing of the valves shall be performedbefore the installation of the cementing head on top of casingstring.

1.1.3. Check the cementing lines and connect the cementing manifold to

the rig mud pumps. All lines of the cementing manifold shall beflushed with water and pressure tested to 5,000psi prior tocementing.

P-1-M-6140 12.3.1

1.1.4. Record all operations on pressure recorder.

Record all mixing, displacing and bumping operations on apressure recorder.

P-1-M-6140 12.3.1-29

1.1.5. Production casing:

• The slurry must be homogeneous

• A batch-mixer will be used

1.1.6. Thickening time must be known before starting with a cement job.

1.1.7. A mixing tank must be used when chemicals are employed.

1.1.8. Carefully check the quantity of chemicals mixed in water.

1.1.9. The use of non-rotating PDC drillable plugs are recommended toenable further drilling phases.

P-1-M-6140 12.3.1-8

1.1.10. In advance to cement job, collect water and cement samples to

assure that the chemical characteristic are the same of thesamples used for pilot test.

P-1-M-6140 12.3.1-9

1.1.11. Mix the cement to the required slurry weight and have the weightchecked regularly. A pressurised mud balance is recommended inorder to reduce any air entering the system to a negligible volume.The use of this tool provides advantages:

• A fluid density value that is virtually the same as that under actual downhole conditions.

• The correct water/cement ratio. It must be noted thatchanging the W/C ratio, means the amount of additives in the

slurry also change.

P-1-M-6140 12.3.1-10



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1.1.12. When mixing cement, samples of slurry shall be collected innumbered containers, taken at the start, middle and end of eachtype of slurry.

P-1-M-6140 12.3.1-11

1.1.13. Also take water, mixing water samples and one sample of drycement from each tank used.

P-1-M-6140 12.3.1.11

1.1.14. Circa three minutes of contact time. The use of other particular spacers, related to mud weight and system in use, will bespecified, in the drilling programme (contact time, compatibility withcement slurry, etc.).

P-1-M-6140 12.3.1-6

1.1.15. Displace the cement with mud at the maximum permissible rateand surface pressure, unless otherwise stated in the CementingProgramme.

P-1-M-6140 12.3.1-17

1.1.16. Stop displacement in the event the pressure exceeds 70% of casing burst pressure or 5,000 psi

P-1-M-6140 12.3.1-20

1.1.17. Reduce the flow rate at the end of operation to avoid any suddenpressure surge when bumping the plug.

P-1-M-6140 12.3.1-21

1.1.18. Bump the plug, pressure up to conduct the casing pressure test.Release the pressure gradually as soon as possible to avoid themicro annulus effect.

P-1-M-6140 12.3.1-22

1.1.19. The bumping pressure values are always given in the Drilling

Programme.

P-1-M-6140 12.3.1-23

1.1.20. Should the plug not bump, never over displace more than half theshoe truck volume (between collar and shoe).

P-1-M-6140 12.3.1-24

1.1.21. Check for back flow to ascertain if the float equipment is holding. P-1-M-6140 12.3.1-25

1.1.22. If the float equipment fails, shut-in the well by closing standpipemanifold a period at least long enough for thickening. Monitor thepressure gauge so that required pressure can be maintained bybleeding excessive pressure periodically.

P-1-M-6140 12.3.1-26

1.1.23. In this case, the pressure remaining must not exceed the observeddifferential pressure between the mud and cement.

P-1-M-6140 12.3.1-27

1.2. Mudline Suspension

1.2.1. Cementing surface casing with inner string

1.2.1.1. Run all the 20" casing in the hole and stab on the landing ring. P-1-M-6140 12.4.1-1

1.2.1.2. Run the inner string into the casing down to the shoe. P-1-M-6140 12.4.1-2



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1.2.1.3. Run the two 23/8" tubing strings into the 20”-30” annulus. Tag the

landing ring and wash out with seawater. At the same time, makeup the cementing line and fill-up the 20" casing 5" DPs annulus

with seawater. Break circulation and check if the stinger ‘O’ ringsare sealed.

P-1-M-6140 12.4.1-3

1.2.1.4. Pressure test the cementing line and cement the 20" casing as per the Cementing Programme.

P-1-M-6140 12.4.1-4

1.2.1.5. When contaminated mud is being circulated out, start washing withsea water through the 2

3/8" tubing and continue the cementing job

or the displacing through the inner string

P-1-M-6140 12.4.1-5

1.2.1.6. Once the cementing job is complete, check for back-flow from theinner string and pull out of hole.

P-1-M-6140 12.4.1-6

1.2.1.7. Pull the 23/8" tubing strings and rig-up the 20" circulating head. P-1-M-6140 12.4.1-7

1.2.1.8. At the end of the cement job start washing with seawater throughtubing strings.

1.2.2. Cementing casing with plugs

1.2.2.1. Disconnect the cementing line at the rig floor, keeping thecementing head connected to the running string.

P-1-M-6140 12.4.2-2

1.2.2.2. To assure that there is no cement in the annulus above therunning tool, follow the procedure listed below for hangersequipped with wash ports.

• Record the hook load to support the weight of the runningstring. Adjust the tension to the free point (neutral at thehanger threads).

• Rotate the running string to open the wash ports in thehanger.

• Reconnect the cementing line to the cementing head andcirculate out all excess slurry. Continue until the annulus isclean.

• Disconnect the cementing line.

P-1-M-6140 12.4.2-3

1.2.2.3. Rotate the running string, in the opposite direction, measuring thedownward movement of the running string.

P-1-M-6140 12.4.2-4

1.2.2.4. Energise the seal. Reconnect the cementing line and pressure testthe casing and running tool

P-1-M-6140 12.4.2-5



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2. LINER Reference

2.1. Excess cement slurry will be 20% of the dual caliper data volumein open hole based on slurry return at the top of the liner.

P-1-M-6140 12.7.3-1

2.2. The slurry must be batch-mixed. P-1-M-6140 12.7.3-1

2.3. Design a proper and compatible spacer to separate the drillingmud from the cement slurry (for 150m of annulus with balancedweight spacer possibly with 8-10 minutes contact's time).

P-1-M-6140 12.7.3-2

2.4. Displace cement with cementing unit (shallow liners). Use rigpumps for deep liners.

P-1-M-6140 12.7.3-3

2.5. If no shear of wiper plug is observed, do not bump the plug: usetheoretical displacement volume only.

P-1-M-6140 12.7.3-4

2.6. Reduce the pump rate to 300-400l/min, 1-2 m3 before the

expected bump plug. Once the theoretical volume has beendisplaced, if the plug does not bump, overdisplace a maximum 2/3

of the shoe track volume (between the landing collar and the floatshoe).

P-1-M-6140 12.7.3-5

2.7. Bump the plug with 500-1,000psi above the final displacementpressure. However, the bumping plug value will be stated in theDrilling Programme.

P-1-M-6140 12.7.3-5

2.8. Bleed off the pressure very slowly and check for back flow. P-1-M-6140 12.7.3-7

2.9. Pressurise approx. 300psi in order to check the correct sting out.Pick up the setting tool and circulate at least twice the annuluscapacity while moving the string.

P-1-M-6140 12.7.3-8

2.10. Pull the setting tool. P-1-M-6140 12.7.3-9

2.11. Once theoretical volume has been displaced, if plug does notbump, overdisplace maximum

2/3 of the shoe truck volume.



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3. POST-CEMENTING OPERATIONS Reference

3.1. If mechanical problems (lost circulation, etc.) are experiencedduring the cementing job, or any doubt arises about cementingresults a temperature survey or CBL/CET shall be run in order toverify the cement job quality.

P-1-M-6140 12.5.1

3.2. After WOC proceed as follows:

• Disconnect the kill and choke lines.

• Disconnect the flange required to set the slips.

• Raise and hang off the BOP stack.

• Set the casing on the slips with the desired tension (Refer tothe Drilling Programme), making sure that the slips are

properly set.• Cut and retrieve the casing.

• Nipple up the new casing spool.

P-1-M-6140 12.5.2

3.3. Perform WOC applying 200psi pressure in the annulus (whenapplicable).

3.4. If after WOC the annulus level is not visible fill up and make a flowcheck before to resume operations.

3.5. When drilling out a liner hanger, cement and floating equipment,

with a stage tool, the following precautions shall be taken:• While drilling cement inside the casing, do not exceed 50rpm

and 2-5t WOB.

• While drilling the underlying formation and until the stabilisersare out of the casing shoe, do not exceed 50-70rpm and keeplow weight and torque on bit.

P-1-M-6140 12.5.4

3.6. Drill out DV collar, run bit down to shut-off plug and perform DVcasing test at previous casing test pressure.

P-1-M-6140 12.5.5

4. SQUEEZING Reference

4.1. Set a Cement Retainer (CR) using wireline whenever possible at 5to 10m above the perforations. Correlate the CCL and GR to avoidsetting the CR across a collar or perforations.

P-1-M-6140 12.6.1

4.2. Run the setting tool on drill pipe, apply 10 ton weight on the CRand try to circulate testing the CR and the rubber seals (‘O’ rings)by pressurising up on the annulus

P-1-M-6140 12.6.2



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4.3. Pick-up the stinger and test the surface lines from cementing unitto cementing head at 5,000psi.

P-1-M-6140 12.6.2

4.4. Pick-up the stinger and mix and pump the slurry. The slurry designdepends on the feeding test results. In front and after the slurry,pump a cushion of treated water or spacer.

P-1-M-6140 12.6.4

4.5. During squeeze do not exceed fracture pressure.

4.6. Apply a moderate squeeze pressure taking into consideration theincreased hydrostatic effect of the cement column.

P-1-M-6140 12.6.8

4.7. Gradually increase downhole pressure to 500-1,000psi above thepressure required to initiate the flow calculated with a residualcement column.

P-1-M-6140 12.6.9

4.8. The pressure reaches a high value, help the stinger seals byapplying pressure on the annulus.

• Pick-up the stinger and reverse circulate out the excesscement. Record the volume fluid taken back.

P-1-M-6140 12.6.11

4.9. During squeeze do not exceed casing collapse pressure.

Reference List :




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STAP-P-1-M-6090


OP. 2.8. WELLHEAD

1. BASE FLANGE Reference

1.1. Welding Procedure P-1-M-6140 15.2.1

1.1.1. Cut the casing at about 200-400mm from cellar deck using a guideframe to ensure the cut is horizontal.

P-1-M-6140 15.2.1-5

1.1.2. Install the base flange, checking it is horizontal and that the lateraloutlets are aligned according to the Company Drilling andCompletion Supervisor’ s requirements.

P-1-M-6140 15.2.1-7

1.1.3. Perform internal welding first, then external. P-1-M-6140 15.2.1-11

1.1.4. Once started, welding should be finished without interruption. Slowcooling should be carried out by using appropriate insulatingsystems.

P-1-M-6140 15.2.1-14

1.1.5. Pressure test the welding after complete cooling of the baseflange.

P-1-M-6140 15.2.1-15

1.2. Safety

1.3. During the time of operation to prepare and carry out the weldingof the base flange, it is absolutely forbidden to work on the drillingfloor or in proximity of the wellhead.

P-1-M-6140 15.2.2-a

1.4. Make sure that the welder has efficient ground and safety switchesconforming to CEI standards or other international/localregulations.

P-1-M-6140 15.2.2-b

1.5. The welder and his assistant must wear protective clothing. P-1-M-6140 15.2.2-c

1.6. The welder must never be left by himself. P-1-M-6140 15.2.2-d

1.7. The work area must be protected from any falling objects. For thisreason a protective system with scaffolding must be built in order

to guarantee safety during the base flange welding operations.

P-1-M-6140 15.2.2-e

1.8. Pressure Testing

1.8.1. Pressure testing must be carried out using hydraulic oil after cooling of the braden head. Temperature must be less than 50°C.

P-1-M-6140 15.2.3-a

1.8.2. For pressure value of the test welding follow the drillingprogramme. In any case never exceed 70% of casing collapsepressure.

P-1-M-6140 15.2.3-a

1.8.3. Re-install test port3/4” NPT plug. P-1-M-6140 15.2.3-c



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2. CASING SPOOL Reference

2.1. Slip InstallationP-1-M-6140 15.2.4

2.1.1. All slips, packing elements and ring joints and their seats shouldbe thoroughly cleaned and lubricated.

P-1-M-6140 15.2.4-1

2.1.2. Clean and inspect the ID of the base flange, polishing out anyburrs or scratches.

P-1-M-6140 15.2.4-5

2.1.3. Lower the slips into the base flange bowl until they shoulder on thecasing spool, checking the correct alignment of the slip segmentsand the correct position.

P-1-M-6140 15.2.4-8

2.1.4. Be sure that the correct tension is applied to the casing string

(hang off load).

P-1-M-6140 15.2.4-4

P-1-M-6100 4.15.5

2.1.5. The casing tension shall be slowly released.

Slippage between slip and casing must not be allowed.

P-1-M-6140 15.2.4-9

2.1.6. One spare set of casing slips shall be available on rig site.

2.2. Primary And Secondary Packing Installat ion P-1-M-6140 15.2.6

2.2.1. Install the first primary support. Place the primary support over thecasing with the bevelled side up. Lower the packing support until itshoulders on the body counterbore.

P-1-M-6140 15.2.6-2

2.2.2. Install the primary packing by:

• Clean and oil the casing and packing thoroughly.

• Fit one side of the packing lip over the casing.

• Insert a clean welding rod (with the flux removed) or screwdriver between the ID of the base flange and the OD of thepacking. This will facilitate installation of the primary packing.

P-1-M-6140 15.2.6-3

2.2.3. Install the secondary packing by:

• Thoroughly grease the packing and fit one side of the packing

lip over the casing.

• Install the packing with a hammer as in step (4).

• Drive the packing down until it contacts the first secondarysupport.

• Install the second secondary support by placing thesecondary support over the casing with bevel facing down.Lower support until it contacts the secondary packing.

P-1-M-6140 15.2.6-8

2.2.4. Use new slips, packing and ring joints every time.



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2.2.5. The flange stud bolts must be tightened with the requested torqueusing a torque wrench.

Use of a ‘hydraulic stud tensioning system’ is preferable to reducemake-up time of flanges.

2.2.6. One spare set of rubber elements shall be available on rig site.

2.2.7. A check of the tightening torque of the stud bolts must be doneduring drilling and after each BOP test.

2.3. Primary And Secondary Packing Group Test

2.3.1. Test packing group with hydraulic oil as follows

2.3.1.1. Install the test equipment. P-1-M-6140 15.3.5-2

2.3.1.2. During the seal test the annulus space valve of the previous casingmust be kept open with the 2” LP plug disassembled, as a leak inthe primary packing group could put the annulus space under pressure.

P-1-M-6140 15.3.5.4

2.3.1.3. Upon completion of the test, bleed off all pressure and unscrewthe relief needle valve so as to avoid it breaking during the BOPstack movement.

P-1-M-6140 15.3.5-5

2.3.1.4. Test the BOP with a cup tester. The needle valve must be

replaced in its relative test port with the needle completely open.

The annulus space valve of the previous casing must be also keptopen.

P-1-M-6140 15.3.5-6

2.3.2. For test pressure value, see drilling program. In any case do notexceed 70% of casing collapse pressure.

P-1-M-6140 15.3.5-3

2.3.3. For all test pressure shall be kept for at least 15 minutes. P-1-M-6140 15.3.5-3

3. MISCELLANEOUS Reference

3.1. Lateral outlets of base flange and casing spools should beoriented according to Company requirements (interference withother wellheads, etc.).

3.2. Annulus pressure must be checked weekly and recorded on thedrilling report. Keep a record of the fluids pumped into or discharged from the well.

3.3. In offshore installations use stainless ring joints, cadmium-platedstuds and bolts and sea fog protected spools.



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4. UNDERWATER WELL HEAD. Reference

4.1. Wellhead datum

4.1.1. Water depth and seabed consistency must be checked running ametallic plate (90mm x 90mm) with HW and DP.

4.1.2. Record water depth, air gap, wellhead datum and RKB/seabeddistance on the drilling report.

4.1.3. Water depth is the distance between the seabed and Lowest Astronomical Tide (LAT)

Calculate the drill floor to seabed distance and LAT after taggingthe seabed with the TGB, taking into account the drilling draughtand tidal variation.

4.1.4. On installation of the BOP on the subsea wellhead, a BOPspaceout scheme shall be filled up, giving depths and dimensionalreferences.

4.2. Temporary Guide Base

4.2.1. Using the result of the soil test, determine the condition of theseabed and whether the TGB should be run.

Use of a TGB is inadvisable in presence of seabed inconsistencyor excessive slope.

4.2.2. Install a slope indicator on the TGB. If the angle exceeds 5°, resetthe TGB or avoid use.

4.2.3. Insert a bumper sub in the TGB running string.

4.2.4. Tension up and mark the guidelines at spider deck level beforedrilling out commences. This ensures that any sinking or tilting,during later drilling operation may be detected.

4.2.5. Observe setting the TGB on the seabed with SSTV or ROV.

4.3. Permanent Guide Base

4.3.1. Install two slope indicators on the PGB.

Check parallel alignment and verticality of posts.

4.3.2. Before cementing, check angle of PGB. If it shows more than 1.5°,pull the PGB at the moonpool and move rig.

4.3.3. During cementing job keep PGB at least 2m from seabed.



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4.3.4. Ensure that a spare ‘O’ ring for each type of housing running toolin use is kept onboard.

4.4. 183/4 housing

4.4.1. Before running, check the gasket sealing areas.

4.4.2. Run the 18”3/4 housing with the seat protector installed.

4.4.3. Spare ‘O’ rings must be available on board for :

• Squnch joint

• Seat protector

• Housing running tool

• BOP testing tool.

4.5. Hangers

4.5.1. One spare hanger for each diameter in use must be availableonboard.

4.5.2. When not otherwise specified, remove the lock down rings (wildcatwells).

4.5.3. Have a spare hanger running tool ‘O’ ring onboard.

4.6. Pack Off

4.6.1. One spare pack-off for each diameter in use must be available onboard.

4.6.2. Pack-off shall be pressure tested, step by step, with water,checking accurately the pressuring volume, to 70% of BOPworking pressure.

4.6.3. Spare ‘O’ rings must be available on board for :

• Pack-off running/testing tool• Retrieving/reinstallation pack-off tool

• Wear bushing

• Connector ring gasket.



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5. COMPACT WELLHEAD Reference

5.1. Cut all conductor pipes of the platform at the same level in order touse the same landing string.

P-1-M-6140 15.4.1

5.2. Prior to running the wellhead, remove all lateral studs (if present)avoiding damage during handling operations.

P-1-M-6140 15.4.3

5.3. Before running casing, wash the hanger seat (use the appropriatewashing tool if available).

P-1-M-6140 15.4.6

5.4. Wash inside the wellhead after each cementing job. P-1-M-6140 15.4.7

5.5. An emergency slip suspension system (as back up) must be

onboard.

P-1-M-6140 15.4.8

5.6. Spare ‘O’ rings and seals must be held onboard. P-1-M-6140 15.4.8

6. MUDLINE SUSPENSION Reference

6.1. A driveable Remote Releasable Connection may be installed onthe landing joint, which avoids sending divers to the sea floor torelease the connector for abandonment.

P-1-M-6140 15.5.1-1

6.2. The 30” landing ring depth will be checked, after running the 30”CP, using a special 26” skirted bit. Ensure tools are adjusted to the

ID of the mudline landing ring.

P-1-M-6140 15.5.1-2

6.3. Check part numbers, condition, dimensions, general compatibilitywith of the tools and equipment the casing and well requirements,tested and in good serviceable condition.

P-1-M-6140 15.5.1-3

6.4. A complete back-up set of seals and ‘O’ rings, adequate casingpup joints are needed to space-out the running tools and must beavailable onboard.

P-1-M-6140 15.5.1-3

6.5. All running tools or tieback tools should be assembled to therespective hangers to confirm that there is no damage due toprevious use or improper handling.

P-1-M-6140 15.5.1-4

6.6. Ensure all seals and ‘O’ rings are removed from therunning/tieback tools before making them up. Running tools shouldthen be removed and new seals fitted.

P-1-M-6140 15.5.1-4

6.7. The threads should then be lubricated and protected by storing inthe proper handling case.

P-1-M-6140 15.5.1-4



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6.8. Before running the casing it is recommended that the mudlinecasing hanger and the running tool be made up to the casing joints

or casing pup joint, and laid out on the pipe rack. Alternatively theymay be joined together and racked back in the derrick.

P-1-M-6140 15.5.1-5

6.9. Before making up the running tool to the mudline casing hanger,reconfirm that both seal and ‘O’ rings are intact and undamaged.Thread and seal areas should be greased following themanufacturer’s requirements (avoid the use of pipe or threadcompound).

P-1-M-6140 15.5.1-5

6.10. Ensure that the hanger is correctly and fully made up to therunning tool.

P-1-M-6140 15.5.1-5

6.11.The casing landing string should be spaced with the wellhead toensure that any couplings are to be a min of 2m away from thecasing hanging point. Casing pup joints will be used, if necessary.

P-1-M-6140 15.5.1-6

6.12. Pull the bit to the mudline suspension point and wash with themaximum flow rate possible at the casing hanger suspensionpoint.

P-1-M-6140 15.5.1-8

6.13. If available, the proper hanger landing profile clean-out tool shouldbe used. This tool ensures the full cleaning of the landing profile.

P-1-M-6140 15.5.1-8

6.14. Operation of mudline equipment must be strictly conducted as per

manufacturer’s instructions.

P-1-M-6140 15.5.1-10

6.15. Flushing the annulus through the mudline washing ports isessential.

P-1-M-6140 15.5.1-11

6.16. Close attention should be paid to casing string rotation, torque andvertical movement of the casing string to ensure that the correctmeasurements are achieved, and the operations are performedproperly.

P-1-M-6140 15.5.1-12

6.17. Measurement of the mudline position (hanger land-off point andtop of casing hanger) must be recorded on the well report for

landing subsequent casing strings and for future corrosioncap/tieback operations.

P-1-M-6140 15.5.1-14

6.18. Verify the integrity of the casing by pressure testing after theclosure of washout ports

P-1-M-6140 15.5.1-15

Reference List :




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OP. 2.9. WELL CONTROL

1. PERSONNEL Reference

1.1. It is required that each member of crew should be familiar withevery item of equipment used in well control. The minimumpersonal knowledge and capabilities required for a crew member to be considered competent is:

• To have sufficient knowledge of all the equipment in order tobe able to determine when operating functions are notworking properly, and consequently, take all necessaryremedial actions to re-instate full functionality.

• To have sufficient knowledge of operating procedures inorder to be able to react in due time, understanding

completely what is occurring.• To be able to correctly interpret the various abnormal

situations and take the appropriate remedial steps of action.

• Carry out basic calculations, and use the results in order tosafely manage any occurrences.

P-1-M-6150 1.3

1.2. Key personnel1 such shall have the fundamental theoretical

knowledge on kick and blow-out control techniques and also hold acurrent Well Control Certificate issued by an accredited industrytraining institute recognised by Governmental bodies and theCompany.

P-1-M-6150 1.3

1.3. Any ‘underbalance’ drilling operation, which is normally notauthorised on wildcat, shall be approved by the Company Drillingand Completion Manager through a well-detailed drillingprogramme or by written instruction.

P-1-M-6150 2.1.1

2. RECORDING Reference

2.1. All BOP tests, drills, function tests, any malfunctions, repair or maintenance to the mud system and well control equipment shallbe recorded in the IADC daily reports and shall be signed by boththe Drilling Contractor's Tool pusher and Company's Drilling andCompletion Supervisor on the well site. They shall also be

recorded in the Eni-Agip ‘Daily Drilling Report’.

P-1-M-6150 7.1.1-a

1 As Key personnel is intended: Rig Manager Tool Pusher, Tour Pusher, Driller, Assistant Driller, Company Supervisor, Mud Logger



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3. PRIMARY CONTROL Reference

3.1. Primary well control is at first achieved by the implementation of aproperly prepared drilling programme, based on pore pressurepredictions, (refer to the Overpressure Evaluation Manual). Thisinformation should allow the proposed well targets to be reached,protecting personnel, rig equipment and Company assets.

P-1-M-6150 2.1.1

3.2. It is the responsibility of the Drilling Contractor to keep the hole fullat all times by using all the available equipment. The Drilling andCompletion Supervisor shall monitor that the correct preventivepractices are being implemented and/or conducted at all times.

Extreme care shall be taken to monitor mud volume, drilling breaksand gas cut mud.

P-1-M-6150 2.1.3

3.3. For each phase of drilling, the MAASP value depends on thefollowing factors:

• Mud weight.

• Minimum formation fracture gradient below the shoe.

• Minimum casing burst resistance of the last casing string.

P-1-M-6150 2.1.4

3.4. The MAASP shall be defined by the Company's Wellsite Drillingand Completion Supervisor, either after setting each new casingstring or, whenever the density of the drilling mud changes.

3.5. The MAASP shall be clearly written on a Kick Control sheet thatwill be posted near the choke control panel.

P-1-M-6150 2.1.4

3.6. The predetermined distance at which the Kelly is to be pulledabove the rotary should be posted on rig floor near the BOPcontrol panel.

P-1-M-6150 3

3.7. The Driller is responsible for carefully measuring and recording theRPSP. The normal circulation flowrate shall be reducedapproximately to 1/3 in 121/4" and larger hole sections and 1/2 in 81/2"hole sections. Awareness of these values is an important elementin killing operations, in order to avoid formation breakdown.

P-1-M-6150 2.1.5

3.8. Is a best practice measure and record the RPSP at three differentflow rates, with all pumps.

3.9. RPSP must be taken at the following times as a minimum:

• Once per tour, or every 300m (1,000ft) intervals.

• Whenever changes occur in the mud density/rheology.

• Whenever changes occur in the dimension andcharacteristics of the string, i.e. change in BHA, jet size, jetplugged or jet lost, etc.

P-1-M-6150 2.1.5



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3.10. On floating rigs, the RPSP shall be measured by circulating, firstthrough the riser and then through the choke/kill line.

P-1-M-6150 2.1.5

3.11. If circulating through the choke manifold, the adjustable chokemust be completely open.

P-1-M-6150 2.1.5

3.12. On wells in deep water, at least two or more reduced circulatingrates, pressures and corresponding choke line pressure lossesshould be recorded plus the pressure losses through both linesused in parallel.

P-1-M-6150 2.1.5

3.13. The RPSP pressures must be measured on the choke controlpanel gauge or on the gauge, which would be used during wellcontrol operations and recorded on the IADC report.

P-1-M-6150 2.1.5

4. SECONDARY CONTROL Reference

4.1. Any time a drilling break is noticed, drilling shall stop (ensure nomore than 1.5m or 5ft is applied into the break) and a staticmonitoring of the well shall be carried out.

P-1-M-6150 2.1.3

4.2. Space-out must be known to the Driller at all times to keep tool joints clear of bag preventer and rams.

P-1-M-6150 4.2.2

4.3. If while tripping out a swabbing is noticed but the well is notflowing:

• Stop tripping

• Run back to bottom• Circulate bottoms up

• Resume tripping with extreme care.

P-1-M-6150 2.2.3

4.4. If while tripping out, a swabbing is noticed and the well is flowing:

• Stop tripping.

• Install on drill pipe the lower Kelly cock available on rig floor and close the same.

• Close in the well with bag type preventer.

• Install the inside blow-out preventer (i.e. Gray valve) and

open the lower Kelly cock.• Strip down in hole as much pipe as safely possible following

the stripping procedures as per P1M071-7.3.2.4 / P1M603313.3.2.4.

• Install Kelly and go through the killing procedure.

P-1-M-6150 2.2.3



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4.5. Top Drive operations

4.5.1. In case of kick during a trip with flow from drill pipe (in 95/8” casingor greater):

• Bring the tool joint near rotary table.

• Connect TDS.

• Close the lower inside BOP (standard equipment on TDS).

• Break down connection between lower and upper IBOP.

• Install a 65/8“ Reg box 4

1/2” IF box crossover on top of lower

IBOP.

• Install Gray valve.

• Open lower IBOP.

• Proceed with normal stripping procedures.

P-1-M-6150 3.1.2

4.5.2. During tripping with 31/2” DP in 7” casing, the normally installed73/8” OD lower BOP and the 73/4” - 8” OD crossover do not allowstripping operations, due to their large ODs. In this case avoidmaking-up the top drive at first.

P-1-M-6150 3.1.2

5. KILLING PROCEDURE Reference

5.1. Eni-Agip always require the use of the soft close-in procedureinstead of hard/fast close-in procedures.

P-1-M-6150 3

5.2. The proper method for treating the kick shall be selected by theCompany representative (Wellsite Drilling and CompletionSupervisor and/or Company Drilling and Completion Manager).

5.3. All methods to be used to bring the well under control are basedon the ‘Constant Bottom Hole Pressure’ concept, as recommendedby API-RP 59 ‘Recommended Practices for Well ControlOperations’.

P-1-M-6150 5.1

5.3.1. Other permitted well control methods, depending on particular situations, are the ‘Wait and Weight’, ‘Driller’s Method’ and the‘Volumetric Method’.

P-1-M-6150 5.1

5.3.2. Bullheading may also be considered when the other preferredkilling methods are not applicable.

P-1-M-6150 5.1

6. STRIPPING PROCEDURES Reference

6.1. Off bottom kicks P-1-M-6150 4.1

6.1.1. Whenever practicable and safe, the bit should be stripped back tobottom to allow implementation of the most effective and practicalkilling method.

P-1-M-6150 4.1

6.1.2. If the well is flowing, under no circumstances will the pipe be run in

the hole unless stripping-in is implemented.

P-1-M-6150 4.1



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6.2. If conditions require stripping using ram preventers, the lower ramsshall not be used but kept in reserve.

P-1-M-6150 4.2

6.3. Stripping through annular preventers P-1-M-6150 4.2.1

6.3.1. To prevent premature damage to the rubber element whilestripping, the closing hydraulic pressure should be reduced to theminimum possible.

P-1-M-6150 4.2.2

6.3.2. Stripping through ram preventers should only be considered when;the surface pressure is greater than the stripping pressure of theannular preventer, or if this pressure cannot be reduced to withinsafe annular working limits.

P-1-M-6150 4.2.2

6.4. Bag-to-Ram stripping is preferred to Ram-to-Ram, unless surface

pressures are such that the annular cannot operate safely.

P-1-M-6150 4.2.2

6.5. Taking the above into consideration, Ram-to-Ram stripping is onlyallowed with a three pipe ram BOP configuration. A two-pipe ramBOP configuration can only allow Bag-to-Ram stripping.

P-1-M-6150 4.2.2

6.6. Stripping through bag preventer should be avoided if the pressureexceeds 70 kg/cm2.

P-1-M-6150 4.2.

7. EQUIPMENT REQUIREMENTS (LAND RIGS, JACK-UPS AND FIXED

PLATFORMS)

Reference

7.1. Equipment must be as specified in ‘Guidelines for inspection or

acceptance tests of Drilling Units’.

7.2. Where H2S is expected and when on wildcat wells, equipmentmust be for H2S service.

7.3. On land rigs the installation of shear rams instead of the blindrams must be evaluated with reference to local laws or to a 'Riskanalysis' performed by Eni-Agip headquarters.

M-1-M-5005 1.1

7.4. • Up to 5,000 psi WP BOP stacks should have at least 2 ramtype preventers (1 pipe ram + 1 blind/shear ram) and 1 bagtype preventer.

• 10,000 psi stacks should have at least 3 ram type preventers(2 pipe rams + 1 blind/shear ram) and 1 bag type preventer.

• 15,000 psi stacks should have at least 4 ram type preventers(3 pipe rams + 1 blind/shear ram) and 1 bag type preventer

P-1-M-6150 6.1.1

7.5. The minimum distance between the shear rams and hang-off piperams shall be 80cm (30”).

M-1-M-5005 2.1P-1-M-6150 6.1.1-c

7.6. All preventers shall be equipped with lock system device.



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7.7. A set of pipe rams must be always installed below the hang-off pipe rams.

M-1-M-5005 2.1

7.8. The choke line configuration must allow circulating through thesheared drill pipe.

P-1-M-6150 6.1.1-j

7.9. Each choke and kill line BOP outlet shall be equipped with two fullbore valves, the outer valve of which will be hydraulically operated(preferably fail-safe closed).

P-1-M-6150 6.1.1-f

7.10. Minimum diameter of choke line should be 3” ID. P-1-M-6150 6.1.1-g

7.11. Minimum diameter of kill line should be 2” ID. P-1-M-6150 6.1.1-g

7.12. For onshore rigs with 10,000 psi or more pressure equipment,flexible choke and kill lines are not acceptable.

M-1-SS-5703 9.14

7.13. In any case articulated choke lines (chiksan) are not acceptable. M-1-SS-5703 9.15

7.14. Spare parts for BOP and valves must be available on rig site.

8. EQUIPMENT REQUIREMENTS (FLOATERS) Reference

8.1. 10,000psi WP stack systems should have 4 ram type preventers(3 pipe rams + 1 blind/shear ram) and 1 or preferably 2 x 5,000psibag type preventers.

P-1-M-6150 6.1.2-a

8.2. 15,000psi WP stack systems should have 4 ram type preventers(3 pipe rams + 1 blind/shear ram) and 2 x 10,000psi bag typepreventers.

P-1-M-6150 6.1.2-a

8.3. The upper hydraulic connector, located between the BOP stackand the Lower Marine Riser Package, shall have a pressure ratingequal or exceeding the WP of the bag preventers.

P-1-M-6150 6.1.2-b

8.4. All ram preventers shall be equipped with ram locks.

8.5. At least one ram preventer below the blind/shear rams shall beequipped with pipe rams to fit the drill pipe in use.

P-1-M-6150 6.1.2-d

8.6. Each choke and kill BOP outlet should be equipped with two fail-safe remotely controlled gate valves.

P-1-M-6150 6.1.2-e

8.7. Avoid choke and kill line outlets below the lower pipe rams, whichact as the 'master valve' of the BOP stack.

8.8. Spare parts for BOP's and valves must be available on rig site.



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9. BOP CONTROL SYSTEM (LAND, JACK-UPS AND FIXED

PLATFORMS)

Reference

9.1. The accumulator system should be capable of closing each ramBOP within 30secs.

P-1-M-6150 6.2.1-a

9.2. The closing time should not exceed 30secs for annular preventerssmaller than 18

3/4” nominal bore.

P-1-M-6150 6.2.1-a

9.3. The closing time should not exceed 45secs for annular preventersof 18

3/4” and larger sizes.

P-1-M-6150 6.2.1-a

9.4. Hydraulic operating equipment shall have at least a 3,000psiaccumulator unit equipped with two regulator valves, one to reduce

the operating fluid pressure to 1,500psi and the other for further reduction of pressure for bag type preventer operations.

P-1-M-6150 6.2.1-b

9.5. The capacity of the accumulators should be at least equal to thevolume (V1), necessary to close and open all BOP functionsinstalled on stack once, plus 25% of V1. The liquid reserveremaining on accumulators should still be the minimum operatingpressure of 1,200psi (200psi above the precharge pressure).

P-1-M-6150 6.2.1-c

9.6. The control panel shall be fitted with acoustic and visual alarms for low accumulator pressure as well as low level in the control fluidreservoir.

P-1-M-6150 6.2.1-d

9.7. A minimum of two air-driven pumps and one electrically driventriplex pump is required for charging the accumulators. Thecombination of air and electric pumps shall be capable of chargingthe entire accumulator system from the precharge to full chargepressure within 15min or less.

P-1-M-6150 6.2.1-e

9.8. In addition to the hydraulic master control panel, the BOP controlsystem shall include at least one graphic remote control panellocated on the rig floor near the Driller’s console.

P-1-M-6150 6.2.1-f

9.9. Offshore units shall have an additional graphic remote controlpanel located at a safe distance from the rig floor, usually inToolpusher’s office or adjacent to the escape route from drillingunit.

P-1-M-6150 6.2.1-f

9.10. Each remote control panel shall be connected to the controlmanifold in such a way that all functions can be operatedindependently from each panel.

P-1-M-6150 6.2.1-f



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9.11. A safety device shall be installed on the BOP control manifold andremote panels to prevent accidental operation of BOP controls

such as the closure of the rams (pipe or shear) on the drillingstring while drilling or tripping.

P-1-M-6150 6.2.1-g

9.12. The BOP end of the control hoses must be flexible and fireproofed.

P-1-M-6150 6.2.1-h

9.13. The BOP accumulator electric-driven pump shall be connected toan emergency source of power.

P-1-M-6150 6.2.1-I

9.14. From the control panel on the rig floor, it must be possible tooperate the shear rams and the hydraulic by-pass (1500-3000psi).

M-1-M-5005 2.3

9.15. The pipe ram preventers shall be equipped, at all times, with thecorrect sized rams to match the string in use.

P-1-M-071 7.4.3-dP-1-M-6033 13.4.3-dP-1-M-6150 6.1.1-b

9.16. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to fullcharge pressure in 15mins.

P-1-M-6150 6.1.1-e

10. BOP CONTROL SYSTEM (FLOATERS) Reference

10.1. Two complete independent control systems (yellow pod and bluepod) are required to ensure redundant control of all stackfunctions.

P-1-M-6150 6.2.2-b

10.2. With charging pumps inactive, the accumulator system shall beable to close, open and close all ram type preventers, and one bagpreventer with a resulting system pressure of 200psi or moreabove the initial pre-charge.

P-1-M-6150 6.2.2-e

10.3. The accumulator system should be capable of closing each rampreventer in less than 45secs and each bag-type preventer in lessthan 60secs.

P-1-M-6150 6.2.2-a

10.4. The rig should be equipped preferably with an emergency and fullyindependent acoustic control system.

P-1-M-6150 6.2.2-c

10.5. The associated subsea accumulator shall be mounted on the BOPstack, not attached to the LMRP, and should have a capacityadequate for closure of: one ram type preventer, shear rams, andfor releasing the LMRP connector.

P-1-M-6150 6.2.2-c

10.6. The control panel shall be fitted with visual and acoustic alarms for low signalling accumulator pressure, as well as control fluidreservoir low level.

P-1-M-6150 6.2.2-f

10.7. A minimum of two air-driven pumps and one electrically driventriplex pump is required for charging the accumulators.

P-1-M-6150 6.2.2-g



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10.8. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to full

charge pressure in 15mins or less.

P-1-M-6150 6.2.2-g

10.9. In addition to the hydraulic master control panel, the BOP controlsystem shall include at least two graphic remote control panels,one on rig floor and the other in the Rig Manager’s office.

P-1-M-6150 6.2.2-h

11. CHOKE MANIFOLD (ALL) Reference

11.1. All choke and kill lines and choke manifold components which maybe exposed to well pressure shall have a working pressure ratingequal or greater than that of the preventers in use.

P-1-M-6150 6.3-a

11.2. The minimum recommended size for all choke lines and valves is3” (76.2mm). All valves shall be of full-opening gate valve types.

P-1-M-6150 6.3-b

11.3. At least four f low wings shall be provided:

• One wing to transmitting well returns directly to the dischargemanifold and shall be equipped with two gate valves.

• Three wings equipped with adjustable chokes with two gatevalves upstream of each choke and one erosion nippleimmediately downstream of each choke.

P-1-M-6150 6.3-c

11.4. A graphic scheme of the choke manifold shall be posted on the rig

floor.

P-1-M-6150 6.3-d

11.5. At least one choke shall be remote hydraulically operated. P-1-M-6150 6.3-c

11.6. During drilling operations, the remote choke shall be left in half-open position

P-1-M-6150 3

12. INSIDE PIPE SHUT-OFF DEVICES Reference

12.1. In shallow holes a back flow valve must be installed in the string. P-1-M-6150 6.4-e

12.2. The Kelly or Top Drive shall be equipped with an upper and a

lower Kelly cock in functioning condition. The Kelly cock’s WP shallbe equal to or greater than the rating of the preventer stack in use.The upper Kelly cock of the top drive shall be hydraulicallyoperated.

P-1-M-6150 6.4-a

12.3. A spare full opening safety valve (lower Kelly cock) that iscompatible with drill pipe in use shall be stationed on the rig floor at all times, in the open position and complete with removablehandles for ease of stabbing.

P-1-M-6150 6.4-b

12.4. A crossover for connecting the full opening safety valve to the drillcollars or tubing in use shall be also stationed on the rig floor.

P-1-M-6150 6.4-c



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12.5. Wrench for cock should be kept handy.

12.6. With a TDS, one spare inside BOP and saver sub shall beavailable on the rig site

12.7. A Gray type inside BOP, with the appropriate connection for thedrill string in use, shall be on the rig floor at all times and must bein the open position.

P-1-M-6150 6.4-d

12.8. One drop-in type backpressure valve, complete with seating substo fit the drill string in use, shall be available.

P-1-M-6150 6.4-e

12.9. A wireline retrievable drop-in type backpressure valve is thepreferred type.

P-1-M-6150 6.4-e

12.10. All string tools installed above the sub shall have an ID greater than the drop-in valve OD.

P-1-M-6150 6.4-f

12.11. A set of float valves, one for each size of drill collar, and one for drill pipes in use, shall be kept available.

P-1-M-6150 6.4-g

13. AUXILIARY CONTROL EQUIPMENT Reference

13.1. The trip tank system shall include centrifuge pumps, fill up the line,recirculating circuit and a mechanical mud level device equippedwith reading indicator, easily visible to the Driller. The minimum

capacity of the trip tank should be 5m

3

(30bbls).

P-1-M-6150 7.6-a

13.2. A mud pit level volume indicator shall be installed on each tank of the active mud system. A continuous recording pit level indicator and totaliser, with audible alarm, is required to monitor the volumeof all active pits.

P-1-M-6150 7.6-b

13.3. The rated working pressure of the cementing lines shall be thesame as the BOP, which will not be less than 10,000psi. Acementing line should be connected to the kill line.

P-1-M-6150 6.7-i

13.4. A mud pit level volume indicator shall be installed on each tank of the active mud system. A continuous recording pit level indicator

and totaliser, with audible alarm, is required to monitor the volumeof all active pits.

P-1-M-6150 6.7-b

13.5. The rig shall be equipped with an adequate degasser, to conditiongas-cut mud, installed on the mud active system.

P-1-M-6150 6.7-e

13.6. On 5” OD x 5,000psi surface lines the connections must bewelded. No threads are allowed except for 2” size.

P-1-M-6150 7.6-f



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13.7. The standpipe manifold shall be equipped with a connection, whichcan be fully isolated to fit a 10,000psi cementing line and fully

isolated.

P-1-M-6150 6.7-g

13.8. The flare must be securely anchored, at least at 30m from thecentre well.

13.9. The flare line must be as straight as possible and bends must beof the flanged type.

13.10. The ends of the BOP’s hoses must be flexible and fire proof type.

13.11. Two 5” OD x 19mm wall thick standpipes and 31/2” ID x 5,000psi

WP rotary hoses with welded connections are required.

P-1-M-6150 7.6-h

13.12. The rated working pressure of the cementing lines shall be thesame as the BOP, which will not be less than 10,000psi. Acementing line should be connected to the kill line.

P-1-M-6150 7.6-i

13.13. The burner booms/flare will be connected to the choke manifold.They will be tied in according to the safety regulations in force for the operating zone.

P-1-M-6150 7.6-j

13.14. An air-operated, skid mounted, high pressure, low-volume testingunit is required for hydraulic testing of the BOP and manifolds.

P-1-M-6150 7.6-k

14. DIVERTER EQUIPMENT Reference

14.1. Whenever possible, there must be at least two discharge lines withthe ends laterally positioned at opposite points of the rig to alwaysenable blowing to the leeward side.

P-1-M-6150 6.6-a

14.2. Diverter outlets and lines shall have a minimum internal diameter of 12” for offshore rigs and 10” for land rigs. Welded flanges or clamped connections are mandatory.

P-1-M-6150 6.6-b

14.3. Diverter valves shall be full-opening valves, preferably ball typevalves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden.

P-1-M-6150 6.6-d

14.4. The automated system shall be set to allow for immediateautomatic opening of the discharge lines followed by closure of theshale shaker line before closing of the diverter packing.

P-1-M-6150 6.6-e

14.5. Each diverter system should incorporate a kill line facility (includinga check valve) in order to be able to pressure test and function testthe system and to pump water through the diverter system.

P-1-M-6150 6.6-g



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14.6. The control system for the diverter should be capable of closingany diverter smaller than 20” within 30secs and any

diverter/annular of 20” or larger within 45secs. Diverter valvesshould be opened before the diverter element is completelyclosed.

P-1-M-6150 6.6-I

15. MISCELLANEOUS Reference

15.1. Five Walky-Talkies shall be available with charged batteries readyto use.

15.2. The emergency system must be placed far from the normal power system and it must have its own fuel tank able to ensure at least24 continuous running hours.

15.3. Power emergency sources shall be connected to the followingservices:

• Radio communication system

• Fire fighting system (offshore)

• Gas monitoring and alarm system (offshore)

• Navigation lights (offshore)

• Divers safety apparatus (offshore)

• Emergency lights in the most important place for safety.

15.4. In addition to the normal electric system and to the emergencysystem, the drilling unit must be provided with a set of emergencybatteries, having enough capacity to ensure a six-hour continuoussupply of current to:

• Telecommunication system

• Navigation lights (off-shore)

• Emergency lights placed along the ways of escape, in theheliport, in the gathering stations for ship abandonment.

The output of the batteries set must automatically switch-onwhenever the emergency electric system as per 13.2 stopsrunning and the main electric system is not operating.

15.5. Emergency source of compressed air shall be connected with BOPaccumulator air-driven pump.

15.6. Cellar must always be empty and clean.

15.7. The escape ways must always be kept free and clean.



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15.8. A minimum volume of 70m3 of kill mud at 1.4kg/l (or at least three

times the inside drill pipe volume) shall be stocked while drilling

surface hole without a BOP stack.

P-1-M-6140 6.5-d

15.9. The pop-off valves on the mud pumps shall be set at the maximumpressure for the liners in use.

15.10. The pump discharge must be securely fixed to the mud tank andpump body.

15.11. The mud mixing system must be efficient enough to ensure themaximum mixing rate while weighting up and simultaneously mudconditioning.

16. BOP AND RISER RUNNING (FLOATERS) Reference

16.1. Before running the BOP stack, check the weather forecast andrefer to 'Rig Operations Manual' for maximum vessel motions for BOP running.

P-1-M-6140 5.4.2

16.2. Move the rig approximately 20m away from the hole when runningthe riser and BOP stack. When the telescopic joint is picked up,reposition the rig over the hole centre again.

16.3. When landing the stack, observe the underwater operations withSSTW or ROV. ‘Blind’ landing should only be used in emergency

situations.

16.4. Bulls-eye angle indicators must be installed above and below theball/flex joint and must be visible by the subsea TV.

P-1-M-6140 5.4.2

16.5. When running the riser with the choke and kill lines, it must betested every third joint.

P-1-M-6140 5.4.2

16.6. Upon latching the BOP stack on the wellhead housing, make apick up test of 15ton (30,000lbs) to verify the connector is lockeddown.

P-1-M-6140 5.4.3

16.7. By pumping down choke or kill line, test the wellhead connector and the casing against blind/shear rams to the pressure indicatedon drilling programme.

P-1-M-6140 5.4.3

17. BOP AND CASING TESTS Reference

17.1. General Procedures

17.1.1. Contract obligations require that all Drilling Contractor's andCompany pressure control equipment must be appropriately andregularly tested according to legislative requirements.

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17.1.2. Rig operations should not continue in the event that there is afailure to the primary or back-up systems.

P-1-M-6150 7.1-c

17.1.3. Derogations of this rule are not allowed on exploration wells or when there are failures on essential equipment.

P-1-M-6150 7.1-c

17.1.4. If malfunctions occur during development drilling or on marginalequipment, the Company Wellsite Drilling & Completion Supervisor and Drilling Contractor Toolpusher/OIM, may unanimously decideto continue operations after being properly informed anddocumented on the actual well situation.

P-1-M-6150 7.1-c

17.1.5. All pressure tests shall be performed using water. P-1-M-6150 7.1-e

17.1.6. BOP stack, choke and kill lines shall be flushed with water prior totesting.

P-1-M-6150 7.2.3

17.1.7. Remove the wear bushing prior to starting BOP tests. P-1-M-6150 7.2.3

17.1.8. In all cases the maximum test pressure for each BOP test will notexceed 70% of the rated WP of the lowest rated item of equipmentin the wellhead assembly, casing or preventer stack assembly,whichever is the lower

P-1-M-6150 7.2.2

17.1.9. If the BOP stack test is done with the cup tester, be sure that the

casing spool valve is open and the check valve in the casing spoolalso kept open by the appropriate needle valve.

P-1-M-6150 7.2.3

17.1.10. All BOP tests, drills, function tests, any malfunctions, repair or maintenance to the mud system and well control equipment shallbe recorded in the IADC daily reports and shall be signed by boththe Drilling Contractor's Toolpusher and Company's Drilling andCompletion Supervisor on the well site.

P-1-M-6150 7.2.3

17.1.11. They shall also be recorded in the Eni-Agip ‘Daily Drilling Report’. P-1-M-6150 7.2.3

17.2. Ram And Annular Type Preventer Tests

17.2.1. Pipe rams and annular BOPs shall be tested with open-ended cuptesters to a low pressure of 300psi (21kg/cm2) and to a highpressure at least equal to the maximum anticipated wellheadpressure.

P-1-M-6150 7.2.2-1

17.2.2. If an over-sized BOP-stack is installed, the high pressure test shallbe equal to maximum wellhead 'estimated' pressure plus 30%(anyway not less than 2,000 psi).



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17.3. Bl ind/Shear Ram Type Preventer Tests

17.3.1. Blind/shear rams shall be tested using blind plug testers to thesame pressure as stated above for pipe rams.

P-1-M-6150 7.2.2-2

17.3.2. Where a plug tester is not available, the blind/shear rams will betested against the casing each time a new casing string has beenset, prior to drilling out the cement. In this case the testingpressure will not be exceed 1,500psi (105kg/cm

2).

P-1-M-6150 7.2.2-2

17.4. Kill/Choke Lines & Manifold Tests

17.4.1. Any time tests are carried out on a BOP stack, the kill and choke

lines shall be tested.

P-1-M-6150 7.4.4

17.4.2. Kill and choke lines will be tested from the choke manifold to thehydraulic operated valve on BOP stack.

P-1-M-6150 7.4.4-a

17.4.3. Each valve of the choke manifold shall be tested individually. P-1-M-6150 7.4.4-b

17.5. Rig Floor & Cementing Manifold Tests

17.5.1. This equipment shall be tested with water every time tests arecarried out on the BOP stack, according to the followingprocedure:

P-1-M-6150 7.4.5

17.5.2. Top drive, BOPs or lower and upper Kelly cocks, standpipe and allindividual standpipe manifold valves, up to the relief valve on themud pumps shall be tested through a special test sub, made up onthe lower Kelly cock and installed on the Kelly/top drive

P-1-M-6150 7.4.5-a

17.5.3. After the first BOP installation, the equipment shall be tested totheir rated working pressures. On routine tests they will be testedat least to the same pressure applied for the BOP test.

P-1-M-6150 7.4.5

17.6. Casing Tests

17.6.1. Casing pressure tests will be carried out according to the pressurestated in the drilling programme.

P-1-M-6150 7.5

17.6.2. In all cases the test pressure will be no higher than 70% of APIminimum internal yield pressure of the weakest casing in the stringor to 70% of the BOP WP.

P-1-M-6150 7.5

17.7. The test pressure shall be held and remain stable for at least 10-15mins.

P-1-M-6150 7.5



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17.8. Function Tests

17.8.1. All preventers and BOP valves, with the exception of the annular preventer and blind/shear rams preventers, should be operated atleast once every shift.

P-1-M-6150 7.4.2

17.8.2. All preventers and BOP valves should be operated every trip(choke manifold included).

P-1-M-6150 7.4.2

18. BOP AND CASING TESTS (FLOATERS) Reference

18.1. General Procedures

18.1.1. Prior to the BOP test, retrieve the 183/4” nominal seat protector. P-1-M-6140 5.4.4-1

18.1.2. Fill the BOP Test Plug running string to the top with water. Thestring must remain open to atmosphere during the entire test.

P-1-M-6140 5.4.4-3

18.1.3. The test must be performed using both the pods. If the yellow podis used for pressure test, the blue pod will be used for the functiontest.

P-1-M-6140 5.4.4-4

18.1.4. Pressure test must not exceed the previous pack-off pressure test.

18.1.5. Record all pressure tests on pressure recorder charts and alsorecord the volumes displaced to reach the test pressures and the

volumes returned when bleeding off.

P-1-M-6150 7.1.1-b

18.2. BOP Tests at Surface

18.2.1. The complete BOP stack shall be stump tested at surface. All BOPcomponents shall be pressure tested to a low pressure of 300psiand to their rated working pressure.

P-1-M-6150 7.3

18.3. BOP Tests Af ter Landing on Wellhead

18.3.1. After the BOP stack is latched to the wellhead, a full function test

on both pods shall be carried out.

P-1-M-6150 7.3.1-2

18.3.2. Choke and kill lines (from surface to the fail-safe) shall be pressuretested to their rated WP.

P-1-M-6150 7.3.1-1

18.3.3. All the BOP components shall be pressure tested with a test plugto a low pressure (300psi).

P-1-M-6150 7.3.1-3

18.3.4. The lower connector shall be tested against one set of pipe ramsto the rated working pressure of the wellhead or the ram preventer,whichever is lower.

P-1-M-6150 7.3.1-3



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18.3.5. All other components, with the exception of shear rams, will betested to a minimum pressure of 70% internal yield pressure of the

weakest joint of casing in the string.

P-1-M-6150 7.3.1-3

18.3.6. Shear rams shall be tested against the casing to a low pressure of 300psi and to a maximum pressure equal to 70% internal yieldpressure of the weakest joint of casing in the string.

18.4. BOP Tests After Setting of Casing

18.4.1. The seal assembly shall be pressure tested to a maximumpressure equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.

P-1-M-6150 7.3.2-1

18.4.2. The test shall be performed at 500psi (35kg/cm2) increments untilthe test pressure is reached.

P-1-M-6150 7.3.2-2

18.4.3. All BOP components shall be pressure tested to a low pressure of 300psi (21kg/cm2) and to a minimum pressure equal to themaximum anticipated wellhead pressure, or 70% of the internalyield pressure of the weakest item of equipment, whichever is thelower.

P-1-M-6150 7.3.2-3

18.4.4. Shear rams shall be pressure tested against the casing prior to

drill out of the shoe as per the drilling programme.

18.5. BOP Tests While Drilling

18.5.1. All BOP components with the exception of shear rams, shall betested to a low pressure of 300psi (21kg/cm2) and to an highpressure at least equal to the maximum anticipated wellheadpressure.

P-1-M-6150 7.3.3-1

18.5.2. In all cases the maximum test pressure for each BOP test will notexceed 70% of the rated working pressure of the lowest rated itemof equipment in the casing or BOP preventer stack, whichever is

the lower.

P-1-M-6150 7.3.3-1

18.5.3. Shear Ram Tests While Drilling:

Function test only.

P-1-M-6150 7.3.3-2

18.6. Choke Manifold Test

18.6.1. The choke manifold will tested every time tests are carried out onBOP.

P-1-M-6150 7.4.5



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19. DIVERTER TEST (BEFORE START OF OPERATIONS) Reference

19.1. Before start of drilling operations, perform a diverter function testby pumping water through the open lines.

P-1-M-6150 9.4.2

19.2. Closing time on 5” DP.

Check the closing time, this time depends on the diverter type,usually:

• for type smaller than 20” should be within 30 seconds

• for type sizing 20” or larger should be within 45 seconds

P-1-M-6150 9.4.3-1

20. FREQUENCY OF BOP TESTS Reference

20.1. Routine BOP test while drilling:

• Once every 14 days.

• Prior to running a DST or production test assembly.

• Any time requested by the Company or to meet wich localregulations.

P-1-M-6150 7.4

20.2. Rig floor manifold and choke manifold should be tested at thesame frequency as in the routine BOP test while drilling.

P-1-M-6150 7.4.4

20.3. Each casing shall be pressured tested:

• When cement plug bumps on bottom.

• After have milled out a DV collar.

• When blind ram are tested.

P-1-M-6150 7.5

20.4. Function Test:

• Blind/shear rams shall be operated every round trip in thehole.

• The annular preventer shall be operated when the scheduledroutine BOP tests are performed.

P-1-M-6150 7.4.2

20.5. Any time the BOP stack is nippled up and after repairing

operations, all BOP operating equipment hoses, control panels,regulator connections shall be checked and tested to the maximummanufacturer's recommended pressure for closing and openingthe BOP's.

P-1-M-6150 7.4.3

20.6. BOP Test Durations P-1-M-6150 7.4.1

20.6.1. The BOP 300psi low pressure test will be performed first. They areto be held for a min period of 5mins. If the BOP does not pass thelow pressure test, do not carry out the high pressure test.

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20.6.2. It is recommended that high pressure tests are held for a minimumof 10mins.

M-1-SS 5703 App.A-B4

P-1-M-6150 7.4.1

20.6.3. The maximum acceptable pressure drop over this 10mins period is100psi.

M-1-SS 5703 App.A-B4P-1-M-6150 7.4.1

20.6.4. All pressure tests should be recorded on pressure charts and shallbe made available upon request by the Company representative.

P-1-M-6150 7.1.1

21. DRILLS Reference

21.1. Familiarity Drills

21.1.1. The purpose of these drills is to familiarise rig personnel with thevarious equipment and with the techniques that will be employed inthe event of a kick.

P-1-M-6150 8.1

21.1.2. Shut-In Drills

21.1.2.1. The Drilling Contractor's personnel shall conduct drills to close-inthe well in the shortest possible time, fully comprehending theprocess.

P-1-M-6150 8.1.1

21.1.2.2. While on bottom:Pick up the Kelly or top drive to the correct height, shut down thepumps and then carry out a simulated well shut-in.

P-1-M-6150 8.1.1-2

21.1.2.3. While tripping:

Lower the stand into the hole to the correct height and set the pipein the slips, stab-in a full opening safety valve (lower Kelly cock) inthe open position, close the safety valve, then carry out asimulated well shut-in.

P-1-M-6150 8.1.1-2

21.1.2.4. To train the rig crews, shut-in drills should be planned to also cover the following associated operations:

• Pull the BHA out of the hole.

• Running casing.

• Wire line surveying.• Logging (as well for TLC logging, if any).

• Running tubing (single as well as dual completion running).

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21.1.3. Choke Manipulation Drill

21.1.3.1. The choke manipulation drill should be carried out before drillingout shoe tracks. Drilling Contractor’s crew should:

• Run the bit to above the shoe track.

• Break the circulation and record the RPSP.

• Close the BOP.

• Apply pressure to the well, and simulate a circulation under kick condition using the automatic power choke and manualadjustable choke.

• Record the circulating drill pipe pressure and casing pressure.

P-1-M-6150 8.1.2

21.2. Emergency ‘On-The-Rig’ Drills

21.2.1. Potential Fire On Well And Rig Abandonment Simulation

21.2.1.1. The bit should be inside the casing shoe and not in a troublesomezone.

P-1-M-6150 8.2.1

21.2.1.2. The Drilling Contractor’s crew on duty will shut-in the well andhang-off the pipe without opening the hydraulic valve on the chokeand kill lines.

P-1-M-6150 8.2.1

21.2.2. H2S Drill

21.2.2.1. The H2S drill can be operated at two levels:

• Alarm drills simulating the presence of H2S in the mud.

• Emergency drill simulating the presence of H2S in the air, i.e.in the shale shakers area, on the rig floor, at the mud tanksetc.

P-1-M-6150 8.2.2

21.2.2.2. All personnel must wear breathing apparatus and, with theexception of the crews on duty, they must proceed to the windwardemergency safe breathing area, while the emergency crew securethe well and simulate the delimitation of the polluted area.

P-1-M-6150 8.2.2

21.2.2.3. H2S drills shall be recorded on the IADC Daily Drilling Report andappropriate company form.

P-1-M-6150 8.2.2

21.2.3. Abandon Rig

21.2.3.1. All personnel, except the crews on duty, must get ready toabandon the rig. Operations must be suspended for the time thedrill is carried out.

P-1-M-6150 8.2.3



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21.3. Well Control Drills

21.3.1. All drills and responses shall be recorded on the Company DailyDrilling Report and IADC Report. Pit drills shall be recorded on theCompany’s appropriate form.

P-1-M-6150 8.3

21.3.2. Pit Drills

21.3.2.1. If the drill string is in open hole, the well will not be shut-in. P-1-M-6150 8.3.1

21.3.3. Trip Drills

21.3.3.1. The drill shall be performed with bit inside the casing shoe andwhen not in a troublesome zone.

P-1-M-6150 8.3.2

21.3.3.2. Trip drill with drill pipe in the BOP stack. P-1-M-6150 8.3.3

21.3.3.3. Trip drill with drill collars or tubing in the BOP stack. P-1-M-6150 8.3.4

21.3.4. Accumulator Drills

21.3.4.1. This drill should be conducted after each casing setting before theBOP pressure tests.

P-1-M-6150 8.4

21.3.4.2. The final accumulator pressure shall not be less than 1,200psi

(84kg/cm2

).

P-1-M-6150 8.4-5

21.3.5. Diverter Drills P-1-M-6150 8.5

21.4. Drill Frequency And Response Times

21.4.1. Shut-in drills and H2S drills shall be carried out on an each shiftbasis at the beginning of any new activity or any time experiencedpersonnel are replaced with new recruits, especially when keyposition personnel are involved such as the Toolpusher, Driller and Assistant Driller. Drills shall be repeated until every crew member gains the correct experience and training.

P-1-M-6150 8.6.1

21.4.2. Choke manipulation drills should be carried out prior to drilling outsurface or intermediate casings string.

P-1-M-6150 8.6.1

21.4.3. Potential fire on wellsite and/or abandon rig drills shall be executedevery week.

P-1-M-6150 8.6.1

21.4.4. Emergency drills have to be performed weekly and repeatedbefore entering the zone where the presence of H2S is suspected,before coring, and before making DST or a production test whenthe presence of H2S is, either, predicted or ascertained.

P-1-M-6150 8.6.1



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21.4.5. Pit/trip drills shall be carried out on a shift basis every fortnight.These drills shall be conducted also when the well is nearing or

entering high pressure zones.

P-1-M-6150 8.6.1

21.4.6. Diverter drills shall be performed prior to drilling out the conductor string.

P-1-M-6150 8.6.1

22. TIMING Reference

22.1. Time is the most important aspect in shut-in drills and pit drills, andthe times required to accomplish the given task shall be recorded.

P-1-M-6150 8.6.2

22.2. The reaction times that can be considered as satisfactory toaccomplish different drill requirements are detailed below:

P-1-M-6150 8.6.2

22.2.1. Shut-in drills. One minute from activation of the alarm signal tobeing ready to close the bag type preventer.

P-1-M-6150 8.6.2

22.2.2. Pit drills. Not more than 2.5min from an observable change indrilling fluid volume to the time the well is closed-in, implementingthe soft shut-in procedure.

P-1-M-6150 8.6.2

22.3. The correct timing for all other tests will be defined in the DrillingContractor's Procedures according to the equipmentcharacteristics.

P-1-M-6150 8.6.2

23. HORIZONTAL WELLS Reference

23.1. The standard Well Control Procedures should be followed at alltimes, however, the drill crew must take into consideration someparticular aspects of a horizontal well:

23.1.1. Assuming that the fluid pressure and type in a horizontal well arewell known, the most likely cause of a kick is due to swabbing,losses, or crossing a fault.

23.1.2. When a long section of reservoir is exposed there is the potentialfor large and rapid kicks.

23.1.3. The practice of hole cleaning must minimise cutting beds whichcan increase the likelihood of swabbing.

23.1.4. Always pump out of a horizontal section; this will enhance thecleaning and reduce the possibility of swabbing.

23.1.5. Large quantities of influx can exist in the horizontal section withminimum effect on the bottom hole pressure.



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23.1.6. A flow check does not provide a reliable indicator that an influx hasnot entered the horizontal section.

23.1.7. In case of swabbed fluid in the horizontal section, both the shut indrill pipe pressure and shut in casing pressure would be zero untilthe influx is in the horizontal section.

23.1.8. Volumetric increases are the most reliable indicator of a kick. (Pitlevels and flow rate changes will be the same as in a verticalsection.)

23.1.9. Until the influx is circulated out of the horizontal section there is noincrease in the pressure casing. When swabbed fluid is in the holeand the Driller Method has been implemented, the casing pressureshould be zero until the influx is in the horizontal section.

23.1.10. If a kick occurs due to a fault or insufficient mud weight it isunlikely that there is any difference between the shut in drill pipeand shut in casing pressure when the influx is in the horizontalsection.

23.1.11. Migration may not occur in the horizontal section.

23.1.12. When killing the well using the 'Wait and Weight' method, the finalcirculating pressure should be reached when kill mud arrives at the

start of the horizontal section not at the bit.

23.1.13. The unevenness of the horizontal section may trap a pocket of gason the high side; this should be removed with more than onecirculation.

Reference List :

‘Well Control Policy Manual’ STAP-P1M-6150

‘Drilling Procedures Manual’ STAP-P1M-6140

‘Acceptance Minimum Requirements for BOP and

Well Control Equipment’ STAP-M-1-SS-5703

‘Well Control Training Manual’ January 1991



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OP. 2.10. LOT


1.1. These tests are carried out to:

a) Investigate the cement seal around the casing shoe whichshould be at least as high as the predicted fracture pressurefor the area.

b) Investigate the wellbore capability to withstand pressuresbelow the casing shoe in order to allow proper well planningwith regard to the setting depth of the next casing, mudweights and alternatives during well control operations.

c) Collect regional information on formation strengths and stressmagnitude for different applications including optimisation of

future well planning, hole stability analysis and modelling,reservoir application

P-1-M-6140 11

1.2. A Leak-Off Test (LOT) will be performed On Wild-Cat wells ateach casing shoe after setting the surface casing. LOTs are alsorecommended to be carried out on both appraisal anddevelopment wells.

P-1-M-6140 11

1.3. The test at point 1.1.a) shall be carried out before resuming drillingof the new phase, while tests at points 1.1.b) and 1.1.c) could beperformed at any depth while drilling the hole, as a porous level isencountered, to ascertain the maximum pressure that it can hold.

P-1-M-6140 11

2. STANDARD PROCEDURE Reference

2.1. Drill out float equipment, clean rat hole and drill 5 meters of newhole.

P-1-M-6140 11.1.1

2.2. Circulate a mud quantity equal to the internal string volume plusthe new hole plus 50m internal casing volumes.

P-1-M-6140 11.1.2

2.3. This mud shall be cleaned and conditioned to the density andfiltrate as indicated in the Mud Programme to be used for the nextdrilling phase.

P-1-M-6140 11.1.2

2.4. Pull the bit back into the casing shoe. P-1-M-6140 11.1.3

2.5. Rig up cementing unit to drill pipes P-1-M-6140 11.1.4

2.6. The unit shall be equipped with high precision low pressuregauges

P-1-M-6140 11.1.4

2.7. The range of the pressure gauge shall be selected based on theactualmud weight and the estimated (LOT) or predeterminated(FIT) pressure.



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2.8. A pressure recorder should be used during the test. P-1-M-6140 11.1.4

2.9. The use of the rig pumps for making these tests is unsuitable. P-1-M-6140 11.1.4

2.10. Fill up and test the lines with mud

2.11. Break circulation with the cementing unit to make sure that the bitnozzles are clear.

P-1-M-6140 11.1.6

2.12. Close BOP and open the previous casing annulus and Pumpslowly until pressure builds up

P-1-M-6140 11.1-7-9

2.13. Once pressure is established, pump uniform volumes of mud andwait for the pressure to stabilise. Flow rates range from 1/8 bbl/min

(20l/min) up to a maximum of 1bbl/min (160 l/min), however valuesof 0.25bbl (121/4” and smaller holes) or 0.50bbl (171/2” hole) arecommonly used, and wait for two minutes, or the time required for the pressure to stabilise.

P-1-M-6140 11.1.10

2.14. Note the cumulative mud volume pumped, the final pumping andfinal static pressure.

P-1-M-6140 11.1.11

2.15. Repeat steps (12) and (13) above and plot pressure versuscumulative mud volume for each increment of pumped volume.

P-1-M-6140 11.1.12

2.16. Continue this procedure until:

• Two or three points on the plot are reached where thepressure deviates and falls below the approximate straightline (or if the pressure does not increase with the injectedvolume). The point on the plot where the curve begins tobend away from the straight line is called Leak Off Point

• Or the predetermined test pressure is reached.

P-1-M-6140 11.1.13

2.17. Stop pumping, shut in the well, record and plot pressure versustime until stabilisation (usually it takes 15-20min). In the earlystage (2-3min) one value every 15-30sec should be collected whilefor the remaining a value of pressure every 30-60sec may besufficient. The use of PACR or an equivalent device, if available, ispreferred.

P-1-M-6140 11.1.14

2.18. Bleed off the pressure and record the quantity of fluid returned intothe cementing unit. Compare it to the volume used for the test toobtain the amount of fluid lost to the formation.

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2.19. Open the BOP and calculate the formation strength in terms of ‘Equivalent Mud Weight’ using the lowest between leak off point

pressure and stabilised pressure.

P-1-M-6140 11.1.16

2.20. Collect the data recorded during the test in a data sheet together with the following information: borehole diameter, depth of test,depth and type of the last casing, mud density, plastic viscosity,filtrate and gels.

P-1-M-6140 11.1.17

Reference List :

‘Drilling Procedure Manual’ STAP-P1M-6140



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OP. 2.11. CORING


1.1. Drift the string to ensure there are no restrictions that can stoppassage of the pressure relief plug ball.

P-1-M-6140 10.3.2-2

1.2. Ensure that the necessary fishing equipment is available beforerunning the core barrel.

P-1-M-6140 10.2.4

1.3. The core barrel shall be stabilised on bottom and top with specialstabilisers in order to reduce the wear on the gauge of the bit with,consequently, crooked and under gauged holes.

P-1-M-6140 10.2.6

1.4. The core barrel shall be run on a stabilised BHA. The stabilisation

of the BHA shall be, when possible, the same as used for drilling.

P-1-M-6140 10.2.7

1.5. DC excess will be eliminated if not necessary for WOB, in order toreduce pipe sticking risks

1.6. If required, it is possible to use MWD and the core barrel intandem, placing the steel ball on the pressure relief plug beforerunning in hole. In this case circulation through the core shoe isimpossible.

P-1-M-6140 10.2.8

1.7. Do not install a MWD tool on a core barrel in a deviated well with afractured formation.

P-1-M-6140 10.2.9

1.8. If a drilling jar is run in the string, the inside diameter of this toolmust be compatible with the ball diameter of the core barrel.

P-1-M-6140 10.2.10

1.9. Use proper size core barrels

1.9.1. Coring in 81/2" holes shall be carried out by using a conventional

core barrel (63/4” x 4”) or Marine Core Barrel (6

1/4" x 3" or 7

1/4" x

4") with a 81/2" diamond or PDC core head.

P-1-M-6140 10.2.1

1.9.2. Coring in 121/4" holes can be carried out by using a standard core

barrel (63/4” x 4”, 61/4” x 3”, 7

1/4” x 4”), Marine Core Barrel (6

1/4" x 3"

or 71/4" x 4") or a full size core barrel (8" x 51/4 ") with a 121/4 " corehead.

P-1-M-6140 10.2.1

1.9.3. Coring in a 6” hole can be carried out using the conventional corebarrel (43/4” x 25/8”).

P-1-M-6140 10.2.1

1.10. The full size core barrel is preferable when a long section of holemust be cored.

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1.11. In case of continuous coring, ream with a drill bit at least every100ft (27m) but only if a 815/32" core head is used. With the use of a

81/2" core bit this operation is not necessary.

P-1-M-6140 10.3.6-11

1.12. If necessary, space out with pup joint in order to avoid, or minimise, pipe connections while coring.

P-1-M-6140 10.3.2-6

1.13. Take and record the Reduced Pump Stroke Pressure (RPSP) withthe core barrel in the hole, after dropping the ball and with it inplace.

P-1-M-6140 10.2.13

1.14. While pulling out of hole, avoid jarring the core barrel and use‘spinner’ or ‘chain out’, to prevent core loss.

P-1-M-6140 10.3.6-1

1.15. Core shall be recovered under the company Well Site Geology’ssupervision.

P-1-M-6140 10.3.6-4

1.16. After coring an H2S bearing formation, it is necessary to wear theCascade System Mask (if available) or the 30-45 minutesbreathing apparatus during the whole core recovery operation

P-1-M-6150 10.3.3

Reference List :

‘Drilling Procedures Manual’ STAP-P1M-6140‘Well Control Policy Manual’ STAP-P1M-6150



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OP. 2.12. DRILLING PROBLEMS (STUCK PIPE, FISHING, MUD LOSSES, SHALLOW GAS,

HANG OFF, H2S)

1. STUCK PIPE Reference

1.1. Differential Sticking

1.1.1. Preventive measures

1.1.1.1. Reduce the mud weight as much as possible, maintaining theminimum differential pressure necessary for a safe trip margin.

P-1-M-6140 16.1.1-1

1.1.1.2. Reduce the contact surface by using spiral type drill collars alsocalled NWS (No Wall Stick).

P-1-M-6140 16.1.1-2

1.1.1.3. Use a properly stabilised bottom hole assembly. A shorter BHAwith a greater number of HWDP could be considered.

P-1-M-6140 16.1.1-2

1.1.1.4. Use mud with minimum solids content and low filtrate in order toobtain a thinner wall cake.

P-1-M-6140 16.1.1-3

1.1.1.5. Reduce the friction factor adding lubricants to the mud. P-1-M-6140 16.1.1-4

1.1.1.6. Keep pipe moving and possibly in rotation as much as possible P-1-M-6140 16.1.1-5

1.1.1.7. Consider the use of a drilling jar/bumper. P-1-M-6140 16.1.1-6

1.1.2. Methods of freeing pipe

1.1.2.1. Work the pipe applying cyclic slack-off and overpull combined withtorque. Always check the reduction in the pipe yield stress due tothe application of the torque.

P-1-M-6140 16.1.1

1.1.2.2. Use a drilling jar/bumper. P-1-M-6140 16.1.1

1.1.2.3. Spot oil-base mud or oil containing a surfactant around the BHA. P-1-M-6140 16.1.1

1.1.2.4. The pill volume shall be at least 20% over the volume of BHA-

Open hole annulus plus a volume so that at the end of thedisplacement the pill height is the same inside and outside thestring.

1.1.2.5. Reduce the mud weight, if possible. P-1-M-6140 16.1.1

1.1.2.6. Conduct a DST procedure. P-1-M-6140 16.1.1

1.1.3. Quick actions are fundamental in freeing wall stuck. P-1-M-6140 16.1.1



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1.2. Sticking Due To Caving Hole


1.2.1.1. Reduce water losses. P-1-M-6140 16.3

1.2.1.2. Lower pH value to 8.5 to 9 (if needed). P-1-M-6140 16.3

1.2.1.3. Use inhibited mud. P-1-M-6140 16.3

1.2.1.4. Add mud stabilising compounds (mainly sodium asphalt sulphate). P-1-M-6140 16.3

1.2.1.5. Increase the mud weight. P-1-M-6140 16.3

1.2.1.6. Increase the Y/PV ratio to create laminar flow on the wall after pipe.

P-1-M-6140 16.3

1.2.1.7. Increase the gel value to obtain a good cutting suspension whencirculation is stopped.

P-1-M-6140 16.3

1.2.1.8. Use bits without nozzles, particularly when reaming, to avoidscouring the well.

P-1-M-6140 16.3

1.2.1.9. Use the minimum acceptable number of stabilisers. P-1-M-6140 16.3

1.2.1.10. Reduce rotary speed, if possible, to 80rpm or less. P-1-M-6140 16.3

1.2.1.11. Reduce the mud flow rate to obtain laminar flow in the annulusbetween hole and drill collars.

P-1-M-6140 16.3

1.2.1.12. Avoid long circulation times across unstable sections. P-1-M-6140 16.3

1.2.1.13. Do not rotate pipe when tripping. Use a spinner or chain out. P-1-M-6140 16.3

1.2.1.14. Trip out with care to avoid swabbing. If any swabbing occurs, pullout with the Kelly on.

P-1-M-6140 16.3

1.2.1.15. Spot high viscosity pills from time to time. P-1-M-6140 16.3

1.2.1.16. Start and stop mud pumps gradually. P-1-M-6140 16.3

1.2.1.17. If circulating pressure increases suddenly, decrease pump strokes. P-1-M-6140 16.3

1.2.2. Methods of freeing pipe

1.2.2.1. If circulation is possible, continue circulating trying to expel thecaving.

P-1-M-6140 16.3



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1.2.2.2. If the string becomes stuck across a carbonate formation, spot anacid pill.

P-1-M-6140 16.3

1.2.2.3. If circulation is blocked, try to regain it by applying pressure shocksand working the pipe at the same time. Special care is required toavoid breaking the formation i.e. overcoming fracture gradientbelow the stuck point.

P-1-M-6140 16.3

1.2.2.4. Use a drilling jar/bumper. P-1-M-6140 16.3

1.2.2.5. It is good practice to spot high viscosity pills from time to time tokeep the hole clean.

P-1-M-6140 16.3

1.3. Sticking Due To Hole Restriction


1.3.1.1. Reduce filtrate, cake and solids content. P-1-M-6140 16.2

1.3.1.2. Use inhibited mud. P-1-M-6140 16.2

1.3.1.3. Increase mud-clearing capacity. P-1-M-6140 16.2

1.3.1.4. Increase flow rate. P-1-M-6140 16.2

1.3.1.5. Follow accurately the Sigma log development and if requiredincrease mud weight.

1.3.1.6. Increase mud weight, if possible.

1.3.1.7. In all situations, frequent wiper trips can reduce the problem andprovide information on the severity.

P-1-M-6140 16.2

1.3.2. Methods of freeing pipe P-1-M-6140 16.2

1.3.2.1. Work the pipe applying cyclic slack-off and overpull combined withtorque. Always check the reduction in the pipe yield stress due to

the application of the torque.

P-1-M-6140 16.2

1.3.2.2. Spot a cushion to break and remove the mud cake around the drillcollars.

P-1-M-6140 16.2

1.3.2.3. Increase the mud weight, if possible. P-1-M-6140 16.2

1.3.2.4. Use a drilling jar/bumper. P-1-M-6140 16.2



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1.4. St icking Due To Hole Ir regular it ies and / or Change In BHA P-1-M-6140 16.3.1


1.4.1.1. The formation of doglegs can be prevented by the use of packedbottom hole assemblies.

P-1-M-6140 16.3.1

1.4.1.2. Trip out with care and note the depths at which overpull occurs.

1.4.1.3. Using very stiff BHA's and reamers can eliminate doglegs. P-1-M-6140 16.3.1

1.4.1.4. A key seat can be eliminated by reaming it with a key seat wiper or an under-gauge stabiliser installed on the top of the drill collars.

P-1-M-6140 16.3.1

1.4.1.5. Always ream a whole interval drilled with the previous bit. P-1-M-6140 16.3.1

1.4.1.6. Always ream the cored section, even if a full gauge core bit wasused.

P-1-M-6140 16.3.1

1.4.1.7. Foresee use of three or six point roller reamer.

1.4.2. Methods of freeing pipe P-1-M-6140 16.3.1

1.4.2.1. Work the pipe applying slack-off if dog leg or key seat (the stringbecomes stuck pulling out) and overpull if running a new BHA (the

string becomes stuck while running in the hole).

P-1-M-6140 16.3.1

1.4.2.2. Spot oil-base mud or oil containing a surfactant around BHA. P-1-M-6140 16.3.1

1.4.2.3. If the stuck point is in a calcareous section, spot an acid pill. P-1-M-6140 16.3.1

2. OIL PILLS Reference

2.1. Light Oil Pills P-1-M-6140 16.4.1

2.1.1. To be used for mud specific gravity up to 1,350g/l (11.3 PPG). P-1-M-6140 16.4.1

2.1.2. The pill volume shall be at least twice the volume of DC-open holeannulus (take into account excess for compensating holeenlargement).

P-1-M-6140 16.4.1

2.1.3. Pump at the maximum practical rate. P-1-M-6140 16.4.1

2.1.4. In order to have a pill volume in the annulus displace 1.3 times thevolume of the DC-open hole.

P-1-M-6140 16.3.1

2.1.5. At 30 to 60mins intervals, circulate out of the string batches, as abalanced plug. Work the string at the same time.

P-1-M-6140 16.4.1



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2.1.6. Repeat the procedure if the pill does not succeed (the pill may beactive for 4 to 16 hours).

P-1-M-6140 16.4.1

2.1.7. Record pump pressure at each step and notate anomalousincreasing of pressure.

2.1.8. Check for drilling balance when pill is in the annulus.

2.2. Heavy oil pills

2.2.1. To be used for specific gravity greater than 1,350 g/l (11.3ppg). P-1-M-6140 16.4.2

2.2.2. The pill volume will be at least twice the volume between the drillcollars and the open hole (take into account excess for compensating hole enlargement).

P-1-M-6140 16.4.2

2.2.3. Pump a spacer of diesel oil with 5% Free Pipe, or similar, in frontand behind.

P-1-M-6140 16.4.2

2.2.4. Pump at maximum practical rate. P-1-M-6140 16.4.2

2.2.5. Displace in order to have a pill volume in the annulus 1,3 times thevolume of DC-open hole.

P-1-M-6140 16.4.2

2.2.6. At 2 to 3 hr intervals, circulate batches of 300 to 600 out of the

string. Work the string at the same time.

P-1-M-6140 16.4.2

2.2.7. Repeat the procedure if the pill results are ineffective (the pill maybe active for 20 to 48 hours).

P-1-M-6140 16.4.2

2.2.8. Record pump pressure at each step and notate anomalousincreasing of pressure.

3. ACID PILLS Reference

3.1. The use of acid pills can be successful if the string gets stuckacross a carbonate formation.

P-1-M-6140 16.4.3

3.2. Considering the risks related to this operation, this should becarried out only if other methods prove to be ineffective.

P-1-M-6140 16.4.3

3.2.1. The proper amount of corrosion inhibitor shall be used and theacid pill will be spaced with oil or water ahead and behind.

P-1-M-6140 16.4.3

3.2.2. Due to the acid reaction gaseous products develop in the well and,hence, special care is required when circulating out the pill. It maybe necessary to circulate through the choke and line up thesurface equipment to safely dispose of the gas.

P-1-M-6140 16.4.3



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3.2.3. Check for drilling balance assuming that all pills are in the annulus.

3.2.4. During all operations never stop the pump, but pump at minimumflow rate.

P-1-M-6140 16.4.3

3.2.5. While displacing acid across the formation, the gaseous productwill cool off the drill string. To avoid breaking, do not work thestring but only apply overpull or slack off.

Resume jarring only when acid is in place.

P-1-M-6140 16.4.3

3.2.6. Appropriate safety measures shall be adopted:

• Wear gloves and protective clothing.

• Use eye protection.

• Have water sprays ready to wash spilled acid.

• Ensure proper ventilation if the pill is mixed in a closed area.

P-1-M-6140 16.4.3

4. FREE POINT LOCATION Reference

4.1. The equipment required for free point indicator and back-off is tobe kept onboard during all drilling activity. (Offshore rigs).

4.2. If the free point is performed without a Kelly or top drive install alower Kelly cock on top of the DP.

The thread will be protected with an appropriate device.

4.3. Leave in place an eventual previous oil pill.

4.4. Check the minimum ID of drill string and verify that no restrictionsor obstructions are present.

P-1-M-6140 16.4.7

4.5. If possible, perform the free point with a Kelly or top drive installed(if necessary, space out).

4.6. Avoid swabbing when coming out with tool.

4.7. A remote operated wireline hydraulic cutter shall be on the rig floor

during the entire operation.

4.8. Record torque and tension at the value the string begins to stretch(string free).

4.9. There are two methods for estimating the depth at which a string isstuck:

• Applying tension and measuring the pipe stretch.

• Locating the tow point with a free-point indicating tool.

P-1-M-6140 16.4.4



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4.10. Measuring The Pipe Stretch P-1-M-6140 16.4.5

4.10.1. Calculating the differential stretch (E = S2 - S1), differential pull (P

= T2 - T1) and applying Hooke’s Law, it is possible to determine

the depth of free point (L) using the following formula:

SI Units P

ExWdpxL

374.26=

API Units P

ExWdpx294,735L =

The value obtained is less reliable as deviation increases due todownhole friction.

P-1-M-6140 16.4.5

4.11. Location By Free Point Indicating Tool

4.11.1. A Free Point survey shall be run to select the back-off point. P-1-M-6140 16.4.6

4.11.2. Pipe which appears to be free in tension does not always react toapplied torque. There is a greater chance of succeeding with theback-off if the pipe is free under both tension and torque.

P-1-M-6140 16.4.6

4.11.3. Interpretation of free point data is very subjective and susceptibleto operator skill, hole condition, etc.

P-1-M-6140 16.4.6

5. BACK-OFF PROCEDURE Reference

5.1. As a general rule, the first attempt to back-off should be made atthe first connection above the Free Point.

P-1-M-6140 16.4.7

5.2. If there is a failure, the second attempt should be performed on thefirst stand above the Free Point. Subsequent attempts should bemade moving upward one stand at a time.

5.3. Check the minimum ID of drill string. P-1-M-6140 16.4.7

5.4. Use an appropriate number of primacord strands for string shot.

(Refer to

Table OP 2.6)

P-1-M-6140 16.4.7

5.5. Check tongs, slips and jerk lines are in working condition. P-1-M-6140 16.4.7-b

5.6. Ensure that slip handles are tied together with strong line. P-1-M-6140 16.4.7-a

5.7. Ensure that no torque remains in the string when it is picked upfrom the slips.

P-1-M-6140 16.4.7-e



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5.8. If the back-off is performed without Kelly or top drive, install alower Kelly cock on top of the DP.

5.8.1. A remote operated wireline hydraulic cutter shall be on the rig floor during the entire operation.

P-1-M-6140 16.4.7

5.9. A detailed standard back-off procedure cannot be used as thereare too many variables.

P-1-M-6140 16.4.7

5.10. The fol low ing i s a typical generic procedure P-1-M-6140 16.4.7

5.10.1. Keep non-essential people away from the rig floor. P-1-M-6140 16.4.7

5.10.2. Tighten up all string connections, applying right hand torque (max80% of nominal value). Work the torque down the string. Thisprocedure should be repeated 4 to 5 times especially in crooked or deviated holes.

P-1-M-6140 16.4.7

5.10.3. Install the back-off tool in the string and run in the hole to around150-300ft (50-100m) below the rotary table.

P-1-M-6140 16.4.7

5.10.4. Pick up the string in order to have a hook load equal to the weightin air of the pipe above the selected back-off point increased by 10to 15%.

P-1-M-6140 16.4.7

5.10.5. Apply left hand torque in steps. Work the pipe at each step totransfer the torque downhole.

P-1-M-6140 16.4.7

5.10.6. The maximum amount of left hand torque should be 80% of themaximum value used for the right hand torque.

P-1-M-6140 16.4.7

5.10.7. Once the right amount of left hand torque is applied, run the Back-off tool to the Back-off point.

P-1-M-6140 16.4.7

5.10.8. If the operation is unsuccessful, release the left hand torque,circulate to clean the string from back-off debris and start again.

P-1-M-6140 16.4.7

5.10.9. The Backing-off of drill collar connections should be performed byfollowing the same procedure. Problems may arise due to thedifficulty in identifying the Free Point and with higher left handtorque required

P-1-M-6140 16.4.7

5.10.10. Prior to running another back-off tool, circulate to clean the insideof the DP from debris.

5.10.11. Perform mechanical back-off only as extreme solution.

5.10.12. In case of unexpected back-off at an unprogrammed depth, pullout the string and check connections.



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6. FISHING Reference

6.1. Inventory Of Fishing ToolsThe following tools shall be always available on the rig for thevarious hole sizes drilled:

• Fishing jars to match the drill collars in use.

• Bumper subs to match the drill collars in use.

• Overshot and oversize guides with grapples, baskets andextension subs, to catch all diameters of tools in hole.

• Taper taps for drill pipe body and tool joints (this is a poor class of tool: overshots are preferable if available).

• Junk baskets or Globe-type baskets.

• Reverse circulation junk baskets.• Junk subs.

• Fishing magnets.

• Milling tools.

• Re-dressing tools for 5" and 31/2" sheared DP.

• Impression blocks.

• Fishing tools to catch electrical log tools (supplied byelectrical log contractor) and relevant crossover.

• Safety joints.

P-1-M-6140 16.5.1

6.2. Preparation

6.2.1. Draw a complete sketch of the equipment run. P-1-M-6140 16.5.2

6.2.2. Apply the utmost accuracy in all measurements. P-1-M-6140 16.5.2

6.2.3. Make sure that the Contractor's personnel directly involved inoperations are fully familiar with equipment to be used and haveknowledge of limitations.

P-1-M-6140 16.5.2

6.2.4. Annotate any existing marks/signs on the fishing tool for futureinterpretation.

6.3. Fishing assembly P-1-M-6140 16.5.3

6.3.1. Fishing tool + Jar and Bumper Sub + Drill Collars + Heavy WeightDrill Pipe + Drill Pipe.

P-1-M-6140 16.5.3

6.3.2. Use as many drill collars as is contained in the fish. If the requirednumber of drill collars is not available on the rig, use a jar accelerator.

P-1-M-6140 16.5.3



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6.3.3. A Safety Joint should not be run. However, a Safety Joint could berun between the catching tool and the jar when a non-releasing

tool such as taper tap is being employed.

P-1-M-6140 16.5.3

6.3.4. Where losses are expected, the use of a Circulation Sub in thefishing assembly should be considered.

P-1-M-6140 16.5.3

6.3.5. Avoid restrictions in the bore of any tools run above the catchingtool, which would prevent the use of a cutting tool or the back-off shot within the fish.

P-1-M-6140 16.5.3

6.4. Fishing procedures

6.4.1. Overshot.

6.4.1.1. Be sure that the overshot OD is compatible with the hole diameter and the grapple with the fishing neck.

6.4.1.2. Whenever possible install a lock ring.

6.4.1.3. When fishing on a tool joint, use a basket grapple with long catchstop.

6.4.1.4. In case of re-run check the overshot shape.

6.4.1.5. Jarring is only possible using type SFS, FS and XFS overshots. P-1-M-6140 16.6.1-1

6.4.1.6. With the overshot just above the fish circulate a few minutes andrecord:

• Pump stroke and pressure.

• String weight up and down.

• Torque.

Do not prolong circulation excessively.

P-1-M-6140 16.6.1-5

6.4.1.7. If possible, circulating bottoms up through the fish before pulling

out of hole should be considered, particularly if potential reservoirsare exposed or penetration rates are high.

P-1-M-6140 16.6.1-7

6.4.1.8. When tripping out of hole with fish, the string shall not be rotated,a chain or Kelly Spinner should be used.

P-1-M-6140 16.6.1-8

6.4.1.9. If pulling out of hole wet, flow checks shall be carried outfrequently.

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6.4.2. Releasing spear

6.4.2.1. Choose the catching size according to casing nominal weight.

6.4.2.2. Install a pack-off on the tool, if circulation is required after latchingthe fish.

P-1-M-6140 16.6.2

6.4.2.3. To allow the unlatching of the spear (if there is not enough weightabove the releasing spear), a bumper sub is recommended.

P-1-M-6140 16.6.2

6.4.2.4. Use the fishing jar if jarring is required. In this case the use of aSpear Stop is required. Check the Spear Stop OD when it is usedin open hole and use the stop only if hole condition permits.

P-1-M-6140 16.6.2

6.4.2.5. Perform the fishing job as per overshot procedure. P-1-M-6140 16.6.2

6.4.3. Taper taps

6.4.3.1. The size of the taper tool should be selected in order to engagethe fish with the middle of the tapered point.

P-1-M-6140 16.6.3

6.4.3.2. It is nigh impossible to release the tool once engaged. For thisreason its use has to be considered the last resort and only after consultation with the Eni-Agip Shore Base (DrillingManager/Superintendent).

P-1-M-6140 16.6.3

6.4.3.3. Lower the catching tool to just above the fish and circulate a fewminutes to clean the top of the fish. Do not circulate excessively asthis may enlarge the hole.

P-1-M-6140 16.6.3

6.4.3.4. Chain or spin out of the hole with the fish. P-1-M-6140 16.6.3

6.4.4. Junk Basket

6.4.4.1. This procedure is more successful in soft formations. P-1-M-6140 16.6.4

6.4.4.2. Use the following parameters:

• WOB = 2 to 4t

• Rotary = 45rpm

• Low Pump Rate (1/2 pump rate while drilling).

P-1-M-6140 16.6.4

6.4.5. Fishing Magnet P-1-M-6140 16.6.5

6.4.5.1. Magnets can be successfully used but only in hard formations toretrieve small steel objects such as bit cones, bearings, slips, tongpins and milling cuttings.

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7. MILLING PROCEDURE Reference

7.1. Avoid the use of redressed mills. Only new mills must be used.

7.2. Mud viscosity should be increased or high viscosity pills should bepumped to help in carrying the steel cuttings out of the hole.

P-1-M-6140 16.7

7.3. Oil based mud has poor carrying capabilities and should beavoided whenever possible. Polymer muds are most suitable for milling.

P-1-M-6028 11.2.5P-1-M-6140 16.7

7.4. Never mill faster than it is possible to remove the cuttings. P-1-M-6140 16.7

7.5. Place junk sub(s) above the mill. P-1-M-6140 16.7

7.6. Generally the most efficient milling rates are obtained by runningthe rotary at 80 to 100rpm. Milling with washover shoes is anexception and they are usually more efficient at speeds of 60 to80rpm. Continuously monitor the torque indicator during millingoperations.

P-1-M-6140 16.7

7.7. 'Reading the cuttings’ is essential to evaluate the performance of the mill. The ideal cuttings are usually 1/32" to

1/16" thick and 1" to 2"long.

P-1-M-6140 16.7

7.8. Weigh steel cuttings and compare with theoretical calculation.

7.9. Always insert a jar in the string.

7.10. Whenever possible, use the same BHA as in drilling.

8. JARRING PROCEDURE Reference

8.1. The pre-set value of mechanical jars must be checked prior torunning in the hole, to verify if the margin of overpull is sufficient tooperate the jar.

M-1-M-5003 4.6.2

8.2. When a drilling jar is used, do not drill to Kelly down but leave

enough room to cock the jar in case of stuck pipe.

M-1-M-5003 4.5.9

8.3. Jarring should be done with a Kelly or Top Drive. If the use of aKelly is not possible, secure the elevator latch by using a piece of rope or chain.

P-1-M-6140 16.8

8.4. Prior to jarring, check the drill line sensor. Ensure the weightindicator readings are accurate and that the Dead Line Anchor issecure and free of debris. Check the derrick and all equipment for any loose items.

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8.5. When jarring, the drill floor must be cleared of all non-essentialpersonnel.

P-1-M-6140 16.8

8.6. Mark the string at the rotary table prior to starting jarring. P-1-M-6140 16.8

8.7. Always allow the jars to trip within their safe working load. Waituntil the jars have tripped before pulling the string further.

P-1-M-6140 16.8

8.8. Never exceed the safe working limit without confirmation that the jars have tripped.

8.9. When sustained jarring is carried out, the drill line should beslipped at regular intervals, depending on the particular situation.

P-1-M-6140 16.8

8.10. Also check the derrick, lifting equipment and travelling blockattachment bolts.

8.11. If a top drive system is used after jarring, check the TDS as per the maintenance and operating specification.

P-1-M-6140 16.8

9. LOST CIRCULATION Reference

9.1. Lost circulation control techniques

9.1.1. Definitions:

• Seepage Loss is that which is less than 50%• Almost Total Loss is that which is more than 50%

• Total

P-1-M-6160 6.1

9.2. Losses in various formation types

9.2.1. Unconsolidated Formations

9.2.1.1. Gradual increase in loss which may develop and increase withpenetration.

If permeability is less than 4/5 darcy, the loss is maybe due to

formation fracture.

P-1-M-6160 6.2

9.2.2. Natural Fractures

9.2.2.1. Gradual increase in losses which may develop and increase withpenetration.

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9.2.3. Cavernous Or Macrovugular Formations.

9.2.3.1. Sudden and severe, to complete loss, of returns.

The bit may fall from a few centimetres to some metres at themoment of loss. Perforations may be 'disturbed' before the losses.

P-1-M-6160 6.2

9.2.4. Induced Fractures

9.2.4.1. Sudden and severe to complete losses.

Fluids with density more than 1.3 SG may help create fractures.

Fracture may occur during, or subsequent, to rough drilling.

If it occurs in one single well and does not occur to the nearby

wells, fracture may be the cause.

P-1-M-6160 6.2

9.3. Loss of circulation with water based fluids

9.3.1. Stand-By/Set Time: Allow 4-8 hours set time. Plan further actionto be taken.

P-1-M-6160 6.4.1

9.3.2. High Viscosity Fluids: Viscosity at +/- 100sec. P-1-M-6160 6.4.1

9.3.3. LCM In Circulation: Shale shakers max., 10-12 mesh. P-1-M-6160 6.4.1

9.3.4. High Filtration Fluids: Do not use with unstable formations P-1-M-6160 6.4.1

9.3.5. Spot Pills With LCM: Squeeze slowly with a low pressure (50psi).Displace by means of bit with no nozzle or with nozzles >1

4/32”.

P-1-M-6160 6.4.1

9.3.6. High Fi ltrat ion Mixtures (200-400cc API): RIH or EDP on toploss, squeeze with low pressure (starting with +/- 50psi @150ltr/min). Do not exceed fracture pressure and maintain for 6-8hrs.

P-1-M-6160 6.4.1

9.3.7. Very High Fi ltrat ion Slurries (>600cc API): Same applicationprocedure as high filtration slurries with temperature >60°C. It may

develop mechanical resistance.

P-1-M-6160 6.4.1

9.3.8. Diaseal M (Fi lt rate >1,000cc API): Same application procedureas high filtration slurries.

P-1-M-6160 6.4.1

9.3.9. GEL Cement (Prehydrated Bentoni te): Formation of slurries withhigher percentages of Bentonite may improve LCM characteristicswhile decreasing mechanical resistance.

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9.3.10. Cement Gilsonite: As for cement plugs, it is advisable to drill theloss zone and carry out the remedial procedure when finished.

WOC for at least 8hrs.

P-1-M-6160 6.4.1

9.3.11. DOBC Squeeze (Diesel Oi l Bentoni te: Apply DOBC/DOBsqueeze procedure. RIH or EDP on top of loss zone. Plastic plugvolume to equal, or be greater than, the hole below the loss zonefirst and second plug, both about 1m3 diesel.

P-1-M-6160 6.4.1

9.3.12. DOB Squeeze: Drillpipe/ annulus ratio is 2:1, about 600 l/min fromdrillpie and 300 l/min from annulus. After displacing half the plug,reduce pump rate by half. After displacing

¾ of the plug, attempt a

‘hesitation squeeze pressure’ with 100-500psi. Underdisplace plug

by one barrel, POOH, allow 8-10hrs set time.

P-1-M-6160 6.4.1

9.4. Loss Of Circulation With Oil Based Fluids

9.4.1. Additions Of Colloid: Seepage loss is commonly due to lowcolloid contents of oil based.

P-1-M-6160 6.4.2

9.4.2. Spot Pills With LCM: squeeze slowly with low pressure (50psi).Displace by means of bit with no nozzles or with nozzles >1

4/32”.

P-1-M-6160 6.4.2

9.4.3. Diesel M (Fi lt rate >1,000 cc API: Spot pill volume is double thehole volume and at least 1.5m3. To avoid contamination 3-4m3,

separating pills are advisable after and before.

P-1-M-6160 6.4.2

9.4.4. Plast ic Plug Wi th Organophi l Clay: Spot pill volume should bedouble the hole volume or at least 1.5m3. To avoid contamination,3-4m

3 separating pills in front and behind is advisable.

P-1-M-6160 6.4.2

9.4.5. Fresh Water Barite Plug

The height of the plug, commonly 130-150m is sufficient.Mix with cement unit.Use bit with nozzles.

P-1-M-6160 6.4.2

9.5. Loss preventive measures P-1-M-6140 17.1

9.5.1. Keep the mud weight as low as possible but providing for adequate overbalance.

P-1-M-6140 17.1

9.5.2. Control the ROP to prevent overloading the annulus with cuttingswhich could result in increased mud densities and/or constrict theannulus.

P-1-M-6140 17.1

9.5.3. Maintain a low yield point and gel strength of mud. P-1-M-6140 17.1

9.5.4. Avoid excessive circulation rates. P-1-M-6140 17.1



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9.5.5. Run pipe slowly to minimise pressure surge. P-1-M-6140 17.1

9.5.6. To break circulation, rotate and reciprocate the pipe first, then startpumping slowly.

P-1-M-6140 17.1

9.5.7. Avoid pump surge. P-1-M-6140 17.1

9.5.8. Use bit nozzles larger than 14/32”. P-1-M-6140 17.1

9.5.9. Have an adequate stock of LCM. P-1-M-6140 17.1

9.6. Remedial actions P-1-M-6140 17.1.1

9.6.1.Remedial actions while drilling

9.6.1.1. If still losing mud, stop pumping and observe the well. P-1-M-6140 17.1.1

9.6.1.2. If the level remains static, the mud weight or viscosity may need tobe reduced slightly and/or slight treatment with lost circulationmaterial if required.

P-1-M-6140 17.1.1

9.6.1.3. If the level drops, the well must be kept full with mud or water,depending on the severity of the losses. An estimate can be madeof the maximum weight the formation can withstand, measuringthe volume of water required and calculating the new mud

gradient.

P-1-M-6140 17.1.1

9.6.1.4. Circulation may be restarted by any or combination of the followingmeans:

• Reduce flow rate (if possible).

• Reduce mud weight (if possible).

• Add LCM to the mud (the shale shaker must be by-passed).

• Wait for the formation to ‘heal’.

• Spot a plug of thick mud and LCM at the thief zone.

• Spot a plug of dehydratable material containing LCM into the

mud losses zone.• Squeeze diesel oil bentonite (DOB) or diesel oil bentonite

cement (DOBC) pills.

• Plug the thief zone with a gelled slurry.

P-1-M-6140 17.1.1

9.6.1.5. See annex table OP 2.7 to choose the method to be followed toregain circulation.

P-1-M-6160 6.1

9.6.2. Rimedial actions While tripping

9.6.2.1. As soon as any irregularity is noticed in filling the hole, the

following general procedure should be carried out:

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9.6.2.2. Check the trip tank system for leakage. P-1-M-6140 17.3.-1

9.6.2.3. Run a subsea TV or ROV down the length of the marine riser, flex joint and BOP stack on both sides. When there is doubt or visibilityis poor, close the BOP rams and check if the level still drops whenthe hole is isolated from the riser system.

P-1-M-6140 17.3-2

9.6.2.4. If there is still mud losses, the cause of the lost circulation may bepressure surges due to running in the pipe too fast or thebit/stabilisers have balled up. Stop tripping and circulate the well.

P-1-M-6140 17.3-3

9.6.2.5. If full returns are observed, resume tripping to bottom. P-1-M-6140 17.1.3

9.6.2.6.If full returns are not established, the well must be kept full withmud or water, depending on the severity of the losses. Circulationmay be restarted by one of the methods listed previously.

P-1-M-6140 17.1.3

9.6.3. Use of LCM pills P-1-M-6140 17.1.4

9.6.3.1. If tripping is considered safe (i.e. the hole stands full of mud), runopen ended drill pipe to immediately above the thief zone.

P-1-M-6140 17.1.4

9.6.3.2. Pump the LCM pill and displace half of it in the hole (minimum pillvolume: 10m3 for a 81/2” hole; 20m3 for a 121/4” hole) and pull thepipe above the pill.

P-1-M-6140 17.1.4

9.6.3.3. Continue pumping the rest of the pill using the ‘Hesitation’Technique and visually check the fluid level all the time.

P-1-M-6140 17.1.4

9.6.4. High filtration pills P-1-M-6160 17.1.4

9.6.4.1. Once pumped the pill must be squeezed in formation to increasefiltration effect.

9.6.4.2.4 When running in hole after a high filtration pill extreme cautionmust be adopted to avoid stuck pipe.

9.6.4.3. Use open end drill pipes to pump high filtration pill.

9.6.5. Cement plug

9.6.5.1. Refer to OP.2.7.3.1



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10. SHALLOW GAS Reference

10.1. Where there is a risk of shallow gas, the use of a floating vessel or a jack-up in floating mode which can move efficiently off location,is recommended.

P-1-M-6150 9

10.2. Primary well control is the only means to protect wells from blowingout, because secondary well control techniques are not normallyapplicable in top hole drilling operations.

P-1-M-6150 9.2

10.3. Prevention

10.3.1. Review existing documentation for the area in question.

10.3.2. Ensure that all personnel involved in drilling operations are trainedon the subject.

10.4. Recommended Drilling Practices

10.4.1. General Practices

10.4.1.1. Before spudding the well, a meeting should be held in order toalert key personnel (Drilling Contractor personnel, mud engineer,mud logging operator included)

P-1-M-6150 9.3.1-h

10.4.1.2. Drilling control (parameters, levels, gas detectors, tripping, etc.)

should be strengthened for this phase.

P-1-M-6150 9.3.1-h

10.4.1.3. A stock of kill mud based on hole size, and for off-shore rigs, water depth and riser size shall be prepared before commencement of drilling.

The correct mud weight must be determined for the particular areais being drilling.

P-1-M-6150 9.3.1-g

10.4.1.4. A 121/4“ or smaller pilot hole shall be drilled in areas with possible

shallow gas.

P-1-M-6150 9.3.1-a

10.4.1.5. Restrict the penetration rate (recommended ROP = one joint/hr).P-1-M-6150 9.3.1-b

10.4.1.6. The drill string disconnecting and releasing procedure should beavailable and known to all relevant personnel in order that they arecarried out efficiently without causing any delays in moving off location.

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10.4.1.7. All efforts shall be made to minimise the possibility of swabbing.Pumping at the optimum circulating rate is recommended for all

upward pipe movements (e.g. making connections and tripping). Inlarger hole sizes especially (i.e. larger than 121/4”) it is important tocheck that the circulation rate is sufficiently high and the pullingspeed sufficiently low to ensure that no swabbing will occur.

P-1-M-6150 9.3.1-c

10.4.1.8. The minimum required number of stabilisers should be used. P-1-M-6150 9.3.1-c

10.4.1.9. Flow checks are to be made :

• Before tripping.

• At any time a sharp penetration rate increase or tank levelanomaly is observed, when any anomaly appears on LWD

log (if used).

• At any specific depth referred to in the drilling programme.

• At each connection while trip in and out.

P-1-M-6150 9.3.1-d

10.4.1.10. A float valve must be installed in all bottom hole assemblies whichare used in top hole drilling.

P-1-M-6150 9.3.1-e

10.4.1.11. Use largest mud pump liners and no nozzles.

10.4.1.12. Shallow kick-offs should be avoided in areas with probable shallowgas. Top hole drilling operations in these areas should be simple

and quick, to minimise possible hole problems.

P-1-M-6150 9.3.1-f

10.4.1.13. Accurate measurement and control of drilling fluid is important inorder to detect gas as early as possible.

P-1-M-6150 9.3.1-d

10.4.1.14. In the event that significant gas readings are obtained from mudreturns, the gas should be circulated out.

If the background gas level cannot be reduced by circulation, themud weight should be increased and the hole circulated until thebackground gas subsides.

10.4.2. Logging P-1-M-6150 9.3.2

10.4.2.1. Information about the presence and depth of possiblehydrocarbons can be obtained from electric wireline logs or LWD,the latter being the preferred method since early detectionobviously enhances the safety of the operation.

P-1-M-6150 9.3.2

10.4.2.2. LWD is the only currently downhole tool capable of shallow gasdetection by means of resistivity and gamma ray recording.

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10.4.2.3. In development drilling the use of a diverter system is stillrecommended if there is a chance of colliding with another well or

if there is a possibility of penetrating charged sands from leakingor poorly cemented casing strings.

P-1-M-6150 9.3.2

10.4.2.4. Shallow gas detection, with electrical wireline logging or LWD, isnot always reliable or conclusive. Excessive hole size and thepresence of fresh formation water may mask the shallow gaseffect during recording.

P-1-M-6150 9.3.2

10.4.3. Losses P-1-M-6150 9.3.3

10.4.3.1. Losses should be avoided during drilling with a diverter systeminstalled.

If losses are encountered, they are to be cured using lostcirculation material or cement. Full returns are to be regainedbefore proceeding to drill ahead.

P-1-M-6150 9.3.3

10.4.3.2. If the losses cannot be cured, possible courses of action includeplugging back with cement, either to anticipate casing settingdepth.

P-1-M-6150 9.3.3

10.4.4. Cementing Operations P-1-M-6150 9.3.4

10.4.4.1. In addition, and where applicable, it is recommended that the BOP

stack remains nippled up with a small annular pressure maintainedduring WOC time.

P-1-M-6150 9.3.4

10.5. Drilling Procedures P-1-M-6150 9.3.5

10.5.1. Running and cementing the 30” casing in a pre-drilled hole, after having drilled a pilot hole, is the recommended technique in areaswhere shallow gas might be encountered.

P-1-M-6150 9.3.5

10.5.2. In floating top hole drilling operation if the formation strength at the30” shoe is considered insufficient the use of the marine riser and

diverter system has to be ruled out and riser less drilling should beemployed.

P-1-M-6150 9.3.5



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10.5.3. 20” Casing:

There are three main methods used to drill 26” hole in shallow gasarea:

• Drill pilot hole and open the hole without riser.

• Drill pilot hole and open the hole through the riser withunderreamer.

• Drill pilot hole, pull the riser and open the hole.

Drill pilot hole through a marine riser with return to seabed via asub sea exhaust valve (or dump valve) or subsea diverter.

P-1-M-6150 9.3.5

10.5.4. Operation Without The Riser:

Riser less drilling is considered to be the safest way to cope withthe shallow gas problem since the vessel can quickly move awayfrom a subsea blow-out. The risk of riser less drilling increaseswith decreased water depth

P-1-M-6150 9.3.5

10.6. Diverter assembly

10.6.1. See OP.02.09.

10.6.2. Diverter System Operating Procedures

10.6.2.1. The diverter system shall be used for all wells unless there is clear information of the absence of potential shallow gas.

P-1-M-6150 9.4

10.6.2.2. The diverter system should never be completely closed-in andused as a BOP in an attempt to control the well as they are notdesigned to hold pressure but only to direct flow overboard.

P-1-M-6150 9.4

10.6.2.3. The blow out contingency plan should be implemented as soon asit becomes apparent that the well cannot be dynamically killed.

P-1-M-6150 9.4

10.7. Diverter procedures

10.7.1. At the first sign of flow, the following actions are required P-1-M-6150 9.4.3

10.7.2. Pump the original mud or water immediately at maximum pumprate.

P-1-M-6150 9.4.4

10.7.3. Stop drilling. P-1-M-6150 9.4.4

10.7.4. Activate the diverter function (start to evacuate the non-essentialpersonnel).

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10.7.5. If the well is still flowing, pump heavier mud at maximum pumprate.

P-1-M-6150 9.4.4

10.7.6. If the well continues to flow after the heavier mud has beenpumped, carry on pumping other mud or water at the maximumrate.

P-1-M-6150 9.4.4

10.7.7. Further dynamic kill attempts may be as follows P-1-M-6150 9.4.4

10.7.7.1.1. Mix heavier mud whilst pumping mud or water at maximum rate. P-1-M-6150 9.4.4

10.7.7.1.2. Pump heavy mud at maximum rate. P-1-M-6150 9.4.4

10.7.7.2.Repeat sequence if dynamic killing is still unsuccessful, but do notuse excessive mud weight which could result in formationbreakdown.

P-1-M-6150 9.4.4

10.7.7.3. Shutting down the pumps to check for flow may result in an evengreater influx flow rates. Continuous pumping is recommendedespecially if there is a suspicion of flow.

P-1-M-6150 9.4.4

11. HANG-OFF Reference

11.1. Procedure for hanging of f w ith hang off tool

11.1.1. The preferred method to hang off the string is to use a hang off

tool which supports the pipe in the casing in the wellhead.

If the seat protector is installed, the hang-off on pipe rams has tobe considered (an appropriate top sup to disconnect the drill stringhas to be available).

11.1.2. Stop drilling and circulate bottoms up, if time permits.

Consider increasing mud weight below the mud line to balance thewell with the riser disconnected.

11.1.3. Pull out enough drill pipe to keep the bit inside casing shoe whenthe hang-off tool is landed on its seat.

11.1.4. If tripping, run or pull as much pipe as possible to get the bit to thepoint which is the same distance above the casing shoe as therotary table is above the seabed

11.1.5. Install a Gray inside BOP one stand below the hang off tool if hanging off inside casing.

11.1.6. If hanging-off in open hole, do not install a Gray inside BOP, butuse a retrievable drop-in back-pressure valve.



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11.1.7. The hang-off assembly must be made up and standing in derrickat all times while BOP stack is on bottom.

11.1.8. Hang-off procedure

• Close and lock the pipe rams.

• Back off right hand release sub on hang off tool.

• Pull the landing string above shear rams.

• Close and lock blind/shear rams.

• Displace riser with seawater.

• Prepare to disconnect LMRP.

11.1.9. A mark should be painted on the anchor lines and guidelines as a

reference for later repositioning of the rig.

11.2. Procedure for re-connect ing wi th hang of f tool

11.2.1. Re-connecting procedure:

• Install new ring gasket on connector.

• Upon latched the connector test choke and kill lines againstfailsafes.

• Run running string approximately 10m (30ft) above theblind/shear rams and displace riser with mud via runningstring or booster line.

• Check for pressure between shear and pipe rams and in theannulus through kill/choke line

• If no pressure open blind/shear rams, stab and make uprunning string.

• If any pressure is detected, follow well control policy.

• Open pipe rams and circulate bottoms up.

• Pull out and remove hang off tool assembly and Gray insideBOP.

11.3. Emergency Procedure for hanging off on p ipe rams

11.3.1. If there is not enough time to run the hang-off tool, the drill stringcan be sheared and hung off on the pipe rams.

11.3.2. Procedure:

• Close hang off pipe rams (below shear rams) withmanufacturer’s reduced operating pressure

• Lower and land pipe on tool joint

• Increase closing pressure to 1,500psi and lock the rams

• Be prepared to shear pipe if LMRP disconnect is required



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11.4. Hanging off with casing

11.4.1. Casing running shall not be commenced if adverse weather isforecast.

11.4.2. If casing running is taking place and there is not enough time torun casing to TD, the hang off procedure must be considered:

• Pull back or run into previous casing shoe.

• Make up the casing hanger.

• Remove casing hanger lock ring and land in the wellhead.

• Release running tool pull above shear rams.

• Close shear rams.

12. H2S DRILLING PROCEDURES Reference

12.1. In presence of H2S an adequate quantity of H2S scavenger mustbe added to the mud.

12.2. A copy of the specific handbook reporting testing and checkingprocedures must be available on the rig.

12.3. When back on bottom after tripping with H2S formations exposedto the open hole, be alert as bottoms up nears the surface and usepersonal protective means to take sample at the shale shakers.

Reference List :



‘Drilling Fluids Operations Manual’ STAP-P-1-M-6160

‘Drilling Jar Acceptance and Utilisation Procedures’ STAP-M-1-M-5003



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Depth From Surface in feet

Pipe OD ins 0 to 3,0003,000 to

6,000

6,000 to

9,000

9,000 to

12,000

Over

12,000

23/8 1 1 1 2 2

27/8 1 1 2 2 3

Tubing 31/2 1 1 2 2 2

4 to 41/2 2 2 2 3 3

23/8 to

7/8

1 2 2-3 3-4 4-6

31/2 to 4 2 3 3-4 4-6 5-8

Drillpipe 41/2 to 6

9/16 2 3-4 4-6 5-9 6-12

65/8 3 4-5 5-7 6-10 7-14

31/2 to 4 2-4 2-5 3-7 3-8 4-9

41/8 to 5

1/5 2-4 3-6 4-8 4-10 5-12

Drill Collar 53/4 to 7 3-6 4-8 5-10 6-12 7-15

71/4 to 8

1/2 4-6 5-9 6-12 7-15 8-18

71/4 to 9

3/4 6-12 8-12 8-15 8-18

41/2 to 51/2 3 3 3 3 3

6 to 7 3 3 3 4 4

Casing 75/8 4 4 4 4 5

75/8 5 5 5 5 5

95/8 5 5 5 6 6

103/4 6 6 6 7 7

Table OP 2.6 - Recommended Strands of 80gr/ft RDX Primacord for String-Shot



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Table OP 2.7 - Lost Circulation Control Techniques

A L M O S T T O T A L

m o r e t h a n 5 0 %

S P O T P I L L S

W I T H L C M

H I G H

F I L T R A T I O N

M I X T U R E

G E L C E M E N T

D O B C


S T I F F - F O A M

S E E P A G E

L O S S

l e s s t h a n 5 0 %

S U R F A C E

A R E A S

H I G H L Y

P E R M E A B L E

F R A C T U R E S


F L U I D A N D H I G H

G E L S


F L U I D

- L C M I N C I R C

U L A T I O N

- H I G H F I L T R A T I O N F L U I D

S P O T P I L L W I T H L C M

H I G H / V E R Y H I G H F I L T R A T

I O N

M I X T U R E

T O T A L

F R A C T U R E S

H I G H

F I L T R A T I O N

M I X T U R E

C E M E N T / G E L

C E M E N T

S L U R R I E S

D O B C

C A V E R N S

G E L - C E M E N T

S L U R R I E S

C E M E N T +

G E L S O N I T E

D O B C

H Y D R A U L I C A L L Y - I N D U C E D

F R A C T U R E S

L O W

D E N S I T Y

F L U I D S

S E T T I M E L O W

L O A D I N G

H I G H

F I L T R A T I O N

M I X T U R E

D O B

D O B C


S T I F F - F O A M

H I G H D E N S I T Y

F L U I D S

F L U I D T H I N N I N G

A N D / O R

U N W E I G H T I N G

H I G H F I L T R A T I O N

M I X T U R E

F R A C T U R E S


S T I F F - F O A M



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OP. 2.13. WELL ABANDONMENT

1. GENERAL INFORMATION Reference

1.1. Cement plugs, set when abandoning wells, should be made fromneat slurries whenever possible.

When static bottom hole temperature exceeds 110°C, useGeoterm type cement.

P-1-M-6140 14.2.3-1

1.2. Spacers should be used ahead and behind the slurry.

Special consideration should be given to the composition andvolume of the spacers when the mud is oil based, calcium chlorideor lignosulphonate treated.

The spacers should be normally 100 m long.

P-1-M-6140 14.2.3-2

1.3. The slurry volume should be calculated using a calliper log, if available. When a calliper log is not available, use a slurry volumeexcess based on local experience.

P-1-M-6100 14.2.3-3P-1-M-6140 14.2.3-3

1.4. If the hole is badly washed out or when potential losses areexpected, it is preferable to set two short plugs instead of one longone.

P-1-M-6100 14.2.3-4P-1-M-6140 14.2.3-4

1.5.Plug exceeding 200m should not be set in one stage.

P-1-M-6140 14.2.3-3

1.6. As soon as the plug is set, pull out slowly 30-50 meters abovetheoretical top and circulate.

P-1-M-6100 14.2.3-8P-1-M-6140 14.2.3-8

1.7. Using drilling or workover rig, all cement plugs shall be set using atubing stinger, each cement plug shall be located and verified,(WOB: 20,000-40,000 lbs, depending on hole size).

P-1-M-6100 14.2.3-11P-1-M-6140 14.2.3-11

1.8. Slurry volume calculations in squeeze cement jobs assumeroughly, 100 litres slurry per meter of perforated zone into the

formation.

P-1-M-6100 14.2.2P-1-M-6140 14.2.2

1.9. A small amount of back pressure, choking the return, should beapplied on the annulus to prevent the slurry level to fall caused by‘U’ tubing.

1.10. Displacement should be calculated in order to spot a balancedcement plug (hydrostatic heads inside the string and outside in theannulus shall be the same).

P-1-M-6140 14.2.3-6



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1.11. An under displacement of 1 or 2 bbl is suggested to help drainingthe slurry off the pipe when pulling out of hole

P-1-M-6140 14.2.3-7

1.12. All cement plug shall be set using a tubing stinger P-1-M-6140 14.2.3-5

1.13. 31/2” OD internal and external flush tubing is recommended as a

tailpipe, particularly when long plugs has to be set, otherwise donot use less than 27

/8”.

1.14. Once the calculated volume of cement slurry has been placedbehind the casing, pull the stinger out without equalising pressure.

1.15.The tubing tailpipe has to be retrieved from the cement very slowlyto avoid contamination

1.16. Records shall be kept of all plugs set and the results of tests shallbe available for inspection.

P-1-M-6140 14.2.3-12

1.17. Before starting with any casing cutting, verify the annulus pressure

1.18. After casing cutting, a complete annulus circulation shall be madeto reduce friction and balance the mud.

P-1-M-6140 14.3

1.19. A cement plug, at least 150 meters long, shall be placed with itstop 50 meters below the seabed (off-shore), or ground level (on-shore).

P-1-M-6140 14.2.2

1.20. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below seabed, using mechanicalcutters.

P-1-M-6140 14.2.2

2. TEMPORARY ABANDONMENT Reference

2.1. During Drilling Operations

2.1.1. Any drilled well which is to be temporarily abandoned shall becemented with Drilling Kill Weight mud below the plug.

P-1-M-6140 14.1.1

2.1.2. All hydrocarbon zones shall be isolated with a cement plugextending at least 50m above and below the zone.

P-1-M-6140 14.1.2-1



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2.1.3. Where there is an open hole below the deepest string of casing, acement plug shall be placed in such manner that extends at least

50m above and below the casing shoe.

The top of the cement plug shall be located and verified bymechanical loading.

P-1-M-6140 14.1.2-1

2.1.4. If the condition of the formation makes cementing difficult, a bridgeplug may be positioned in the lower part of the casing but not morethan 50m above the shoe

A cement plug at least 20m in length shall be placed on top of themechanical plug.

P-1-M-6140 14.1.2-1

2.1.5. Uninteresting perforated zones:These intervals shall be isolated by means of a mechanical plugand shall be squeeze cemented. If the condition of the formationmakes cementing difficult a cement plug 50m high will be set ontop of the mechanical plug.

P-1-M-6140 14.1.2-2

2.1.6. Interesting perforated zones:

These intervals shall be isolated by means of a mechanical plug.

Then a cement plug shall be set at least 50 - 100m in length intothe casing, depending on casing diameter, from 5 - 50m below the

sea bottom.

P-1-M-6140 14.1.2-2

3. SAND PLUG Reference

3.1. If not available, the bottom hole temperature must be recorded.

3.2. Analyse the water pH.

3.3. Internal and external flush tubing should be used, 31/2” OD when

possible in any case never less than 27/8”.

3.4. The gelling agent must be added very slowly to avoid lumps andfish eyes.

3.5. The use of a blender is recommended.

3.6. Sand slurry must be separated from the completion fluid bycushions.

3.7. If the plug to be set is more than 300ft high, the operation has tobe performed in stages.

3.8. Keep the string rotating during the sand slurry displacement.



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3.9. Like a cement plug, do not reach the balanced plug conditionduring displacement, under-displace a little to have a hydrostatic

head higher than in the annulus to compensate displacementwhen the pulling the tubing.

3.10. The consistency of the sand plug must be tested by running a bitand slacking off weight.

4. CASING PATCH Reference

4.1. Prior to running a casing patch in the hole, run a taper mill and/or string mill of the same ID as the casing to properly gauge the holeand clean the area where the casing patch is to be set.

4.2. The string configuration and rigidity has to be similar to the stringfor running the casing patch.

4.3. Condition the mud to prevent solids from settling out of the wellfluid during the patch setting operations.

4.4. Check and record any and all abnormal weight readings whilerunning in and pulling out.

4.5. Watch the M/D carefully when running the hole patch and stop assoon as a loss in weight is noticed.

4.6. Do not force a casing patch string when there is unexpected drag.

4.7. When an accurate setting depth is required, correlation with aneutron log must be conducted.

4.8. A taper mill of correct OD has to be run to gauge the casing patchafter it has been set.

5. PERMANENT ABANDONMENT Reference

5.1. Explorative wells

5.1.1. Open hole

5.1.1.1. All permeable zones shall be plugged individually to avoid anycross flow.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

5.1.1.2. Cement plugs shall be set with top and bottom at least 50 metersabove and below each zone.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

5.1.1.3. The top of the cement plugs shall be located and verified bymechanical loading.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2



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5.1.2. Casing shoe

5.1.2.1. Last casing string above open hole shall be sealed with a cementplug, it shall extend at least 50meters above and below the shoedepth.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

5.1.2.2. Plug shall be tested by mechanical loading. P-1-M-6100 14.1.2P-1-M-6140 14.1.2

5.1.3. Liner head

5.1.3.1. At the hanging point of the liner a cement plug shall be set, it isextending at least 50meters above and below the top of liner.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

5.1.4. Casing cutting

5.1.4.1. The casing shall be cut at least 100meters above the shoe of theprevious casing string and a cement plug shall be placed in suchmanner that extends at least 50 mertres above and below thecasing cut point.

P-1-M-6100 14.3P-1-M-6140 14.3

5.2. Completed wells

5.2.1. Onshore Wells with pressure in the annulus casing/casing

• Check and record the wellhead pressure

• Pressure the test BOP and lubricator to 500psi above staticwellhead pressure

• Condition the packer fluid versius completion fluid

• Have two circulating heads ready to speed up the tubing tailretrievement from cement slurry after the cement plug hasbeen set.



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5.2.1.1. Case I° (Casing with top of cement below the surface) Phase one:

5.2.1.1.1. Open hole:

• By pulling unit to retrive both packer and completion string

• By coiled tubing to seal the last casing string above open holewith a cement plug: it shall extend at least 50 meters aboveand below the shoe depth.

• If it is impossible to retrieve the packer, a cement squeeze willbe performed in the formation below the packer.

• Proceed with cutting and retrieving of the completion stringabove the packer.

• If the squeeze is not allowed, in HPHT wells, a bridge plug will

be set in the completion string below the packer, thecompletion string above the packer will be retrieved and acement plug on the packer wil be performed.

• In the other wells, if the squeeze is not allowed, to retrive thecompletion string above the packer and to perform a cementplug on the packer.



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5.2.1.1.2. Perforated casing zones:

• Perforated zones shall be isolated with mechanical plug andshall be squeeze cemented.

• Before setting either both cement or mechanical plugs, to clear the internal of the casing using taper mill.

• Prior to running a CR in deep holes, make sure to haveenough rig pulling force capacity to release the CR setting tool.

• Run a cement retainer below the perforation to spot a water cushion across the perforation prior to setting a CR above thelevel to be abandoned.

• A cement retainer will be set maximum 10-15 meters abovethe perforations.

• When an accurate setting depth is required, a CR should be

run and set on electric wireline.• After the CR has been set, perform a hydraulic test by

pressurising the annulus to 500-1,000psi and mechanically byslacking 5-10 ton weight on it.

• An injection test has to be performed beginning with water across the perforations and using different rates.

• Consider the bottom hole pressure to avoid reaching thefracture gradient when displacing slurry to bottom.

• During squeeze operations with a CR, monitor the annulusreturns.

• A 50 meters long cement plug shall be placed above the

cement retainer, the length of this plug may be reduced toavoid any interference with any upper perforated intervals.

• Do not reach the balanced plug condition when displacing,underdisplace to obtain a hydrostatic head in the string slightlyhigher than in the annulus to compensate tubing displacement.

• Displacement of cement slurry should be done with the BOPclosed and return under the choke to avoid the U-tube effect.

• Instead of point 4.3.1.2.1, a cement plug shall be placed withupper and lower ends located at least 50meters above andbelow the perforated zone. This solution must be consideredas a contingency.

• The cement slurry volume will be calculated in order to have

cement from the bottom of the perforations to the cementretainer and a minimum of 100 litres slurry per metre of perforated zone.

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

P-1-M-6140 12.6.2

P-1-M-6100 14.1.2P-1-M-6140 14.1.2

P-1-M-6100 14.2.2

P-1-M-6140 14.2.2

5.2.1.2. Case I° (Casing with top of cement below the surface) Phase two:

5.2.1.2.1. In both cases Open hole and Cased hole, 20/30 day later, returnon the well with a workover rig and verify the hydraulic seal of theplugging previously performed.

5.2.1.2.2. All casing will be retrieved as much as possible



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5.2.1.2.3. The casing shall be cut at least 100 m above the shoe of theprevious casing string and a cement plug shall be placed in such away to cover the casing at least 50 metres above and below thecasing cut point.

P-1-M-6100 14.2.2P-1-M-6140 14.2.2

5.2.1.2.4. To set cement plug use a tailpipe at least as long as the height of the cement plus the cushion in front in the annulus.

5.2.1.3. Case II° (Casing with top of cement at the surface) Phase one:

5.2.1.3.1. Same as per case I° phase one

5.2.1.4. Case II° (Casing with top of cement at the surface) Phase two:

5.2.1.4.1. If the annulus casing/casing is cemented, will be made windows ina adequate zones.

5.2.1.4.2. A water cushion should be left across the areas to be treated

5.2.1.4.3. Position in the window an inflettable packer to insulate thepressures.

5.2.1.4.4. After a 50 m long cement plug shall be placed above the inlettable

bridge plug.

5.2.2. Onshore Wells without pressure in the annulus casing/casing

5.2.2.1. The cement plug test will be performed by pressurising the top of the plug with a 1500 psi differential pressure.

5.2.2.2. If the top of cement is under the shoe of the previous casing, it willbe mandatory to carry out a cement plug 100 m long in theannulus casing/casing by circulating through the casingperforations.

5.2.2.3. Several levels with the same hydraulic regime (homogeneousformations, pressure and production fluid) can be plugged bymeans of two cement plugs, provided the lower extends at least50 m below the bottom of the deeper level and the upper extendsat least 50 m above the top of the higher level

5.2.2.4. Between such two plugs it will be placed a fluid with the samecharacteristics of that one used during the running of theproduction casing



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5.2.2.5. If SBHP is lower than hydrostatic pressure of the production fluid,all annuli will be cemented to surface and the completion string willbe totaly abandoned in the well.

5.2.2.6. In the other situations, the completion string will be rercovered upto 50 m under the shoe of the surface casing or in any cases notdeeper than 250 m from surface.

5.2.3. Offshore Wells with pressure in the annulus casing/casing


5.2.3.2. Both for explorative and completed offshore wells the wellabandonment will be carried out following the procedure (abovespecified) for onshore well, making distintion between the twocases (pressure or not in the annulus), but performing theoperation in one unique phase.

5.2.3.3. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below seabed, using mechanicalcutters.

5.2.4. Offshore Wells without pressure in the annulus casing/casing


5.2.4.2. Both for explorative and completed offshore wells the wellabandonment will be carried out following the procedure (abovespecified) for onshore well, making distintion between the twocases (pressure or not in the annulus), but performing theoperation in one unique phase.

5.2.4.3. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below seabed, using mechanicalcutters.

Reference List :





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OP3. COMPLETION AND WORKOVER OPERATIONS

OP. 3.1. GENERAL

1. BOP STACK AND TESTING Reference

1.1. The BOP stack configuration including ram sizes should be inaccordance with the Well Programme.

1.2. After the BOP stack has been installed, the DS shall produce asketch of the BOP including the size and location of the rams andthe depths referred to RKB and send it with the BOP Test Report.

P-1-M-6140 3.1.2

1.3. The function and pressure tests will be recorded on a chartrecorder and the charts held in file.

P-1-M-7120 4.3f

1.4. The test schedule will be according to local regulations but will beat least every 14 days. If operational constraints prevent ascheduled pressure test, a dispensation will be requested andissued by the authorities and held on file

P-1-M-7120 4.3e

1.5. In workover operations prior to pulling the tubing, the BOP stackwill be tested against plugs set in the tubing hanger.

P-1-M-7120 4.3g

1.6. BOP test af ter the completion has been pulled

1.6.1. Use a test tool when pressures are lower than the internal casingyield pressure.

1.6.2. Use a tubing hanger and plugs installed in the tubing spool whentest pressures are higher than the internal casing yield pressure.

1.6.3. Depending on the type of completion to be pulled the appropriaterams will be installed into BOP:

On single completion install concentric rams

On dual completion single pulling string use off set rams

On dual completion when simultaneously pulling both strings use

dual rams plus centralisers rams.

1.6.4. Any time the BOP stack is nippled up and after repairingoperations, all BOP operating equipment hoses, control panels,regulator connections, shall be checked and tested to themaximum manufacturer's recommended pressure for closing andopening the BOP's .

P-1-M-6150 7.4.3



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1.6.5. All BOP components shall be pressure tested with a test plug to alow pressure of 300psi (21kg/cm2) and then to the following

pressures:

The lower connector, against one set of pipe rams, to the ratedWP of the wellhead or the ram type preventer, whichever islower.

All the other components, to a minimum pressure equal to, themaximum anticipated wellhead pressure, or 70% of theinternal yield pressure of the weakest item of equipment,whichever is the lower.

P-1-M-6150 6.3.1

1.6.6. The BOP 300psi low pressure tests will be performed first. Theyare to be held for a min period of 5min. If the BOP does not pass

the low pressure test, do not carry out the high pressure test.

P-1-M-6150 7.3.1

1.6.7. It is recommended that high pressure tests are held for a minimumof 10min. The maximum acceptable pressure drop over this 10minperiod is 100psi.

P-1-M-6150 7.3.1

1.6.8. Hold pressure for 10min. The acceptable pressure drop is 100psiof the initial pressure before stabilisation, unless local legislationdictates otherwise.

M-1-S-S-5703P-1-M-7120 4.3c

2. WELL CONTROL Reference

2.1. Well Control Drills P-1-M-6150 8.3

2.1.1. Pit Drills:

The purpose of this drill is to ensure that the drill crews are familiar with the Soft Shut-In procedure implemented in the event of takinga kick while drilling.

2.1.2. Particular care has to be taken during the crew change, make sureall information is handed over.

2.1.3. The Company Drilling and Completion Supervisor shall be present

on the rig floor at the beginning of every trip to check for fill-up.

P-1-M-6140 7.1

2.1.4. Always use the trip tank (tripping in and out) and accurately recordvolumes to make sure the hole is taking/giving the proper amountof fluid.

P-1-M-6140 7.1

2.1.5. After nippling up a BOP stack, minimum requirements for kill mudcannot be specified. The volume and density of kill mud shall beadjusted to the well pressure prognosis and pit volumes availableon the rig.

P-1-M-6140 6.5



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2.1.6. Properties of reserve and kill mud should be checked andmaintained daily and recorded the mud report.

P-1-M-6140 6.5

2.1.7. Safety valves have been tested and are available already made upand in open position with the crossovers to the workstring andWeco connections to suit the kill line connection.

P-1-M-7120 4.1f

3. FLUID LOSS CONTROL Reference

3.1. When lost circulation is encountered, some specific informationregarding the situation is required prior to initiating correctiveprocedures.

P-1-M-6140 17.0P-1-M-6160 6.2

3.2. An automatic pit level device shall be installed and operational, at

all times, on all mud pits and on the trip tank. A pit volume recorder shall be continuously working on the rig floor and on the MudLogging Unit.

P-1-M-6150 6.2

3.3. Always use the trip tank (in and out) and accurately recordvolumes to make sure the hole is taking/giving the proper amountof fluid. If any discrepancy is observed, the Driller shallimmediately inform the Tool Pusher and Company Drilling andCompletion Supervisor.

P-1-M-6150 6.2

3.4. Prior to using a LCM pill, consideration will be given to reducingthe hydrostatic head by reducing the brine weight (with drill water)

and so reduce the level of losses. This will only be attempted if thereduction in weight does not compromise the safety of the well.

P-1-M-7120 4.9

3.5. LCM pills used in completion operations should be selected inorder minimise potential damage to producing formations.

P-1-M-7120 4.9

3.6. If fluid loss control is needed and no results are obtained with aviscous pill, calcium carbonate or others specific bridging agentsshould be used.

P-1-M-6160 6.4

3.7. Viscous Pills

These can be built, either, using drill water, completion brine or ahigher weight brine as a base and adding a predispersed liquidviscosifier to increase the funnel viscosity according to the wellprogramme.

P-1-M-7120 4.9.1

3.8. Sized Salt Pills

The actual composition of the sized salt pill will be determinedprimarily by the porosity, permeability and temperature of theformation to be bridged.

Sized salt pills must be formulated in a saturated brine base toprevent solution of the bridging material.

P-1-M-7120 4.9.1



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3.9. Calcium Carbonate Pills:

Calcium carbonate can be used as a drilling fluid and for LCM pillsto control fluid losses. In completion operations it is now the mostcommonly used fluid for controlling fluid losses within Eni-Agip’operations.

P-1-M-7120 4.9.1

3.10. Avoid reverse circulate whenever possible.

3.11. Do not close blind rams after a trip and keep hole under control if necessary with the trip tank on.

3.12. Minimum stock requirements for mud weighting materials,chemicals, pipe freeing agent, dispersant, lost circulation material,

cement, kill and reserve mud on the rig, depends on the wellpressure prognosis, severity of potential drilling problems and rigload capacity.

P-1-M-6140 4.7.2

3.13. During well completion and workover operations, all steps must betaken to ensure that, if any fluid is in contact with the formation, itis both clean and filtered. A fluid in any other condition will, for thereasons stated above, result in some degree of formationimpairment.

P-1-M-7120 4.1f

Reference List :





‘Acceptance Minumum Requirements for BOP and Well Contrl

Equipment’ STAP –M1SS-5703



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OP. 3.2. WELL PREPARATION

1. CASING CLEANING Reference

1.1. A suitably sized bit, or junk mill, and tandem scraper assembly willbe run to clean out the casing or liner of any excess cement, andto scrape the intended perforated interval(s).

P-1-M-7120 4.2

1.2. Solids control shall be performed using the appropriate equipment,whenever needed. Maintain the right pressure on the desander and desilter manifold for maximum performance.

P-1-M-6150 6.2

1.3. Prior to displace fluid in hole, empty all surface lines and pits andwash with proper solution or solvent.

1.4. Cushions have to be used to separate mud from the completionfluid.

1.5. When pressure allows displacement should be done in reversecirculation.

1.6. A second series of washing cushions can be circulated once thehole is completely filled with completion fluid.

1.7. Use of acid cushion to remove casing scales to be considered.

2. COMPLETION AND PACKER FLUIDS Reference

2.1. Definitions

2.1.1. Completion fluid:

It is the fluid in the well during the installation (or the removal) of the completion.

2.1.2. Packer fluid:

It is the fluid in the casing/tubing annulus above the upper packer after the packer has been set. Packer fluid can be either the samefluid used while running the completion (completion fluid) or any

other fluid displaced in the annulus above the upper packer after the completion operation. Packer fluid may sometimes be ‘non killweight fluid’.

2.2. Completion fluid P-1-M-7120 4.7

2.2.1. Hydrostatic pressure has to control formation pressure (300psiminimum overbalance).

P-1-M-7100 7.3.6

2.2.2. Completion fluid, if not solids free, has to be conditioned in order toavoid solid settling.

P-1-M-6160 4



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2.2.3. Rheology shall be checked three times a day or more frequently if requested by Company Drilling and Completion Supervisor.

P-1-M-6150 6.2

2.3. Packer fluid

2.3.1. Characteristics have to be stable over time.

2.3.2. Fluids have to be treated with anticorrosive additives. P-1-M-7100 7.3.6

3. BRINE Reference

3.1. Brine handling

3.1.1. Rig personnel involved must be aware of brine properties.

3.1.2. Proper safety equipment as plastic hand gloves, goggles andrubber boots should be wear when handling and mixing heavybrine.

3.1.3. A breathing mask have to be used to avoid breathing salt dust.

3.1.4. Do not expose skin to salt dust or liquid.

3.1.5. As heavy brine solution is hygroscopic, density must be checkedfrequently in dump weather condition.

3.1.6. Check mud system butterfly isolating valves when changing frommud to brine.

3.2. Brine filtration

3.2.1. A pit of brine will not be filtered by circulation on itself. P-1-M-7120 4.8.1

3.2.2. All filtered brine will be checked to ensure that it meets therequired level of cleanliness.

P-1-M-7120 4.8.1

3.2.3. Filter brine from the dirty pit to a dedicated clean tank, or pump

directly into the well.

P-1-M-7120 4.8.1

3.2.4. Monitor ∆P across the two filter units to control system efficiency.

3.2.5. The prime filtration system is the Diatomaceous Earth filter presswith a bag filter system for use as a downstream guard filter

P-1-M-7120 4.8.1

3.2.6. First filtering stage has to be performed with a DE filter unit. P-1-M-7120 4.8

3.2.7. Cleanliness must be checked at the casing return and downstreamthe filter unit.



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4. CMT LOGGING Reference

4.1. After a cement job is completed, 72 hours is the minimum WOCtime before a cement evaluation log is to be run.

4.2. A shooting nipple with stuffing box has to be installed if the well isopen to the reservoir.

4.3. The contractor has to specify the emergency cable cuttingprocedure.

Reference List :







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OP. 3.3. WELLBORE COMPLETION

1. PERFORATING Reference

1.1. Preliminary

1.1.1. The Contractor shall specify all the equipment and accessory thatshall be utilised to perform the service (appendix 3 of technicalspecifications) and the crew composition (appendix 2 of technicalspecifications )

1.1.2. A copy of the Perforating Contractor’s Safety Procedure on GunHandling and Running shall be made available on site.

1.2. General Notes

1.2.1. A safety meeting must be held with all the personnel involved inthe operations.

P-1-M-7120 5.1

1.2.2. Verify with the service personnel the shot density, phasing andperforation intervals as per Eni-Agip programme.

1.2.3. The first casing perforation shall be performed in daylight.Subsequent series of shots can be carried out at any time.

P-1-M-7120 5.3j

1.2.4. Company Geologist should be present on rig site for correlation(whenever possible)

1.3. Safety

1.3.1. Perforating operations should be carried out strictly according tothe safety policies of Eni-Agip and the perforating Contractor. Inthe event of any inconsistency between policies, the mostconservative policy will apply.

P-1-M-7120 5.3.b

1.3.2. During the arming and connecting operation, all non-operatingpersonnel shall be at a safe distance.

P-1-M-7120 5.1

1.3.3. While arming and connecting the guns no electrical change are tobe made on the rig that would cause the gun to fire.

P-1-M-7120 5.1

1.3.4. Electrical welding operations must be stopped before any workwith explosive start.

P-1-M-7120 5.1

1.3.5. All radio transmitters must be turned off prior to shootingoperations; when the guns are 30m below ground level the radiocan be turned on (when required).

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1.3.6. All radio transmitters, radio beacons included, within a radius of 500ft from the well, shall be turned off, (since they may detonate

blasting caps), starting from gun arming until perforating guns are500ft below the sea bottom (similarly, when pulling guns out of hole and guns above 500ft).

P-1-M-7120 5.3g

1.3.7. After the guns has been removed from the well, it shall beinspected to see that all the charge are fired.

1.4. Wireline perforators

1.4.1. Inside casing

1.4.1.1.Rig up and pressure test the Shooting Nipple. P-1-M-7120 5.4

1.4.1.2. Check the distance between the CCL or GR and the top shot. Incase of selective gun, the distance from the CCL to the top of eachsection.

P-1-M-7120 5.4.1.5

1.4.1.3. Do not run a perforating string longer than the distance betweenthe blind rams and the stuffing box.

P-1-M-7120 5.4.1.4

1.4.1.4. After perforations perform a 15min static control monitoring thefluid level.

1.4.1.5. After perforations pull out of the hole slowly without swab the well(less than 5,000 ft/hour).

P-1-M-7120 5.4.1.4

1.4.2. Through tubing

1.4.2.1. The BOP and Lubricator should always be pressure tested. P-1-M-7120 5.4.2.1

1.4.2.2. Rig up wireline for a full bore drift run. Run in the hole and drift thetubing.

P-1-M-7120 5.4.2.3

1.4.2.3. Correlate the GR/CCL to the original GR log. Record a shortsection of film across the interval to be perforated showing at least

five casing collars and the pup joint at the top of the reservoir zone. Do not run down into the perforations on subsequent runs.

P-1-M-7120 5.4.2.7

1.4.2.4. Position the string at the desired perforating interval and fire theguns.

P-1-M-7120 5.4.2.8

1.4.2.5. Observe and record WHSIP to confirm the guns have fired. P-1-M-7120 5.4.2.9

1.4.2.6. Do not flow the well with the toolstring inside the tubing string.



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1.5. Tubing Conveyed Perforating

1.5.1. Run a bit and scraper to clean the casing before running the TCPsystem.

P-1-M-7120 5.6.1

1.5.2. Radio silence must be in force before connecting the firing headuntil the guns are 100 metres below ground level. On recovery of the guns, regardless of any indications that they have past 100mbelow ground level until the firing head is removed.

P-1-M-7120 5.6.4

1.5.3. Install the radioactive tag, if needed, as near as possible to thegun assembly. The service Specialist will have the planned Hook-Up diagram with OD, ID and length.

1.5.4. Rig up the main logging cable and run a gamma ray logging tooldown to the correlation depth. Tie-in on depth to the reference logand record on sufficient film to show both radioactive pip markersand any zones of gamma ray character on the log.

P-1-M-7120 5.6.4.9

1.5.5. Rig up the main logging cable and run a gamma ray logging tooldown to the correlation depth. Tie on depth to the reference logand record sufficient film to show both radioactive pip markers andany zones of gamma ray character on the log.

P-1-M-7120 5.6.4.11

1.5.6. Space out the tubing string to place the shots exactly on depth,

making proper allowance for the desired tubing compression or tension.

1.5.7. If case of TCP with a permanent completion, use the resondingfiring system.

1.5.8. If the guns have to be dropped down, verify the sufficient rat hole. P-1-M-7120 5.6

1.5.9. To prevent corkscrewed tubing between the top guns and packer,a shock absorber shall be used.

2. SAND CONTROL Reference

2.1. Gravel pack

2.1.1. Under-reaming should be performed using a non damaging fluid

2.1.2. Well fluids and sand carrying fluids must be filtered. P-1-M-7120 6.4.2

2.1.3. All mud system involved in the gravel operations must be cleaned(including wellhead and BOP cavity).

P-1-M-7120 6.4.1



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2.1.4. Verify screen gauge and gravel delivered is correct according tothe well programme.

P-1-M-7120 6.4.6

2.1.5. Gauge wash pipes and BHA. Verify centralisers are of the correctdimensions and properly spaced out.

P-1-M-7120 6.5.7

2.1.6. Verify gravel size.

2.1.7. The wire spacing of the screens should be checked for the proper gauge and uniformity.

P-1-M-7120 6.2

2.1.8. Working string used to place GP should be plastic coated. Checkfor coating integrity at the DP ends.

2.1.9. Have pup joints available to space out the work string.

2.1.10. Run the BHA in the hole slowly to prevent damage of the screen.

2.1.11. Apply pipe dope sparingly on the pin end only when making up thework string.

P-1-M-7120 6.5.10

2.1.12. Perform a circulation test using different rates prior to start GPoperations.

2.1.13. Always measure the quantity or evaluate the gravel reversed out.

3. CASING MILLING Reference

3.1. Mud or viscosified brine is needed.

3.2. Install ditch magnets in the mud circuit.

3.3. Test the knives are opening by pumping through the tool prior torunning in hole.

3.4. If an accurate depth is required a correlation log is needed.

3.5.Once on depth, rotation has to start prior to the mud pump.

3.6. Use low weights in section milling. A normal range can beconsidered to be between 4000 and 8000lbs.

3.7. Watch the cuttings over the shale shaker to monitor the tool andmud system efficiency.

3.8. The section of casing milled must be re-passed prior to pull outtool.



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3.9. Continue to circulate returns clean prior to starting pulling out of the hole.

3.10. Pay attention when re-entering the casing as the knives could bestuck in the open position.

Reference List :




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OP. 3.4. COMPLETION PULL OUT

1. WELL KILLING Reference

1.1. General

1.1.1. Check and record well head pressure.

1.1.2. Pressure test line at least 500psi over max. foreseeable pressure.

1.1.3. Pressurise kill line 200-300psi above the well head pressure beforeopening the Xmas tree valve.

1.1.4. Be careful not to exceed the fracture pressure given in theprogramme with the bottom hole pressure.

1.1.5. Bleed off any eventual residual pressure and perform a flow checkfor at least 30mins.

1.2. Bullheading

1.2.1. Bullheading should be performed with an aim of not fracturing theformation. The surface squeeze pressure applied should notexceed the pre-calculated MAASP.

P-1-M-6150 5.1.5

1.2.2. Be careful not to exceed the fracturing pressure given in theprogramme with the bottom hole pressure.

1.2.3. Unless particular problems arise such as overpressure or mechanical problems, perform bullheading at a high pump rateand never cease pumping once the operation has begun, until thecalculated volume of kill fluid has been pumped.

1.2.4. Monitor casing pressure during operation. If pumping in a string of a dual completion, during killing monitor also second string. Inspecial circumstances there might be a requirement for maintaining a back pressure on the annulus (e.g., short sealassembly in the packer, low tension snap latch, etc.)

1.2.5. Once the calculated volume has been pumped if an increment inpressure is noticed, immediately stop the mud pump.

1.2.6. Hold any final pressure until it drops to zero or it stabilises.



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1.3. Killing by circulation

1.3.1. Perform killing by reverse circulation is the normal procedure.

1.3.2. Balance pressure at the circulating depth between the tubing andthe casing before establishing communication.

1.3.3. In dual completions establish circulation L/S-S/S by opening theports between the two packers.

1.3.4. Reverse circulate through choke manifold until weight of fluid is thesame in and out. During the reverse circulation, the backpressuremaintained at the choke shall be calculated in order to keep thebottom hole pressure between the formation and the fracturingpressure.

1.3.5. Flow check every 30mins.

1.4. Killing by CTU

1.4.1. Nipple up the equipment and pressure test the coiled tubing andBOP stack.

1.4.2. Pressurise the coiled tubing to 200-300psi above wellheadpressure before opening the Xmas tree valves.

1.4.3. Run the coiled tubing to bottom hole checking overpull atpredetermined depths. Monitor the STHP and ensure that it is notbuilding up.

1.4.4. Once at the bottom circulate with adequate kill fluid having returnthrough choke manifold.

1.4.5. Stop circulation when kill fluid weight in and out is both the same.

1.4.6. Flow check every 30mins

1.5. Lubricate and bleed killing method

1.5.1. This method can be used to completely kill the well or to reducethe shut-in pressure in high pressure wells.

1.5.2. To get the maximum advantage from this method start theoperations flowing the well to reduce shut-in pressure then close,stop flowing and start pumping killing fluid.

1.5.3. Do not allow a large volume of killing fluid to be discharged duringthe bleeding phase.



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2. PACKER UNSEATING AND COMPLETION PULLING Reference

2.1. General

2.1.1. Consult the final completion report to check the packer(s) shear ring(s) value and decide the max. pull to apply.

2.1.2. Use the same type of tubing joint used for the completion with theproper crossover to make up the landing joint(s).

2.1.3. Install the circulating head in the open position on the landing joint(s).

2.1.4. When unsetting the packer do not exceed the max. tension

applicable for the tubing joint.

2.1.5. If overpull is required and is excessive, stop pulling and work thepipe up and down.

2.1.6. If the max. tension is reached and no progress is made, the tubinghas to be cut above the packer so as to be able to be engagedwith a fishing string.

2.1.7. Once the packers are unset, work the string slowly allowing thepacker elements time to relax fully then pull the tubing hanger tosurface.

2.1.8. After the tubing hanger has been removed from its seat, circulateone full hole volume of conditioning fluid since gas may be trappedbelow the packer, be ready to circulate through choke manifold.

2.1.9. Make an accurate list of all the joints and all the special tools inhole to be broken out

2.2. Pulling carbon steel tubing

2.2.1. For breaking-out, the back-up tong has to be positioned on the

lower part of the coupling (if applicable).

M-2-SS-722 5.2.h

2.2.2. A low gear will be selected in the power tong for break-out.

2.2.3. Be certain the power tong can move with the pipe, and that thepipe is not supporting the weight of the power tong. To ensure this,stop spinning after five turns, disengage the tong from the pipebody, then re-engage the tong and complete break-out.

2.2.4. Apply thread storage compound and install protectors.



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2.3. Pulling alloy tubing

2.3.1. Padding material will be fitted to the V-door and cat walk areas toprevent damaging the tubulars as they are laid out.

2.3.2. Ensure that the power tongs are fitted with the correct size non-marking dies.

2.3.3. Tubing slips and elevator will be dressed with low stress dies. M-2-SS-701 4.1.d

2.3.4. The use of a pick-up/lay-down machine is recommended. M-2-SS-701 4.3.1

2.3.5. Care must be taken setting pipe in the slips to prevent shockloading and impact damage.

2.3.6. The connection will be broken using a power tong at a low speedof 2rpm.

M-2-SS-701 5.2

2.3.7. Once the thread has been broken, the connection will be backedoff by using a strap wrench.

M-2-SS-701 5.3

2.3.8. Storage compound will be applied and clean thread protectorsinstalled.

2.3.9. Never pull out alloy tubing in stands. M-2-SS-722 5.2.h

Reference list :


‘Running Procedures for Corrosion Resistant Alloy OCTG’ TEPR-M-2-SS-701

‘Tubing Power Tong’ TEPR-M-2-SS-722



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OP. 3.5. PIPE/TOOL RECOVERY

1. PACKER MILLING Reference

1.1. Install a wear bushing during this operation.

1.2. If a packer milling tool (Baker or similar ) is used, have more shoesof the same size (OD-ID) on location as one might not be enoughto mill a packer.

1.3. While preparing the tool make sure the ID of the extension isbigger than the ID of the milling shoe.

1.4. The use of a junk basket (or junk sub) positioned just above themilling tool is recommended.

1.5. With a milling tool, the use of a rotary jar is recommended.

1.6. Install ditch magnets in the mud system.

1.7. Consider the use of a centraliser, especially in a deviated hole.

1.8. If not working in mud, a viscosified brine must be used.

1.9. Using a packer milling tool with catch sleeve, the packer must bereached with the Kelly while circulating.

1.10. At least 3 metres of Kelly have to be above the rotary table whenengaging the packer.

1.11. When approaching the packer, watch M/D and pump pressuregauge carefully to observe that the milling tool is entering thepacker.

1.12. Check and record the up, down and rotating weights, also checkand record the torque before entering with the catch sleeve in thepacker.

1.13. Once the packer has been located, pick up the milling tool, startrotation and then lower the milling tool to start milling. Never start amill when on the fish.

1.14. During milling, pick up the milling tool from time to time to changethe working position.

1.15. To have a high annular velocity, the pump flow rate should be thehighest allowed by the pump and the hole conditions.

1.16. If rubber is reducing milling rate try shutting off the mud pump for short periods and spud the mill frequently.



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2. FREE POINT Reference

2.1. A Free Point survey shall be run to select the back-off point. P-1-M-6140 16.4.6a

2.2. Pipe which appears to be free in tension does not always react toapplied torque. There is a greater chance of succeeding with theback-off if the pipe is free under both tension and torque.

P-1-M-6140 16.4.6f

2.3. If an accurate free point depth is required an electric free point logmust be carried out.

2.4. A pressure holding device, as an hydrolex or stuffing box, has tobe installed on the string with the possibility to pump in hole if needed.

P-1-M-6140 16.4.7

2.5. The most common procedure to locate the free point is to performit in steps always splitting the string by half.

2.6. The tension applied to the string with the free point tool on depth,has to be higher than the weight of the string itself pulling out of hole.

2.7. Do not apply the same tension all times but vary.

2.8. If the tool used allows, check for pipe free under stretch andtorque.

3. BACK OFF Reference

3.1. Only a mechanical back off has to be attempted on tubing jointsand it has to be used as last resort.

3.2. A circulating head has to be installed on the string.

3.3. Set the weight in neutral at the desired depth.

3.4. If a top drive is available, start turning the string counter-clockwisea predetermined number of turns depending on the type of threadand the depth of back off.

3.5. Apply left hand torque in a series of steps. Work the pipe at eachstep to transfer the torque downhole.

P-1-M-6140 16.4.7.7

3.6. The maximum amount of left hand torque should be 80% of themaximum value used for the right hand torque.

P-1-M-6140 16.4.7.8

3.7. Once the right amount of left hand torque is applied, run the Back-off tool to the back- off point

P-1-M-6140 16.4.7.9

3.8. Hold the torque and reciprocate sting to transmit torque to thebottom.

.



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3.9. Set the string in the same position with the same pull and give fewmore turns.

3.10. Repeat the operation until the pipe is free.

3.11. If a top drive is not available, after the string has been turned withthe slips in the rotary table, torque should be released and theback turns has to be recorded to see the effective turns taken bythe string.

3.12. Left hand threaded drill pipe, or reversing tool, can be consideredfor performing a mechanical back off.

3.13. Pull the drill string out of the hole. Fire the charge when across theselected joint connection and retrieve the tool.

P-1-M-6140 16.4.7.10

3.14. If the operation is unsuccessful, release the left hand torque,circulate to clean the string from back-off debris and start again.

P-1-M-6140 16.4.7.13

3.15. The backing-off of drill collar connections should be performed byfollowing the same procedure. Problems may arise due to thedifficulty in identifying the Free Point and with higher left handtorque required.

P-1-M-6140 16.4.7

3.16. As general rule, the first attempt to back off should be made at the

first connection above the free point. Subsequent attempt shouldbe made moving upward one stand at a time.

P-1-M-6140 16.4.7

4. TUBING PUNCHER Reference

4.1. All the safety procedures for explosive running must be followed.

4.2. This operation is normally done before removing the Xmas treeand pressure testing equipment is mandatory.

4.3. Identify the type of charges and check if they match with the typeand material of tubing in the hole.

4.4. Make sure the engineer in charge of the job has measured thedistance between the CCL and the top of the charges.

4.5. Depth correlation will be done with a CCL compared with thetubing tally in the completion report.

4.6. Pressure at punching depth has to be equalised or kept higher inside tubing by pressurising with rig pump to get an overbalancefrom tubing to the annulus.



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4.7. Keep tubing and annulus pressure under observation during theoperation.

4.8. It is good practice after the puncher has been fired to pull thepuncher about 50m upwards and try to establish circulation.

4.9. Check the gun when out of hole and pay attention to any chargeswhich may not have fired.

5. TUBING CUTTER Reference

5.1. Safety procedures for explosive running have to be followed

5.2. Depth correlation has to be done with a CCL compared against the

completion tubing tally.

5.3. Make sure the tubing cutter, chemical or explosive, has the proper size and is adequate for the type and material of tubing in hole.

5.4. At all times use pressure control equipment.

5.5. The string should be in tension when cutting. The pull at surfacewill be decided according to the depth, the hole characteristics andthe OD of tubing.

5.6. Observe the M/D when firing the tubing cutter.

5.7. Pull the tubing cutter out of the hole taking particular care whenpulling through restrictions in the tubing string such as landingnipples, sliding sleeves, etc.

5.8. If a chemical cutter is used, once out of hole, wash the rig floor with abundant amount of water to avoid direct contact with skin or residual acid.

5.9. A chemical cutter is preferred if the next trip in the hole is with anovershot.

6. WASHING OVER Reference

6.1. Hole characteristics such as deviation, dog legs, restriction etc.have to be considered when planning to run wash over pipe.

6.2. Run the minimum wash pipe joints necessary considering the wellsituation at all times.

6.3. Select the proper milling shoe depending on the type of job to bedone and measure the ID and OD of the dressed end and the IDand OD of the body.



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6.4. The ID of the washover shoe has to be smaller than the washover pipe ID and the OD larger than the wash pipe OD.

6.5. Check all parameters before entering the fish with washover pipe,string weight up, down and rotating, torque, pump pressure andrate.

6.6. Due to the fragility of washover pipe keep the torque carefullymonitored when working on the fish.

6.7. Because of the small clearance between casing ID and wash pipeOD, frequently pick up the string to avoid getting stuck.

6.8. After the washpipe has been pulled out, before re-running thesame joints, an accurate check of the threads and the body mustbe done.

6.9. The pump flow rate should be high enough to keep the millingshoe free from cuttings and to have an annular velocity highenough to carry the cuttings to surface.

7. FISHING Reference

7.1. A detailed and accurate sketch of the equipment in the hole isnecessary to make a proper fishing tool selection.

P-1-M-6140 16.5.2.2

7.2. If the hole or fish condition is not known, more information can beobtained by running an impression block on drill pipe, or cable, toget a picture of the top of the fish.

7.3. If a parted string has been retrieved, information can be obtainedfrom the end condition of the parted string.

7.4. With any type of fishing tool used, the fish should be approachedwith the pumps on.

7.5. When the top of fish is in good condition, an overshot can be runto attempt recovery. If not in good shape it must be redressed witha mill first.

7.6. Check the grapple and mill control for proper size when running anovershot. Also check the guide and top connection ID compared tothe OD of f ish.

7.7. Unless for particular situations, an overshot will be run all timeswith a jar and DCs.



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7.8. If the fish is plugged, and no circulation is expected, once engagedwith the overshot, it is good practice to remove the mill control seal

prior to running. In any case the possibility of being able tocirculate with the fishing tool engaged has to be considered.

7.9. To engage a fish, the fishing string is lowered and rotated to theright very slowly, pumping at minimum rate. During the engagingoperation, continuously monitor the weight indicator and stand pipepressure.

P-1-M-6140 16.6.1.5

7.10. Prior to engaging the fish, record the weight of fishing string (up,down and rotating) with and without circulation.

P-1-M-6140 16.6.1.4

7.11. When running overshot, space out string before engaging the fish,in order to have the tool joint at the rotary table, or before to installthe Kelly.

7.12. Using the Kelly, a fish can be reached and engaged by slowlyrotating the string (e.g. 10 RPM)

7.13. If an electric line run is planned, do not engage a fish with theKelly.

7.14. Slack off weight before trying to unset an overshot by rotatingclockwise.

7.15. It is nigh impossible to release the tool once engaged. For thisreason its use has to be considered the last resort and only usedafter consultation with Eni-Agip Shore Base (DrillingManager/Superintendent).

P-1-M-6140 16.6.3.1

7.16. To engage the fish, apply right hand torque. A gradual increase of back torque is an indication of successful operation

P-1-M-6140 16.6.3.4

7.17. Running a jar with a taper tap or die collar should be evaluated inevery single situation. A jar could negate the fishing tool action.

Reference List :




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OP. 3.6. WELL COMPLETION

1. TUBING/PACKER INSTALLATION PROCEDURE Reference

1.1. Single string

1.1.1. Always handle the tubing with thread protectors fully screwed on.

1.1.2. Drift the tubing with the correct OD drift mandrel 42” or 1067mmlong.

1.1.3. Ensure the wear bushing has been removed from the tubing spoolprior to starting running the completion or, in case of a metal sealtubing spool, prior to landing the tubing hanger. In cases where theretrieving tool is equipped with a bottom thread and no control

lines or electric lines are being run, the wear bushing can beretrieved prior to installing the SCSSV.

1.1.4. Use safety clamps while running the BHA.

1.1.5. A circulating head with a proper crossover must be available onthe rig floor.

1.1.6. Thorough cleaning of threads with proper solvent and air should bedone immediately before use.

1.1.7. Visually inspect both the male and female thread conditions.

1.1.8. Do not try any repair job on the sealing areas of premium tubing.

1.1.9. Check the tong alignment.

1.1.10. Use a stabbing guide.

1.1.11. Keep the tubing aligned during make-up. The use of a stabber isrecommended for premium tubing.

1.1.12. Make-up the tubing by hand for at least the first two or three turns.

1.1.13. Apply the correct make-up torque value according to the frictionfactor for the type of grease being used.

1.1.14. Avoid contamination of the thread compound by water, rain, drillingfluid, etc. A new bucket of compound should be opened at thebeginning of the installation.

1.1.15. A dope applicator is recommended for use on every type of connection.



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1.1.16. Use a make-up joint analyser when running premium tubing.

1.1.17. Check for slip marks, depth of damage must be less than 5% of the wall thickness.

1.1.18. Run in the hole slowly to avoid the piston effect and continuouslywatching the M/D. If an overflow of fluid occurs, pumping of aheavy pill can be considered.

P-1-M-7120 7.3.2.10

1.1.19. Check the displacement continuously.

1.1.20. Check the anchor screws are completely open before landing thetubing hanger.

1.1.21. Check and record the weight of the string both up and down.These data have to record in the final completion report.

P-1-M-7120 7.3.2.14

1.1.22. Tighten anchor screws to energise the hanger seal and pressuretest before nippling down the BOP. A two way BPV shall also beinstalled and tested prior to nippling down the BOP.

1.1.23. Calibrate the string with wireline.

1.1.24. A correlation log must be conducted if accurate packer positioningis required.

1.2. Dual string (simultaneous)

1.2.1. Have two circulating heads available on the rig floor with thecorrect tubing thread.

1.2.2. During running in the hole, keep the long string/short string gap asper the programme.

1.2.3. The tubing hanger guide in the tubing spool has to be positionedprior to lower the tubing hanger.

1.2.4. Calibrate the short string and long string with wireline beforeinstalling the Xmas tree.

1.3. Special alloy tubing

1.3.1. Always use extremely clean plastic thread protectors fully screwedon.

1.3.2. The thread protectors will be removed and cleaned and thethreads cleaned and inspected by an approved thread inspector.

P-1-M-7120 8.2.5.9



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1.3.3. Always handle the tubing with nylon slings. P-1-M-7120 8.2.5.4

1.3.4. The tubing will be drifted from end to end using a nylock drift to API spec. The drift dimensions will be as per (API RP 5A5):

P-1-M-7120 8.2.5.12

1.3.5. The use of a device such as a pick-up/lay-down system isrecommended to carry the tubing to the V-door. Padding materialwill be fitted to the V-door and catwalk areas to prevent damage tothe tubulars.

P-1-M-7120 8.2.7.1

1.3.6. Before running, check the travelling block-to rotary tablealignment.

1.3.7. Use a dope applicator, or similar, to apply the right amount of thread compound.

P-1-M-7120 8.2.6.4

1.3.8. If no pipe dope applicator is available, apply thread compoundsparingly to the entire pin end and to only the shoulder seal andfirst three threads of the box using a new, clean, 1” fibre brush,ensuring that it fills the thread roots and covers the seal faces andtorque shoulder adequately.

P-1-M-7120 8.2.6.5

1.3.9. A thread inspector must inspect all threads. P-1-M-7120 8.2.6.9

1.3.10. Tubing slips will be dressed with low stress dies. P-1-M-7120 8.2.7.8

1.3.11. The power tongs will be fitted with the correct size non-markingdies.

P-1-M-7120 8.2.7.2

1.3.12. Make-up joints hand tight with a strap wrench before using power tongs.

1.3.13. The last turns will be made using a torque turn unit with a graphicaltorque turn analyser to confirm the correct make up value.

P-1-M-7120 8.2.7.17

1.3.14. Care will be taken setting pipe in the slips to prevent shock loadingand impact damage.

1.3.15. The make up speed should be between 3 to 10rpm. Final make upshould be at 5 RPM.

P-1-M-7120 8.2.7.18

2. HYDRAULIC LINE INSTALLATION Reference

2.1. Attach an across-coupling protector at the first connection andensure the control line is flat against the tubing and is in tension.

P-1-M-7120 8.5.3.7

2.2. Run in the hole on tubing applying the protectors at everyconnection and mid joint, keeping tension on the control line.

P-1-M-7120 8.5.3.8



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2.3. When the spacing out procedure has been completed, wrap thecontrol line around the pup joint below the hanger to provide

contingency if the line is damaged during make up and landing.

P-1-M-7120 8.5.3.9

2.4. Never rotate the string when running in the hole with a control line. P-1-M-7120 8.5.3.8

2.5. Never allow any hole fluid to enter the control line.

2.6. Attach the remaining control line from the reel to the exit port in thehanger and pressure test the line according to the completionprogramme.

P-1-M-7120 8.5.3.11

2.7. Lock and monitor the pressure in on the reel keeping the valveopen as it is run in the hole preventing pressure locking, allowingthe string to self fill and checking for control line leaks.

P-1-M-7120 8.5.3.6

3. ELECTRIC LINE INSTALLATION Reference

3.1. Install protector/centralisers and ensure the string is properlycentralised to prevent stripping off the electric line or protectors.

3.2. Check the electrical continuity and isolation every 200-300m run inhole.

3.3. Do not rotate string during running to avoid cable damage.

3.4. Do not suddenly stop the string with the brake to avoid cablestretching.

4. SUCKER ROD PUMP INSTALLATION Reference

4.1. Ensure that the rods and pump assemblies have been properlychecked and tested.

P-1-M-7120 10.2.3.2

4.2. Pull back to space out the rods so that the polished rod will bepositioned correctly through the stuffing box.

P-1-M-7120 10.2.3.7

4.3. Make up the stuffing box to the wellhead and pressure test through

the flowline against the standing valve.

P-1-M-7120 10.2.3.9

4.4. Pressure test according to the programme. P-1-M-7120 10.2.3.17

4.5. Begin the pump commissioning process bringing the wellonstream.

P-1-M-7120 10.2.3.18

4.6. Optimise the pump speed to maximise stable production flowingconditions.

P-1-M-7120 10.2.3.21



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4.7. When a tubing pump is used, in deep wells it should be runcomplete with standing valve and plunger to avoid damaging the

precision machined surfaces during tripping. On a second trip therod string will be connected.

4.8. Rods must be handled with care and stored to ensure they are nottrampled on.

4.9. The use of a hydraulic tong is recommended to obtain uniformmakeup results.

4.10. Once on bottom, establish the pump stroke, space out and installthe polished rod.

5. ESP SYSTEM INSTALLATION Reference

5.1. Gauge the hole prior to running the pump to make sure there is noclearance problem.

P-1-M-7120 10.1.2

5.2. The ESP manufacturer’s field representative must thoroughlycheck all equipment before installation.

P-1-M-7120 10.1.2

5.3. The manufacturer’s field representative must direct the assemblyprocedure and check the equipment as it is being run-in.

P-1-M-7120 10.1.2

5.4. Mechanically check the free rotation of downhole components. P-1-M-7120 10.1.2

5.5. Check the electrical connection and test the motor, power cable,and flat cable pothead

P-1-M-7120 10.1.2

5.6. Check the connecting coupling size is correct.

5.7. When running the BHA in the hole, check if the shaft rotates freelyafter every single component has been flanged up.

5.8. Check cable insulation and continuity before to connecting it to themotor.

5.9. Make sure the motor and protector are full of oil. Displace theshipping oil with insulation oil in the seal section.

P-1-M-7120 10.1.2

5.10. The check valve, if required, should be installed 5-6 joints abovethe pump.

5.11. The bleeder valve should be installed 1 or 2 joints above the checkvalve.



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5.12. Do not make sudden stops with brake during running to avoidcable damage.

5.13. Do not rotate the string during running to avoid cable damage.

5.14. Once the run-in procedures are completed and final electrical testscompleted, the manufacturer’s representative will complete theelectrical connections.

P-1-M-7120 10.1.2

5.15. Phase rotation should be checked carefully to ensure that thepump will rotate in the correct direction. Start the pump. Fluidpump-up time, load and no-load voltage and amperage on eachphase must be recorded.

P-1-M-7120 10.1.2

5.16. Monitor the wellhead pressure while the string is still full of completion fluid to verify correct pump operation

P-1-M-7120 10.1.2

5.17. Check the cable for any short circuits and insulation every 200-300m while running and after the eventual splicing.

P-1-M-7120 10.1.2

6. WELL HEAD INSTALLATION AND TESTING Reference

6.1. Make sure all the protective paint in the sealing seats has beenremoved.

6.2. Remove all plugs from test and vent ports in the seal flange prior

to install the Xmas tree and blow air through to make sure all arefree. In the same way test eventual control line ports.

6.3. Use a lifting flange to hang the Xmas tree. P-1-M-7120 8.6.1.2

6.4. Use a travelling block to hang and lower the Xmas tree onto theseat to maintain better control.

P-1-M-7120 8.6.1.9

6.5. Make sure all Xmas tree valves are open before installation. P-1-M-7120 8.6.1.10

6.6. Lower the Xmas tree very slowly on the tubing spool with all boltsinserted in the base flange so that it is guided to the right position.

6.7. Short strings and long strings have to be easily identified in anevidently clear and permanent manner

6.8. The bolt nuts must be tightened, with a torque wrench, gradually ina progressive 90° phased makeup sequence until the final torqueis reached, continuously checking the gap between the twoflanges.



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6.9. All pressure testing of energised seals should be carried outaccording to the procedures stipulated in the manufacturer’s

manual or well programme procedures. When testing is complete,bleed off pressure from the test port, remove test apparatus,replace the check valves and plugs.

P-1-M-7120 8.6.1.12

6.10. All pressure testing of energised seals has to be carried out.

6.11. Pressure test the tubing hanger upper seal by pressurising theXmas tree. The test port on the opposite side of the seal has to beopen during this test.

P-1-M-7120 8.6.1.14

6.12. Pressure test the tubing hanger seals and ring joint via the port onthe seal flange. Keep the casing valve on the tubing spool and testport open during this test.

P-1-M-7120 8.6.1.13

6.13. Always have one set of spare seals and ring joint available.

6.13.1. Test the control line ports, if any.

6.14. Record all operations on a pressure recorder. P-1-M-7120 8.6.1.15

7. PACKER(S) SETTING Reference

7.1. Install a plug by wireline in the packer tailpipe landing nipple, fill upthe assembly with brine

P-1-M-7120 7.3.1.6

7.2. Keep the casing valve on the tubing spool open

7.3. Set the packer applying pressure according to the manufacturer’ssetting procedure.

P-1-M-7120 7.3.1.14

7.4. Hold setting pressure for about 10 min. monitoring any returnsfrom the casing.

7.5. Bleed off pressure slowly.

7.6.Pressurise the casing to 500psi to test above the packer.

7.7. Record all operations on a pressure recorder.

Reference List :




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OP. 3.7. STIMULATION

1. MATRIX TREATMENT Reference

1.1. Preliminary

1.1.1. A copy of the Company Safety Procedures on corrosive andpoisonous fluid shall be available on site.

1.2. General Notes

1.2.1. Hold a safety meeting with all the personnel involved in theoperations.

P-1-M-7120 15.2

1.2.2. All the surface lines must be pressure tested and recorded on a

Martin Decker type chart recorder.

P-1-M-7120 15.4.3

1.2.3. Begin acid pumping operation only in day light.

1.2.4. Plan the operation in order to open the well for clean up in daylight.

1.2.5. Iron content in the chloridric acid shall be not more than 1000 ppm.

1.2.6. The acid tanks should be internally coated with acid resistant paintand equipped with a level indicator.

1.2.7. The pump/squeeze manifold should have outlets for pressuremonitoring and a connection for the pump unit and Xmas tree/teststring. Between all connection an interception valve shall be fitted.

1.2.8. On the pumping line install a hydraulically actuated valve withremote control (as near as possible to the wellhead).

1.2.9. Use a computerised control module with continuous recording of working parameters on tape or floppy disk.

1.2.10. The amounts and volumes of chemical products should be

checked when they arrive at the well site.

1.3. Safety

1.3.1. During the acid mix operation and pumping operations, all non-operating personnel shall be kept at a safe distance.

P-1-M-7120 15.2

1.3.2. All work areas will be chained or roped off, and warning signsplaced at all access routes. The exact requirements will bespecified on the work permits.

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1.3.3. Fire hoses will be available in the areas where acid is to be used.The hoses will be fully charged, so that they can be used

immediately should a spill occur.

P-1-M-7120 15.2

1.3.4. Sacks of soda ash or calcium carbonate shall be available for absorbing small spills of acid.

P-1-M-7120 15.2

1.3.5. Acid showers and eye baths will be available should any personnelcome into contact with acid.

P-1-M-7120 15.2

1.3.6. The first aid safety kit for personnel coming in contact withcorrosive and poisonous fluids should be positioned at the rig side.

2. HYDRAULIC FRACTURINGReference

2.1. General

2.1.1. All equipment shall be positioned at least 15m away from thewellhead

2.1.2. Lines connecting blenders and pumps shall be flexible with at least10 Bar (150 psi) WP.

2.1.3. All lines shall be anchored and pressure tested.

2.1.4. During all the treatment operation the annulus pressure shall be

monitored.

2.1.5. A safety check valve shall be positioned as near as possible to thewellhead on the pumping line.

2.2. Preliminary Tests

2.2.1. Prior to starting the treatment, it shall be necessary to perform thefollowing tests:

• Fracture extension pressure.

• Leak-off test.

• Fracture closure pressure.

• Friction loss.



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2.3. Equipment

2.3.1. The equipment required to perform the fracturing job is as follows:

• Water/brine stock tanks.

• Frac fluid stock tanks.

• Pumps equipped with an over pressure shut down system.

• Blender with tub, centrifugal pumps, screw pump,densitometer, flowmeters.

• Pressure gauges, flowmeters, relief valve, pop-off/bleedvalves, viscometer.

• Surface lines.

• Computerised control module.

• Sand trap, API sieves (if required).

• Proppant tanks (if required).

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OP. 3.8. COILED TUBING OPERATIONS

1. RIG UP, TESTING AND DEPLOYMENT Reference

1.1. The tubing string should be drifted by wireline prior to the first runof the coiled tubing.

1.2. A coiled tubing specification chart must always be available on theCT unit.

This chart will contain at least the following data:

P-1-M-7120 13.2.1

1.2.1. Tubing specification:

• Serial Number

• OD

• Max. working pressure

• Max. tensile load.

1.2.2. Updated history logs:

• Cycle history log

• Treatment history log

• Last NDT test.

1.3. The CT BOP must be connected directly to the Xmas tree (or tothe flowhead)

P-1-M-7120 13.4.2

1.4. Once the injector and the BOP stack have been positioned, the CTshould be filled and flushed with water to make sure there is noobstruction.

P-1-M-7120 13.4.2.1

1.5. All rams and the stripper will be function and pressure tested withwater to at least 500psi over the static wellhead pressure prior torunning in the hole.

P-1-M-7120 13.4.2.6

1.6. The back pressure valves will also be pressure tested. P-1-M-7120 13.4.3.5

1.7. The weight indicator must be tested before running coiled tubing in

to a well.

P-1-M-7120 13.5.3

1.8. Ensure the mechanical and electronic depth counters are set tozero depth at the swab valve or at the rotary table prior to runningin the hole.

P-1-M-7120 13.5.4

1.9. A schematic of the completion string (including string restrictions,inclinations and string profile) will be given to the CT operator for guidance when running.

P-1-M-7120 13.1.1



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1.10. Standard running speed should be 50ft/min, running or pullingthrough unobstructed tubing, slowing to 15ft/min within 50ft either

side of obstructions.

P-1-M-7120 13.5.5

1.11. Ensure that the tubing internal pressure is maintained at all time bypumping.

Ensure that tubing pressure does not increase while running byventing when necessary.

P-1-M-7120 13.5.7

1.12. The C/T contractor will provide plots of pipe weight, pipe loadingand buckling stress against depth for the particular job to beperformed. Any significant deviation from these plots during theoperation must be investigated.

P-1-M-7120 13.5.10

1.13. Pulling weight tests/checks should be performed every 1,000ftregularly during running in.

P-1-M-7120 13.5.11

1.14. A tapered coil tubing string has to be used in deep deviated wellsand always where excessive drag is encountered.

2. GAS LIFTING Reference

2.1. Run in the well carefully, stopping to establish nitrogen injection ata low rate, increasing the rate slowly as the coiled tubing is further run in.

P-1-M-7120 13.6.1.7

2.2. Once the tubing has reached the predetermined depth, stoprunning in and continue pumping nitrogen until nearly all thenitrogen is pumped, or the well is flowing strongly.

P-1-M-7120 13.6.1.8

2.3. Temperature of nitrogen pumped should be kept under control. Avoid pumping too cold or too hot nitrogen compared to the welltemperature.

2.4. Pull the tubing out of the well before the nitrogen supply iscompletely exhausted. This is to ensure that the pressuredifferential across the tubing wall does not exceed 1,000psi.

P-1-M-7120 13.6.1



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2.5. The following data will be recorded throughout the nitrogen liftoperation:

• Wellhead flowing pressure

• Nitrogen injection pressure

• Nitrogen injection rate

• Wellhead flowing temperature

• Separator level

• Separator pressure

• Separator temperature

P-1-M-7120 13.6.1.2

2.6. The returns from tubing should be through a choke manifold andseparator.

3. WELL CLEANING Reference

3.1. 11/4” is the minimum size CT OD which should be used to carry out

clean up jobs.

3.2. A jet nozzle, with radial and coaxial holes of the proper ID will beinstalled in the CT BHA.

3.3. The returns from tubing string should be through a choke manifoldand a separator.

P-1-M-7120 1.1.3.1

3.4. A sampling point will be installed in the return line. P-1-M-7120 1.1.3.2

3.5. Begin running in carefully with the well producing at a reducedrate. Keep the tubing string filled full of treated sea water bycirculating at the minimum rate. Carry out regular pull tests/checksat 1,000ft intervals.

P-1-M-7120 1.1.3.7

3.6. Monitor the pump pressure, wellhead pressure and coiled tubingstring weight continuously throughout the operation. If there areany indications of problems pull back above the last hold up depthimmediately and evaluate the situation.

P-1-M-7120 1.1.3

3.7. Sand can be washed using viscosified brine or brine cushionsalternated with nitrogen cushions. Apply the later solution whenworking inside casing.

3.8. Before entering open casing always circulate the tubing stringcapacity twice.

3.9. Penetration, when working inside casing, has to be performed insteps depending on the casing ID. After each step, it is goodpractice to pull the CT back up to the previous starting point.



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3.10. Run in slowly to the top of the fill, stopping to note the hangingweight. Slow down when the weight begins to drop off the tubing

and flag pipe at surface as a reference. The tubing must be kept intension at all times.

P-1-M-7120 1.1.3.1

3.11. After penetrating 20ft, pick-up to the tubing shoe then run back into repeat the process in stages of 20ft, pumping continuously.

P-1-M-7120 1.1.3.2

3.12. Break circulation when well above the last recorded hold up depthand establish a minimum circulation rate while pumping gel.

P-1-M-7120 1.1.3.9

3.13. When the target depth is reached continue pumping washingfluid(s) reciprocating the CT and tag bottom several times toensure all that the sand has been removed.

P-1-M-7120 1.1.3

3.14. Lift and flow the well when pulling out to ensure all moving sandupwards is removed.

P-1-M-7120 1.1.3.5

3.15. Collect samples at the sampling point and monitor the sandcoming out.

4. CEMENTING Reference

4.1. 11/4” is the minimum size CT OD which should be used to carry out

this type of operation.

4.2. An accurate formulation and mixing procedure for the cement isessential to obtain a successful job, a batch mixer must be used.

4.3. Measure the volume of the CT, do not rely on calculated volumes.

4.4. The string should be filled with a formation compatible fluid.

4.5. Back pressure valves and a nozzle head should be installed in theCT BHA.

4.6. Depth correlation can be carried out comparing wireline depths (atbottom and at the tubing shoe).

4.7. Start pulling the CT when the top of cement displaced into the

casing is about 20/30m above the nozzle.4.8. Stop pulling the CT when the nozzle is about level with the

theoretical top of cement.

4.9. Continue pumping to clean the hole of excess cement.

4.10. If the job is carried out in an under balance condition, the returnhas to be done through a choke manifold, measuring accuratelythe volumes in and out.



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5. ACIDISATION Reference

5.1. Prior to rigging up the acid equipment a safety meeting will be heldwith all relevant personnel. The meeting will address the hazardsinherent with handling acids, particularly under pressure. Themeeting will also address the actions to be taken in the event of anemergency.

P-1-M-7120 13.6.2

5.2. Suggested BHA is, from the bottom up:

• Jetting nozzle

• 2 dart type check valves

• 6ft straight bar

• Tubing connector

P-1-M-7120 13.6.2-2

5.3. Run in the well carefully, circulating at minimum rate. Performregular pull tests/checks at 1,000ft intervals.

P-1-M-7120 13.6.2-6

5.4. If an acid wash or solvent treatment is to be performed then:

• Circulate the coiled tubing to treatment fluid.

• Jet the area to be treated while reciprocating the coiled tubingslowly.

• Circulate the tubing to injection quality seawater.

• Pull out of the hole.

P-1-M-7120 13.6.2-8

5.5. Check the internal condition of the CT and, if necessary, flush thecoiled tubing with an acid cushion prior to start the operation.

Reference List :




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OP. 3.9. WELL TESTING


1.1. An emergency safety hydraulic wing valve normally closed will beinstalled at the wellhead and operated by a remote control panel.

P-1-M-7130 7.1.1

1.2. A test pressure programme for the surface layout must beprepared by the contractor.

P-1-M-7130 7.1.1

1.3. All surface lines from the wellhead to the choke manifold willconsist of rigid pipe sections or coflexip, no chiksan loops areallowed.

P-1-M-7130 7.1.1

1.4. All surface lines from the wellhead to the flare manifold and

vessels, will be pressure tested using water. All pressures will berecorded on a Martin Decker type chart recorder.

1.5. All surface lines will be anchored to the platform deck or to theground.

P-1-M-7130 7.1.1

1.6. Fluid samples to evaluate BS&W during well clean up will becollected at the choke manifold on the choke cover hammer union.

1.7. Verify the positive choke ID with a vernier caliper. Do not rely onthe printed numbers.

1.8. When sand is produced, the choke ID will be checked atpredetermined intervals.

1.9. The test separator is used to:

• Separate the well flow into three phases; oil, gas and water

• Meter the flow rate of each phase, at known conditions

• Measure the shrinkage factor to correct to standardconditions

• Sample each phase at known temperature and pressure

P-1-M-7130 7.1.6

1.10. Separator pressure has to be kept as low as the well performanceallows and lower than 50% of the upstream pressure (to maintaincritical conditions).

1.11. Downstream choke manifold lines will preferably not be less than3” OD.

1.12. In oil well test, the oil level in the separator should be kept as lowas possible.

1.13. Flowing and static well head pressures will be measured using aDWT



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1.14. A high pressure injection pump with hydrate inhibitor will beavailable at all times on gas well tests.

P-1-M-7130 7.3.1

1.15. Bottom hole pressures will be recorded using a down holepressure and temperature sensor positioned as close to theperforations as possible.

1.16. Surface oil and gas samples will be collected at the end of the testwhen stabilised parameters are obtained.

1.17. Bottom hole samples in oil or condensate wells, if required, will becollected at the end of the build up period with the well flowingslightly and the bottom hole sampler positioned at the top of theperforations.

2. TESTING WITH DOWNHOLE TEST TOOLS Reference

2.1. In gas well tests, the completion string will have the capability toshut-in the well downhole (this is recommended even in oil welltests).

2.2. An emergency single shot circulating valve will be used in the teststring.

P-1-M-7130 6.2.6

2.3. The distance between the completion string shoe and the top of the perforations will be not less than 15m to allow PLT recording.

P-1-M-7130 6.1

3. WELL TESTING THROUGH A COMPLETION STRING Reference

3.1. Prior to flowing, the annulus will be pressurised to 500psi and thispressure will be held, monitored and recorded throughout all thetest.

4. SURFACE DATA ACQUISITION Reference

4.1. Wellhead pressure

4.2. Casing pressure

4.3. Wellhead temperature

4.4. Separator pressure P-1-M-7130 13.1.2

4.5. Separator temperature P-1-M-7130 13.1.2

4.6. Oil flow rate

4.7. Gas flow rate

4.8. Water flow rate



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4.9. Oil gravity P-1-M-7130 13.1.7

4.10. Gas gravity P-1-M-7130 13.1.7

4.11. Water salinity P-1-M-7130 13.1.10

4.12. CO2 content P-1-M-7130 13.1.14

4.13. H2S content P-1-M-7130 13.1.14

4.14. BSW P-1-M-7130 13.1.6

Reference List :

‘Well Testing Manual’ STAP-P-1-M-7130



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OP. 3.10. WIRELINE OPERATIONS


1.1. Wireline Unit

1.1.1. Offshore operations

1.1.1.1. Heavy duty skid: it shall be enclosed in a container with the enginearea separated from the reel area, explosion proof electricequipment, internal and external lightening, soundproof enginezone, engine exhaust shall have an extinction device, operator cabin insulated and air-conditioned, electric engine starter,arranged to be moved by crane, structure and covering shall be of stainless steel.

P-1-M-7110 6.3

1.1.1.2. Light duty skid: it is permitted for particular applications only under authorisation of the Well Area Manager and on structuresinadequate to accommodate heavy-duty skid. It has reel andengine separated, engine starting can be manual, engine exhaustpipe with extinction device, frames arranged to be moved bycrane.

P-1-M-7110 6.4

1.1.1.3. Equipment: skids shall be equipped with surface facilities and withdown-hole equipment suitable for operations on all wells of theplatform it will be installed, besides it shall be equipped with fishingequipment suitable for working string recovery. If all equipment or

part of it is not installed in the container, it shall be contained in awater proof stainless steel box.

1.1.2. Onshore operations

1.1.2.1. Heavy duty truck: it shall be enclosed in a container with the reelarea separated from the operator area, the truck engine shall beused as power unit for reel; it shall be equipped with power unitand compressor explosion proof electric equipment, internal andexternal lightening, soundproof engine case, engine exhaust pipewith extinction device, operator cabin insulated and air-

conditioned, electric engine starter, arranged to be moved bycrane, structure and covering shall be of stainless steel

The loading truck capacity shall be higher than the reel weight andall the equipment overall dimensions shall comply to regulations inforce in the country it is to be used.

P-1-M-7110 6.1

1.1.2.2. Equipment: trucks shall be equipped with surface facilities and withdown-hole equipment suitable for all the operations on the wells of the field where they have to be carried out; in addition it shall beequipped with fishing equipment suitable for the W/L toolstringrecovery; if the required surface equipment has a workingpressure greater than 5,000psi, it shall be moved separately.

P-1-M-7110 6.1.3



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1.1.3. Reel unit

1.1.3.1. General Characteristics: reel capacity not lower than 25,000ft of OD 0.092” or 20,000ft of OD 0.108” wire, surface velocity not lower than 1,800ft/min, maximum pulling capacity not lower than2,100lbs @ 20,000ft.

P-1-M-7110 6.1.2

1.1.3.2. Power transmission between engine and reel shall be hydraulic. P-1-M-7110 6.1.2

1.1.3.3. Engine/pump hydraulic group: able to supply the power requestedby the reel, 40-50 HP approximately.

P-1-M-7110 6.1.2

1.1.3.4. For light duty applications, reel capacity will be not lower than15,000ft of OD 0.092” wire and 20-30 HP.

P-1-M-7110 6.2.2

1.1.3.5. Hydraulic Circuit: it shall have the possibility of continuouslyadjusting pull and velocity. The possibility of regulating the reelmaximum pull. The possibility to operate the hydraulic engine asbreak when running. It shall have safety valves bleeding from highpressure circuit to low pressure circuit on the pump and on engine;it shall have a safety valve bleeding from low pressure circuit toatmosphere. It shall work with an easy to find common hydraulicoil.

P-1-M-7110 6.1.2

1.1.3.6. Equipment: the weight indicator hydraulic load cell type with

indicator gauge range will not be lower than the wireline breakingstrength and with subdivisions not greater than 5lbs. Depthindicator counter wheel type with 0.5m subdivisions. High pressurecircuit gauge, hydraulic oil thermometer, minimum/maximumhydraulic oil indicator level, gauge oil engine, thermometer for cooler liquid (truck unit), air thermometer (skid unit).

P-1-M-7110 6.1.2

1.2. Wireline crew P-1-M-7110 2.3

1.2.1. Light duty crew: composed of a Chief Operator, an Operator and aHelper.

P-1-M-7110 2.3.1

1.2.2. Heavy duty crew: composed of a Chief Operator, an Operator andtwo Helpers.

P-1-M-7110 2.3.2

1.2.3. Crew composition for work on HP-HT well does not fall within theabove mentioned definitions, but will be decided, depending on thetype of job, by the Wireline Supervisor.

P-1-M-7110 2.3

1.2.3.1. A Wireline Supervisor shall lead the Wireline Crew; for light duty jobs the Chief Operator could be the substitute.



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1.2.4. Personnel qualification P-1-M-7110 2.4

1.2.4.1. Chief operator :

• Experience: not less than 8 years in wire line job and not lessthan 4 years as Operator, wire line job on gas well, sour gaswell and oil well with WHP up to 10,000psi.

• Educational qualification: no lower than a professionaldiploma.

• Specialisation courses: basic wireline, advanced wireline,wireline fishing, H2S, first aid, fire fighting.

P-1-M-7110 2.4.1

1.2.4.2. Operator :

• Experience: not less than 4 years of wire line job and not lessthan 2 years as helper, wireline job on gas well, sour gas welland oil well with WHP up to 10,000psi.

• Educational qualification: not lower than a professionaldiploma.

• Specialisation courses: basic wireline, H2S, first aid, firefighting.

P-1-M-7110 2.4.2

1.2.4.3. Assistant Operator:

• Experience: not less than 2 years of activity in oil business

• Educational qualification: not lower than a professionaldiploma.

• Specialisation courses: basic wireline, H2S, first aid, firefighting.

P-1-M-7110 2.4.3

1.2.4.4. Chief operator for HP-HT well operations:

• Experience: not less than 2 years as Chief Operator and 2years experience on HP-HT wells.

• Educational qualification: not lower than professional diploma.

• Specialisation courses: basic wireline, advanced wireline,wireline fishing, H2S, first aid, fire fighting.

P-1-M-7110 2.4.1

1.2.5. Definition of job type P-1-M-7110 2.2

1.2.5.1. Light duty: Operations on completions maximum 27/8” OD and with

surface equipment up to 10,000psi.

P-1-M-7110 2.2.1

1.2.5.2. Heavy duty: Operations on completion of 31/2.” OD and over with

surface equipment up to 10,000psi. Operations with surfaceequipment equal or greater than 15,000psi.

P-1-M-7110 2.2.2



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1.3. Safety during operations P-1-M-7110 16

1.3.1. Equipment: Spark arresting exhaust silencer, explosion proof electric circuits, foam extinguisher, explosive mixture and toxic gasdetector, use of no spark-making tools.

P-1-M-7110 16.6

1.3.2. Personnel: overall, helmet, safety boot, gloves, safety glasses,soundproof headset, self contained breathing apparatus 30-45minute, first aid kit.

P-1-M-7110 16.5

1.3.3. During Heavy Duty Job use of crane is compulsory. P-1-M-7110 8.3

1.3.4. For operations on rig, barriers are necessary and use of safetybelts for work floors higher than 1.5m or more from ground floor.

P-1-M-7110 16

1.4. Documentation

1.4.1. Operations on rig

1.4.1.1. All information concerning well condition, operation to be carriedout and safety regulations to be followed shall be given by theSupervisor to the Chief Operator.

1.4.1.2. The Chief Operator shall consign the Rig Site Report to theSupervisor at the end of operation.

1.4.2. Operations on producing wells

1.4.2.1. The Supervisor shall gather information useful and necessary for operation development:

• Work schedule

• Wireline last report

• Completion schematic

• Wellhead schematic

• P & T last profile

• Well test last report, if any

P-1-M-7110 9

1.4.2.2. All information concerning the well operation to be performed andsafety regulations to be observed shall be given by the Supervisor to the Chief Operator.

1.4.2.3. The Chief Operator shall consign the Well Site Report to theSupervisor at the end of operation.

1.4.2.4. The Supervisor will fill in the wireline report at the end of operationand will consign it to the Wireline Superintendent.



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2. SURFACE EQUIPMENT Reference

2.1. Gin poleP-1-M-7110 4.1.1

2.1.1. The gin pole is a telescopic antenna composed by 3 sections of pipe approx. 8ft long (for a total of 20ft), OD2

1/2” - OD2”- OD 1

1/2”

respectively. The upper part OD11/2” has a welded slot to allocate

the hook of the crown block. The lifting system higher than 20ft willbe hydraulic.

P-1-M-7110 4.1.1

2.1.2. N80 steel or better. P-1-M-7110 4.1.1

2.1.3. Gin pole will be anchored to the wellhead in two positions, at least1m distant, by a chain min. OD5/16” and a chain tightener.

P-1-M-7110 4.1.1

2.1.4. Gin pole components are perforated OD 16mm every 0.25m toallow its extension.

P-1-M-7110 4.1.1

2.1.5. The pins shall have a OD of 15mm. P-1-M-7110 4.1.1

2.1.6. The gin pole components have the last hole of the pin series at 1ftfrom the ends.

2.1.7. A system of blocks will be used to lift the lubricator. P-1-M-7110 4.1.1

2.1.8. The system of blocks shall be 3:1 or 4:1 type with OD 18mm Nylon

rope and hooks on the two blocks to be connected to the gin poleand to the lubricator.

P-1-M-7110 4.1.1

2.2. Adapter flange P-1-M-7110 4.2

2.2.1. It is the junction between the top flange of the wellhead and thewireline BOP bottom connection.

P-1-M-7110 4.2

2.2.2. It shall be made from one block of forged and worked steel. P-1-M-7110 4.2

2.2.3. The type of steel shall be corrosion resistant to all fluids in hole. P-1-M-7110 4.2

2.2.4. Working pressure shall be equal or greater than the wellheadpressure.

P-1-M-7110 4.2

2.3. BOP’s P-1-M-7110 4.3

2.3.1. The lubricator assembly shall have at least a BOP with wire ramsor driven wire rams system.

P-1-M-7110 4.3

2.3.2. The wireline BOP shall be a ram type. P-1-M-7110 4.3



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2.3.3. BOP shall be hydraulically and manually operated. This will beactuated by a skid with accumulators able to perform a full

opening-closing-opening cycle in 90 sec.

P-1-M-7110 4.3

2.3.4. Working pressure shall be the same of the wellhead workingpressure.

P-1-M-7110 4.3

2.3.5. BOP shall be equipped with an equalising valve. P-1-M-7110 4.3

2.3.6. Rams shall be replaced after closure on wire. P-1-M-7110 4.3

2.3.7. All elastomers will be adequate to the formation fluid type. P-1-M-7110 4.3

2.3.8. Steel type shall be suitable to the fluid present in hole. P-1-M-7110 4.3

2.3.9. Bottom connection shall be equal to the one on the adapter flange. P-1-M-7110 4.3

2.3.10. Hydraulic control pipes connection of shall be pull-push type. P-1-M-7110 4.3

2.3.11. The hydraulic pump shall have the fluid end with the same BOPworking pressure.

P-1-M-7110 4.3

2.3.12. Hydraulic hoses connecting BOP to the pump shall have the sameworking pressure as BOP.

P-1-M-7110 4.3

2.3.13. BOP pump shall be positioned 30m from the wellhead. P-1-M-7110 4.3

2.4. Lubricator P-1-M-7110 4.4

2.4.1. It shall be composed by sections of pipe 8ft long.

2.4.2. Connections shall be Quick-Union type with hydraulic sealingassured by an ‘O’ Ring for a working pressure up to 5000psi andby a system of ‘O’ Ring + Seal protector ring + Non extrusion ringfor working pressure greater than 5000psi.

P-1-M-7110 4.4

2.4.3. Connection between pipe and Quick Union shall be either integral

type or welded type.

P-1-M-7110 4.4

2.4.4. The Lubricator working pressure must be equal or higher than thewell head working pressure.

P-1-M-7110 4.4

2.4.5. All elastomers shall be of a compound suitable for type of formation fluid.

P-1-M-7110 4.4

2.4.6. Steel type shall be suitable to the fluid present in hole.



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2.4.7. Lower section shall have ID and length adequate to receive theW/L tools used.

P-1-M-7110 4.4

2.4.8. The lower section shall have a OD1/2” NPT hole for working

pressure up to 10,000psi or metal seal for higher working pressureto bleed off well pressure

P-1-M-7110 4.4

2.4.9. A wear joint shall be installed on the bleed-off point. P-1-M-7110 4.4

2.4.10. The bleed-off valve shall have the same working pressure as thelubricator.

P-1-M-7110 4.4

2.4.11. The upper section shall have a lifting clamp strong enough to holdthe stuffing box + lubricator + BOP + adapter flange weight.

P-1-M-7110 4.4

2.4.12. The clamp shall be installed a 2-3ft from the stuffing box. P-1-M-7110 4.4

2.5. Stuffing box P-1-M-7110 4.5

2.5.1. The stuffing box connection will be equal to the lubricator upper connection.

P-1-M-7110 4.5

2.5.2. The stuffing box shall be hydraulically operated. P-1-M-7110 4.5

2.5.3. The Stuffing Box must be hydraulically controlled and the hydraulic

control pump positioned in safe position. Hydraulic hoseconnections ‘pull-push’ type are allowed.

The hydraulic control pump must be equipped, downstream thefluid end, if necessary, with check valve + ‘Tee’ + bleed off valve of the proper WP.

P-1-M-7110 4.5

2.5.4. Stuffing box WP shall be equal to the wellhead’s WP. P-1-M-7110 4.5

2.5.5. The hose WP must be at least equal or higher than the StuffingBox working pressure.

P-1-M-7110 4.5


P-1-M-7110 4.5


2.5.8. Sheave bracket assay shall have a size suitable to the diameter and to the wire material.

P-1-M-7110 4.5

2.5.9. The stuffing box packing shall have a quantity and type suitable for the type of wire steel and fluid in hole.

P-1-M-7110 4.5



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2.5.10. The stuffing box packing conditions must be compulsory inspectedbefore starting to run in hole with any tools.

P-1-M-7110 4.5

2.6. Safety check union P-1-M-7110 4.7

2.6.1. Use of a Safety Check Union between the upper section of lubricator and injection nipple is compulsory in operations on wellswith sour gas and on oil wells.

P-1-M-7110 4.7

2.6.2. The working pressure shall be equal or greater than the wellheadWP.

P-1-M-7110 4.7

2.6.3. Connections shall be equal to lubricator upper section and to theinjection nipple connection.

P-1-M-7110 4.7


P-1-M-7110 4.7


2.7. Injection nipple P-1-M-7110 4.6

2.7.1. The use of an injection nipple between the stuffing box and thesafety check union is suggested.

P-1-M-7110 4.6

2.7.2. The working pressure shall be equal or greater than the wellheadWP.

P-1-M-7110 4.6

2.7.3. Connections shall be equal to that of the stuffing box and SafetyCheck Union.

P-1-M-7110 4.6


P-1-M-7110 4.6

2.7.5. The use of needle valve and/or check valve on the injection line,connected directly to the Injection Nipple in standing position, isrecommended.

P-1-M-7110 4.6


2.7.7. The injection nipple shall have a OD1/2” NPT hole for working

pressure up to 10000psi or metal seal for higher working pressure.

P-1-M-7110 4.6

2.8. Swab valve P-1-M-7110 4.8

2.8.1. The presence of a manual swab valve with characteristics equal tothe master valve is compulsory.

P-1-M-7110 4.8



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2.8.2. Use of an additional hydraulic swab valve having the samecharacteristics as the working valve for operations on wells with

STHPε 10,000psi is suggested.

P-1-M-7110 4.8

2.8.3. The hydraulic test on the additional Swab Valve at the WorkingPressure must be recorded before the installation. The flangedconnection between the additional Swab Valve and the Xmas Treemust be hydraulically tested at Working Pressure before thePressure Control Equipment rig up

P-1-M-7110 4.8

2.8.4. Hydraulic swab valve actuator shall be double action. P-1-M-7110 4.8

2.8.5. The pump to activate the hydraulic swab valve shall be positioned30m from the wellhead.

P-1-M-7110 4.8

3. WIRE SELECTION Reference

3.1. Diameter selection P-1-M-7110 5.1

3.1.1. Light Duty Operations shall be carried out with OD 0.092” wire. P-1-M-7110 5.1

3.1.2. Heavy Duty Operations shall be carried out with a wirelinediameter allowing a maximum pull load during normal operationsnot exceeding the yield strength by 50%.

P-1-M-7110 5.1

3.2. The use of 0.108" or 0.125" slickline to perform heavy-duty

operations is recommended.

P-1-M-7110 5.1

3.3. The Wireline Superintendent may make exceptions to theseregulations by selecting and authorising a wireline for some specialoperations (i.e. gradient recording on HP/HT wells).

P-1-M-7110 5.1

3.4. Material selection P-1-M-7110 5.2

3.4.1. Wire line cable shall be made of material resistant to well fluidcorrosion

M-1-M-4001P-1-M-7110 5.2

4. TOOLSTRING SELECTION Reference

4.1. General P-1-M-7110 3

4.1.1. The wireline toolstring is composed of: rope socket, stem, jars,knuckle joints.

P-1-M-7110 3.1

4.1.2. Wireline toolstrings shall have standard diameters of 11/4” and 1

1/2”

OD. Diameters of 1”, 111/16” and 17/8” OD are allowed for particular operations only by the Wireline Superintendent’s authorisation.

P-1-M-7110 3.1



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4.1.3. The service tools (running tools, pulling tools etc.) are notconsidered an integral part of the wireline toolstring.

P-1-M-7110 3.1

4.1.4. Connections for standard operations shall be threaded. Operationson flowing wells, operations on wells where strong jar action isexpected and operations on HP-HT wells shall be carried out with‘Quick-lock’ connections.

P-1-M-7110 3.2.6

4.1.5. Threads of connections of 11/4” and 1

1/2” OD components shall be

15/16”- 10 UNF.

P-1-M-7110 3.2.6

4.1.6. Threads of connections of OD 1” components shall be 5/8”-11 UNF.

Threads of connections of OD 111/16” and OD 17/8” components

shall be 11

/16” - 10 UNF.

P-1-M-7110 3.2.6

4.1.7. The standard material for the wireline string components is AISI4140.

P-1-M-7110 3.1

4.1.8. Material for the wireline string components in H2S service wellsshall be defined in accordance with the Wireline Supervisor,Superintendent, STAP and TEAP departments.

P-1-M-7110 3.1

4.1.9. All wireline toolstring components shall be equipped with externalfishing necks suitable to be latched by standard OTIS or CAMCOpulling tools.

P-1-M-7110 3.1

4.2. Assembly selection P-1-M-7110 3.2

4.2.1. Rope Socket P-1-M-7110 3.2.1

4.2.1.1. The ‘Disc-spring Type’ rope socket shall be used for light dutyoperations.

P-1-M-7110 3.2.1

4.2.1.2. The ‘No-knot Type’ rope socket shall be used for heavy-dutyoperations and with H2S service wire.

P-1-M-7110 3.2.1

4.2.2. StemP-1-M-7110 3.2.2

4.2.2.1. They can be 1ft, 2ft or 3ft long. P-1-M-7110 3.2.2

4.2.2.2. They shall be manufactured out of a single block of drawn steel. P-1-M-7110 3.2.2

4.2.2.3. ‘Filled Type Stem’ can be used filled with Tungsten alloy. P-1-M-7110 3.2.2

4.2.3. The ‘Filled Type Stem’ external barrel must have an equalisinghole and the threads locked by an Allen screw.

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4.2.4. Jars P-1-M-7110 3.2.3

4.2.4.1. For light duty the ‘Link Type Jar’ with a stroke from 20” to 30” isused in the wireline toolstring.

P-1-M-7110 3.2.3

4.2.4.2. For heavy duty the Hydraulic Jar or Upstroke Jar is used in thewireline toolstring set above the ‘Link Type Jar’.

P-1-M-7110 3.2.3

4.2.4.3. Use the Tubular Jar instead of ‘Link Type Jar’ in the wirelinetoolstring for fishing.

P-1-M-7110 3.2.4

4.2.4.4. Use the Upstroke Jar and the ‘Link Type Jar’ in the wireline stringfor operations on HP-HT wells.

P-1-M-7110 3.2.2

4.2.4.5. The use of ‘Knuckle Jar’ is allowed for particular operations on theWireline Supervisor’s authorisation.

4.2.5. Knuckle joints P-1-M-7110 3.2.5

4.2.5.1. The number and position of knuckle joints are planned inaccordance with the completion type, well deviation, type of wireline operation to be performed, and previous experience

P-1-M-7110 3.2.5

4.2.5.2. The inclusion of knuckle joints in the wireline toolstring for operations on vertical wells, or in heavy jarring operations is not

recommended due to its design, which represents a weak point inthe wireline toolstring.

P-1-M-7110 3.2.5

4.2.5.3. The use of ‘Knuckle Joint’ is allowed only in directional wells andthe number and the position inside the Wireline toolstring will bedefined by the Wireline Superintendent while programming theoperation.

P-1-M-7110 3.2.5

4.3. Toolstring Selection

4.3.1. In 23/8” OD completion use a wireline toolstring of 1

1/4” OD to run in

static conditions. The 11/2” OD is allowed to retrieve flow control

equipment.

P-1-M-7110 3.1

4.3.2. In 27/8” OD completion use a wireline toolstring of 1

1/2” OD to run in

static conditions.

P-1-M-7110 3.1

4.3.3. In 31/2” OD completion use a wire line string of 1

1/2” OD to run in

static conditions.

P-1-M-7110 3.1

4.3.4. In completions smaller than 23/8” OD use a wireline toolstring

diameter of 1” OD to run in static conditions.

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4.3.5. For completions larger than 31/2” OD a wireline toolstring of 1

1/2” or

1 7/8” OD can be used, if provided in the planning.

P-1-M-7110 3.1

4.3.6. The wireline toolstring diameter and composition to operate indirectional wells shall be provided by preplanning and agreed uponby the Wireline Superintendent and Well Area EngineeringDepartment.

4.3.7. The wireline toolstring diameter and the composition to operate inflowing wells shall be provided by preplanning and agreed upon bythe Wireline Superintendent and Well Area EngineeringDepartment.

5. RIG UP/DOWN OPERATIONSReference

5.1. Toolstring Weight Determination P-1-M-7110 8.1.1

5.1.1. The weight of the wireline toolstring is the sum of required weightsas follows:

• To balance the force resulting from wellhead pressure actingon the wire area and to overcome the friction of the wire onsheaves and stuffing box.

• To provide mass for jar action.

P-1-M-7110 8.1.1

5.2. Rig Operations: rig up during well completion P-1-M-7110 8.2.1a

5.2.1. It is the responsibility of the Eni-Agip Supervisor to provideinstructions and documentation required by the operation, inparticular:

• Operation programmes.

• Completion design including depths and diameters of equipment.

• Height of rotary table floor from a reference point (baseflange or upper flange of the tubing spool).

• Type and characteristics of fluid present in the string.

P-1-M-7110 8.2

5.2.2. Selection of surface facilities:

• Sub tubing threaded pin down x quick union box up withconnection for lifting sub.

• ‘T’ member threaded quick union pin x box and 2” Wecolateral outlet (Fig. 1002 or 1502).

• Wireline BOP with quick union pin down x box up.

P-1-M-7110 8.2.1

5.2.3. The above components shall have an ID to allow the passage of the tool with a maximum diameter according to the completiondesign.

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5.2.4. The unit type shall be selected according to the type of completionand maximum working depth.

Wire size and metallurgy shall be selected according to thecharacteristics of the completion fluid and possible presence of corrosive fluids (e.g. H2S, brine with corrosive components).

P-1-M-7110 8.2.1

5.2.5. The Wireline Crew shall be qualified to conduct all plannedoperations without creating interruptions in the activity.

P-1-M-7110 8.2.1a

5.2.6. The Wireline unit shall be equipped with at least the following:

• Components of the wireline string sufficient to make up twostrings.

• Gauge cutters suitable to the completion design.

• Wire suitable to fluids present/expected in hole as well asmechanical stress.

• Fishing equipment suitable to the completion design (e.g.Wireline grabs, wire cutters Go Devil, impression blocks,etc.), and wireline string used (pulling tools, fishing socket,etc.).

P-1-M-7110 8.2.1a

5.2.7. The rope socket must be:

• For Heavy-Duty Jobs use a ‘no knot’ type.

• For Light-Duty Jobs the use of a conventional rope socket,

making it with 15 turns, is allowed.

P-1-M-7110 8.2.1

5.2.8. After assembling, check that the rope socket is free to rotatearound the wire

P-1-M-7110 8.2.1

5.3. Rig Up During Production P-1-M-7110 8.2.1b

5.3.1. The surface facilities are composed of a lubricator, stuffing box,BOP and adapter flange. Such components shall be suitable to theoperation according to the following criteria:

• Lubricator ID adequate to the max. tool size of the equipment

be used.• WP greater or equal to the Xmas tree WP.

• Compatibility of materials with fluids present in hole.

• Additional equipment, i.e. injection nipple and safety checkunion can be decided according to the type of operation andwell condition.

P-1-M-7110 8.2.1b

5.3.2. Wire size and metallurgy shall be selected according tocharacteristics of the completion, formation fluids and reservoir temperature

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5.3.3. The Wireline unit shall be equipped with a minimum of equipmentincluding:


• Gauge cutter of a suitable diameter to the completion design.

• Wire suitable to fluids present or expected in the hole as wellas mechanical stress.

• Fishing equipment suitable to the completion design (e.g.:Wireline. grabs, Go Devil wire cutters, impression blocks,etc.), and to the wireline string used (pulling tools, fishingsocket, etc.).

• Shifting tools, running and pulling tools of suitable size.

• Amerada mechanical and/or memory gauges and all relevantequipment.

• Plugs for possible shut off levels and well securing.

P-1-M-7110 8.2.1b

5.4. Jack-Up/Fixed Plat form/Barge-Rig Up During Wel l Complet ion P-1-M-7110 8.2.2a

5.4.1. Rig up during well completion operations are wireline operationsperformed during the well completion phase.

P-1-M-7110 8.2.2a

5.4.2. Selection of the surface facilities:

• Sub tubing threaded pin down x quick union box up with

connection for lifting sub.

• ‘T’ member threaded quick union pin x box and 2" Wecolateral outlet (Fig. 1002 or 1502).


P-1-M-7110 8.2.2a

5.4.2.1. The above components shall have an ID to allow the passage of the tool with a maximum diameter according to the completiondesign.

P-1-M-7110 8.2.2a

5.4.3. The unit type shall be selected according to the type of completionand maximum working depth.

P-1-M-7110 8.2.2a

5.4.4. The wire size and metallurgy shall be selected according to thecharacteristics of the completion fluid and the possible presence of corrosive fluids (e.g. H2S, brine with corrosive components).

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5.4.5. The Wireline Crew shall be qualified to withstand all plannedoperations without creating interruption in the activity.

• Light Duty Crew shall be used when dealing with a singlecompletion of a limited depth.

• Heavy Duty Crew shall be used when dealing with singleselective or dual completion with several sliding sleeves,landing nipples, surface controlled safety valves.

P-1-M-7110 8.2.2a

5.4.6. The Wireline unit shall be equipped with at least the following :


• Gauge cutters suitable for the completion design.

• Wire suitable to fluids present/expected in hole as well as for mechanical stress.

• Fishing equipment suitable for the completion design (e.g.,Wireline grabs, Go Devil wire cutters, Impression blocks, etc.)and wireline string used (pulling tools, fishing socket, etc.).

P-1-M-7110 8.2.2a

5.5. Jack-Up/Fixed Plat form/Barge-Rig Up During Production P-1-M-7110 8.2.2b

5.5.1. These are wireline operations carried out in a pressured hole. P-1-M-7110 8.2.2b

5.5.2. The surface facilities are composed of a lubricator, stuffing box,

BOP and adapter flange. Such components shall be suitableaccording to following criteria:

• The Lubricator ID adequate to the max. tool size of theequipment to be used.

• WP is greater or equal to the Xmas tree W P.


• Additional equipment, i.e. injection nipple and safety checkunion can be decided according to type of operation and wellcondition

P-1-M-7110 8.2.2b

5.5.3. The unit type shall be selected according to the completion and

maximum depth of work. Wire size and metallurgy shall beselected according to the characteristics of the completion,formation fluids and reservoir temperature

P-1-M-7110 8.2.2b

5.5.4. The composition of the Wireline Crew shall be qualified towithstand all the planned operations without creating interruptionsin the activity.

The employment of a Heavy Duty Crew or Light Duty Crewdepends on the diameter of completion string, working pressure of surface equipment, duration and type of operation.

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5.5.5. The wireline unit shall be equipped with a minimum of equipmentincluding :



• Wire compatible to the fluids present/expected in hole as wellas mechanical stress.

• Fishing equipment suitable to the completion design (e.g.,Wireline grabs, Go-Devil wire cutters, impression blocks,etc.), and to the wireline string used (pulling tools, fishingsocket, etc.).



• Plugs for the possible shut off levels and well securing

P-1-M-7110 8.2.2b

5.6. Dr il l Sh ip/Semi-Submersible, Rig Up During Wel l Complet ion P-1-M-7110 8.2.3a

5.6.1. Rig up during well completion operations are wireline operationsperformed during the well completion phase.

P-1-M-7110 8.2.3a

5.6.2. Selection of surface facilities:

• Sub tubing threaded pin down x quick union box up with

connection for lifting sub.

• ‘T’ member threaded quick union pin x box and 2” Wecolateral outlet (Fig. 1002 or 1502).


The above components shall have an ID to allow the passage of the tool with a maximum diameter according to the completiondesign

P-1-M-7110 8.2.3a

5.6.3. The unit type shall be selected according to the type of completionand maximum working depth. Wire size and metallurgy shall beselected according to the characteristics of the completion fluid

and the possible presence of corrosive fluids (e.g., H2S, brine withcorrosive components).

P-1-M-7110 8.2.3a

5.6.4. The Wireline Crew shall be qualified to withstand all plannedoperations without creating interruptions in the activity.

• A Light Duty Crew shall be used when dealing with a singlecompletion on wells of a limited depth.

• A Heavy Duty Crew shall be used when dealing with singleselective or dual completion with several sliding sleeves,landing nipples, surface controlled safety valves

P-1-M-7110 8.2.3a



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5.6.5. The wireline unit shall be equipped with at least the following :



• Wire suitable to fluids present/expected in hole as well as for mechanical stress.

• Fishing equipment suitable for the completion design (e.g.,Wireline grabs, Go Devil wire cutters, impression blocks,etc.), and wireline string used (pulling tools, fishing socket,etc.).

P-1-M-7110 8.2.3a

5.7. Dr il l Sh ip/Semi-Submersible- Rig Up During Production P-1-M-7110 8.2.3b

5.7.1. These are wireline operations carried out in a pressured hole. P-1-M-7110 8.2.3b

5.7.2. The surface facilities are composed of a lubricator, stuffing boxand BOP. With a temporary Xmas tree available, the connection tothe lubricator normally takes place by means of a crossover threaded pin down x quick union box up. Furthermore, the Xmastree will be already compensated by means of the lifting frame.

P-1-M-7110 8.2.3b

5.7.3. Such components shall be suitable to the operation according tofollowing criteria:

• The lubricator ID adequate to the max. tool size of theequipment to be used.

• WP greater or equal to the Xmas tree WP.


• Additional equipment, i.e, injection nipple and safety checkunion can be decided according to type of operation and wellconditions.

P-1-M-7110 8.2.3b

5.7.4. The unit type shall be selected according to the completion andmaximum depth of work. Wire size and metallurgy shall beselected according to the characteristics of the completion,formation fluids and reservoir temperature

P-1-M-7110 8.2.3b

5.7.5. The composition of the Wireline Crew shall be qualified towithstand all planned operations without creating interruptions inthe activity. The employment of Heavy Duty Crew or Light DutyCrew depends on the diameter of completion string, workingpressure of surface equipment, duration and type of operation

P-1-M-7110 8.2.3b



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5.7.6. The wireline unit shall be equipped with a minimum of equipmentincluding :



• Wire compatible to the fluids present/expected in hole as wellas mechanical stress.

• Fishing equipment suitable to the completion design (e.g.Wireline grabs, Go Devil wire cutters, impression blocks,etc.), and to the wireline string used (pulling tools, fishingsocket, etc.).



• Plugs for the possible shut off levels and well securing

P-1-M-7110 8.2.3b

5.8. Rigless operations P-1-M-7110 8.3

5.8.1. Rigless Operations are the operations carried out without rigs,either onshore or offshore by using equipment and Wireline Crewsfor HD (Heavy Duty) or LD (Light Duty) Jobs, according to the typeof equipment, completion and duration of the operation.

P-1-M-7110 8.3

5.8.2. It is the responsibility of the Eni-Agip Supervisor to giveinstructions and documentation required for the operation and inparticular :

• Completion Design

• Wellhead Tubing Hanger Design

• Last Wireline Report (ARPO-11)

• Last P&T Gradients Report (ARPO-12)

• Type and characteristics of the fluid present in the string.

The Wireline Programme shall report:

• Type of wellhead connections.• Wire type and size to be used.

• Design of the workstring to be used.

• Maximum expected THP.

• Type and position of the flow control equipment in the hole.

• Type of running/pulling tools.

• Type of pressure and temperature recorder.

P-1-M-7110 8.3

5.8.3. The Wireline Crew equipment shall include all equipment of individual protection and fire fighting required to comply with therules issued by the Operations Responsible.

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5.8.4. Heavy Duty Land Operation P-1-M-7110 8.3.1

5.8.4.1. Operations defined as Heavy Duty Land Operation are thoseconducted on wells completed with 3

1/2" tubing or higher size, or

with surface equipment rated 15,000psi or higher.

P-1-M-7110 8.3.1

5.8.4.2. The surface equipment shall be selected according to the followingparameters:

• WP and Xmas tree size.

• Max. size of the tools to be used according to the nipplespresent in the string.

• Characteristics of the fluids present in hole.

• The composition of the Wireline Crew and the type of unitshall be required by HD type.

P-1-M-7110 8.3.1

5.8.4.3. The wireline unit shall be equipped with a minimum of equipmentincluding:

• Components of the wireline string sufficient to make up twostrings


• Wire suitable to fluids present/expected in hole as well asmechanical stress.

• Fishing equipment suitable to the completion design (e.g.,

Wireline grabs, Go Devil wire cutters, impression block, etc.)and wireline string used (pulling tools, fishing socket, etc.)

• Amerada mechanical and/or memory gauges and relevantequipment.

P-1-M-7110 8.3.1

5.8.5. Light Duty Land Operation P-1-M-7110 8.3.2

5.8.5.1. These are operations conducted on wells completed with amaximum tubing diameter of 27/8" and with surface equipment notexceeding the 10Kpsi.

P-1-M-7110 8.3.2


• WP and Xmas tree size.

• Max size of the tools to be used according to the nipplespresent in the string.

• Characteristics of the fluids present in hole

P-1-M-7110 8.3.2

5.8.5.3. The composition of the Wireline Crew and the type of unit shall berequired by LD type.

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5.8.5.4. The wireline unit shall be equipped with a minimum of equipmentincluding :



• Wire suitable for fluids present/expected in hole as well asmechanical stress.

• Fishing equipment suitable to the completion design (e.g.,Wireline grabs, Go Devil wire cutters, impression block, etc.)and wireline string used (pulling tools, fishing socket etc.)

• Amerada mechanical and/or memory gauges and relevantequipment

P-1-M-7110 8.3.2

5.8.6. Heavy Duty Offshore Operation P-1-M-7110 8.3.3

5.8.6.1. This is the definition of operations conducted on wells, located onproduction fixed platforms, completed with 3

1/2” tubing or higher, or

with 15,000psi surface equipment or higher.

P-1-M-7110 8.3.3


• WP and size of the Xmas tree.

• Max size of the tools to be used according to the nipples

present in the string.• Characteristics of the fluids present in hole

P-1-M-7110 8.3.3

5.8.6.3. The composition of the Wireline Crew and the type of unit shall beof type HD

P-1-M-7110 8.3.3

5.8.6.4. The wireline unit shall be equipped with a minimum equipmentincluding:


• Gauge cutter of a diameter suitable to the completion type

• Wireline suitable to the characteristics of the fluid present inhole as well as mechanical stress

• Fishing equipment suitable to the completion type (e.g.,Wireline grabs, wire cutters, Go Devil, impression block, etc.)and wireline string used for pulling tools, fishing socket etc.)


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5.8.7. Light Duty Offshore Operation P-1-M-7110 8.3.4

5.8.7.1. This is the definition of operations conducted on wells, located onproduction fixed platforms, completed with 2

7/8” tubing or smaller,

or with 10,000psi surface equipment or less.

P-1-M-7110 8.3.4

5.8.7.2. The selection of the surface equipment shall be done according tothe following parameters:

• WP and size of the Xmas tree

• Max. size of the tools to be used according to the nipplespresent in the string

• Characteristics of the fluids present in hole

P-1-M-7110 8.3.4

5.8.7.3. The composition of the Wireline Crew and the type of unit shall beof type LD

P-1-M-7110 8.3.4

5.8.7.4. The wireline unit shall be equipped with a minimum equipment andincluding:


• Gauge cutter of a diameter suitable to the completion type

• Wireline suitable to the characteristics of the fluid present inhole as well as mechanical stress

• Fishing equipment suitable to the completion type (e.g.:wieline grabs, wire cutters go devil, impression block, etc.)and type of wire string used (pulling tools, fishing socket etc.)


P-1-M-7110 8.3.4

5.8.8. Other operations

5.8.8.1. Provide necessary work permits, signed by the Production UnitManager or his deputy and by the Safety Manager or his deputy.

5.8.8.2.Remove from the well head area any object that can be anobstacle or a risk to the operation.

P-1-M-7110 8.3.2.1

5.8.8.3. Verify that the cellar is free from H2O and/or inflammable materialand the practicability of walkways and barriers.

P-1-M-7110 8.3.2.1

5.8.8.4. Check the wellhead top flanges and verify to have the proper adapter available.

P-1-M-7110 8.3.2.2

5.8.8.5. Inspect the stuffing box, if necessary replace packing, and makeup the rope socket.

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5.8.8.6. Assemble the lubricator on the ground or on suitable supports. Assemble the wire line working string according to the program

and put it in the lubricator (operation to be carried out with 2persons at the least), screw an aluminium plug on the thread of thelubricator lower section.

Make up the lubricator on the appropriate gantries withoutremoving the lower thread protector. Install a bleeder valve on thelower joint of the lubricator.

P-1-M-7110 8.3.2.15

5.8.8.7. Connect the wireline toolstring to the rope socket. Connect thestuffing box to the lubricator.

P-1-M-7110 8.3.2.22

5.8.8.8. Lift up the lubricator with the hook of the travelling block, leaning

the wire line string on the aluminium plug; bring the lower connection just above the BOP top connection.

5.8.8.9. Control all the weight measure equipment. Install the pressuretransducer (Martin-Decker load cell) and the sheaf to the wellhead, in such a way that the wire forms a 90° angle.

P-1-M-7110 8.3.2.25

5.8.8.10. Set the wire in the sheave groove. Lift up the wire line workingstring with the reel, unscrew the aluminium plug from the lubricator bottom connection; make sure that the weight showed by theweight indicator in the operator cabin is equal to theoreticalcalculated; otherwise act on the instrumentation as per

manufacturer procedures.

P-1-M-7110 8.3.2.27

5.8.8.11. Lower the working string to the work floor The weight indicator should indicate zero. Lift the string and check that the weightindicator reading corresponds to the calculated weight. If the checkis negative clean the line and/or manually re-adjust theinstrumentation.

P-1-M-7110 8.3.2.30

5.8.8.12. Connect the required tool to the wireline toolstring P-1-M-7110 8.3.2.31

5.8.8.13. Bring the tool at the height of the reference flanges and set to zero

the depth counter.

P-1-M-7110 8.3.2.32

5.8.8.14. Abandon the location and restore conditions. P-1-M-7110 8.3.2.47

6. NDT PROCEDURES Reference

6.1. The wireline system is defined as the package required to conductwireline operations on a well and includes the winch, power pack,pressure control equipment and all other relevant auxiliaryequipment.

P-1-M-7110 15.0



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6.2. All surface equipment and the wireline cable must have a series of periodical non-destructive tests (NDT) carried out.

P-1-M-7110 15.0

6.3. A visual inspection must be conducted periodically on all theequipment before each pressure test

P-1-M-7110 15.0

6.3.1. All surface equipment components shall be accompanied by acertificate of the last hydraulic test and non-destructive test theyhave been submitted.

P-1-M-7110 15.0

6.3.2. All the surface equipment must be marked with a uniqueidentification code on a alphanumeric nameplate, from which itmust be possible to identify the equipment number, workingpressure, type of material and type of service.

P-1-M-7110 15.0

6.3.3. The Wireline Supervisor (if applicable) and the Contractor’s Quality Assurance Manager, or his appointed delegate, are responsible for the registration of the tests and for the correct procedures to befollowed.

P-1-M-7110 15.0

6.4. Surface equipment Test schedules P-1-M-7110 15.1

6.4.1. Stuffing box P-1-M-7110 15.1.1

6.4.1.1. A visual inspection every 12 months. P-1-M-7110 15.1.1

6.4.1.2. Pressure test every 12 months. P-1-M-7110 15.1.1

6.4.1.3. Magnaflux on body and thread and , in case, penetrant liquidcontrol on the thread every 24 months.

P-1-M-7110 15.1.1

6.4.2. Safety quick unions P-1-M-7110 15.1.2

6.4.2.1. Visual inspection every 12 months. P-1-M-7110 15.1.2


6.4.2.3. Magnaflux on body and thread and, in case, penetrant liquidcontrol on the thread every 24 months.

P-1-M-7110 15.1.2

6.4.3. Injection nipple P-1-M-7110 15.1.3




P-1-M-7110 15.1.3



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6.4.4. Lubricator P-1-M-7110 15.1.4

6.4.4.1. Visual inspection as per point 6.3.1 every 12 months. P-1-M-7110 15.1.4



P-1-M-7110 15.1.4

6.4.4.4. ‘X’ ray examination for lubricator sections with welded connectionsevery 24 months.

P-1-M-7110 15.1.4

6.4.5. BOP’s P-1-M-7110 15.1.5


6.4.5.2. Pressure test every 12 months, or each time redressed. P-1-M-7110 15.1.5

6.4.5.3. Magnaflux on body and thread and, in case, penetrant liquidcontrol on the thread 24 months.

P-1-M-7110 15.1.5

6.4.5.4. ‘X’ ray examination for BOP with connections welded every 24months.

P-1-M-7110 15.1.5

6.4.6. Adapter flange P-1-M-7110 15.1.6




P-1-M-7110 15.1.6

6.5. Specification for control

6.5.1. Visual inspection P-1-M-7110 15.2.1

6.5.1.1. Visual inspection inside all assembly for notching detection causedby wire running, cuttings detection and recognition of thicknessthinning. To be performed before pressure test.

P-1-M-7110 15.2.1.1

6.5.1.2. Visual inspection of every quick union to look for damage onthread and in particular on sealing surface and on groves.

P-1-M-7110 15.2.1.2

6.5.1.3. Visual inspection on BOP with special attention to sealingsurfaces, to elastomers characteristics, to hydraulic connections.To be performed before pressure test.

P-1-M-7110 15.2.1.3



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6.5.1.4. Visual inspection of adapter flange with particular attention to ring joint seats.

P-1-M-7110 15.2.1.4

6.5.1.5. For every component examined, draw up the Visual inspectionbook to be carefully kept by the Wireline Supervisor or by thecontractor Base Manager.

P-1-M-7110 15.2.1.5

6.5.2. Pressure test for lubricator equipment P-1-M-7110 15.2.2

6.5.2.1. Pressure the working pressure, hold pressure for 15 min., checkfor leaks and bleed off.

P-1-M-7110 15.2.2.1 P-1-M-7110 15.2.2.2

6.5.2.2. Repeat the procedure twice. P-1-M-7110 15.2.2.3

6.5.2.3. Bleed off pressure and control sealing components condition. P-1-M-7110 15.2.2.4

6.5.2.4. Tests shall be recorded on paper and/or magnetic support to beattached to the book.

P-1-M-7110 15.2.2.5

6.5.2.5. For every component examined, draw up the Visual inspectionReport book to be carefully kept by the Wire Line Supervisor or bythe contractor Base Manager.

P-1-M-7110 15.2.2.6

6.5.3. Pressure test BOP P-1-M-7110 15.2.3

6.5.3.1. Pressurise to working pressure with open rams, hold pressure for 15 min, check for leaks and bleed off.

P-1-M-7110 15.2.3.1P-1-M-7110 15.2.3.2

6.5.3.2. Repeat the procedure twice. P-1-M-7110 15.2.3.3

6.5.3.3. Pressurise to working pressure with closed rams pumping fromwell direction, hold pressure for 15 min, and check for leaks andbleed off.

6.5.3.4. Repeat the procedure twice.

6.5.3.5. Tests shall be recorded on paper and/or magnetic support to be

attached to the book.

P-1-M-7110 15.2.3.5

6.5.3.6. For every component examined, draw up the BOPs Pressure TestReport Book to be carefully kept by the Wire Line Supervisor or bythe contractor Base Manager.

P-1-M-7110 15.2.3.6

6.5.4. Radiographic Examination (x-ray) P-1-M-7110 15.2.5

6.5.4.1. The examination shall be carried out by companies included in AGIP vendor list.

P-1-M-7110 15.2.5.1



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6.5.4.2. The examination shall be carried out in accordance with ASMESection 5-2 and ASME 8 div. 1 appendix 6-UW 51 regulations.

P-1-M-7110 15.2.5.2

6.5.4.3. For every component examined, draw up the “RadiographicExamination Report Book” with attached all the negative films. Itwill be carefully kept by the Wireline Supervisor or by thecontractor Base Manager.

P-1-M-7110 15.2.5.3

6.5.5. Magnetic Examination (Magnaflux) P-1-M-7110 15.2.4

6.5.5.1. The examination shall be carried out by companies included in AGIP vendor list.

P-1-M-7110 15.2.4.1

6.5.5.2.The examination will be carried out as per the following Eni-Agipspecifications:

• TECN-708444-S-0400

• TECN-708444-S-0401

• TECN-708444-S-0402.

P-1-M-7110 15.2.4.2

6.5.5.3. Prior to perform Magnaflux, surfaces to be tested shall besandblasted.

6.5.5.4. Sealing surfaces shall be carefully protected before sandblasting.

6.5.5.5. For every component tested, draw up the “Magnetic ExaminationReport Book” to which the report of company who actuallyperformed the work will be attached; that Report Book kept by theWireline Supervisor or by the contractor Base Manager.

P-1-M-7110 15.2.4.3

6.5.6. Hardness Test P-1-M-7110 15.2.6

6.5.6.1. A hardness test of material shall be included in the documentationof every item.

P-1-M-7110 15.2.6.1

6.5.6.2. Surface equipment for standard service shall have a minimumhardness of 200 Brinnell fore material with 80,000psi minimum

yield; a hardness between 290 Brinnell (30 Rockwell C) and 341Brinnell (36 Rockwell C) for material with 110,000psi minimumyield.

P-1-M-7110 15.2.6.2

6.5.6.3. Surface equipment H2S service shall have a hardness notexceeding 22 Rockwell C.

P-1-M-7110 15.2.6.3



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6.6. Controls on Wireline

6.6.1. Controls with induced currents

6.6.1.1. An “Eddy Current Device” apparatus shall be used.

6.6.1.2. Every wire coil of any material shall be tested at the first spooling.

6.6.1.3. The frequency of controls shall be determined on the basis of theseverity of operations performed on the field by the DistrictWireline Supervisor.

6.6.2. Torque test

6.6.2.1. Special equipment in accordance with API 9A regulations shall beused.

6.6.2.2. Testing procedure shall be as indicated in specification.

6.6.2.3. Controls frequency shall be determined, on the basis of operationsseverity performed while working, by the Wireline Supervisor.

6.6.2.4. Every Wireline Unit shall have a report book where wire length,cuts made, maximum overpull made (per operation), torque testand controls made with induced current shall be reported.

6.7. Definition of H2S service

6.7.1. It is necessary to use H2S resistant materials when STHP is equalor greater than 4.5 Kg/cm2 and partial pressure of H2S is equal or greater than 0.0035 Kg/cm2.

6.7.2. Any decision about the material type to be used shall be taken jointly by the District Wireline Supervisor and ARCO, TEAP andSTAP units.



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7. SCSSV TEST PROCEDURES Reference

7.1. Surface tests on installed SCSSVs must be performed in order toidentify any problems on their primary function.

M-1-S-5010E

7.1.1. The failures to be checked are:

• FTC (fail to close on command)

• PCL (premature valve closure)

• FSN (fail to set in nipple)

• LCP (leakage in closed position)

• FTH (fail to hold in nipple)

• FTO (fail to open on command)

• WCL (well to control line communication)

• CLW (control line to well communication)

M-1-S-5010E

7.1.2. The leakage rate shall be less than 25smc/hr (15scf/min) of gas or 400cc/min of fluid.

M-1-S-5010E

7.2. The test sequence shall agree with API RP 14B. M-1-S-5010E

7.3. The test frequency must be every six months. M-1-S-5010E

7.3.1. The test frequency can change when a typical MTTF has beencalculated for homogeneous types of valves.

M-1-S-5010E

Reference Lists:

‘General Wireline Procedures Manual’ STAP-P-1-M-7110

‘Definition of Criteria for Routine Tests on SCSSV’ STAP-M-1-S-5010E



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OP4. MATERIALS AND TRANSPORT

OP. 4.1. WAREHOUSE MATERIALS


1.1. The Materials Supervisor is responsible for receiving, inspecting,checking documentation and storing materials

1.2. The Materials Supervisor is responsible for updating the materialsinventory

1.3. Materials Supervisor will send to the Well Area Department acomplete list of the materials actually dispatched to the wellsite.

1.4. The Drilling & Completion Superintendent is responsible for theevaluation of all materials returned from the wellsite.

2. TUBULARS Reference

2.1. In cases where there are non-conformity of any tubulars, theDrilling & Completion Manager is responsible for determining if they shall be acceptable, or whether they need to be inspected or replaced

A-1-M-1000 2.2.3

2.2. Tubulars should be stored on steel racks with a minimum groundclearance of 0.5 meters; stringers should be of treated wood or

steel; the pipe at the ends of each layer should be wedged toprevent rolling.

A-1-M-1000 3.7.2

2.3. Where special storage is required, the Drilling (or Completion)Superintendent is responsible for providing input to the MaterialsSupervisor

A-1-M-1000 2.4.4

2.4. Depending on the storage life and the pipe yard surrounding,tubulars should be periodically inspected and new protectivecoatings applied when necessary to prevent corrosion

A-1-M-1000 3.2.5

2.5. Under no circumstances should tubulars be lifted with hooks in

their ends.

A-1-M-1000 3.5.2

P-1-M-7120 8.2.5

2.6. Ensure that the closed-end thread protectors are kept in place atall times

A-1-M-1000 3.6.2P-1-M-7120 8.2.5

3. OTHER MATERIALS Reference

3.1. Rubber packing elements, wellhead parts, ring joints, pressuregauges and other particularly delicate materials, must be stored ina dry area and protected from accidental damage.



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3.2. Chemicals must be stocked in a dedicated area and possibly onpallets stored on a cement slab with drain ditches and protected

from rain with plastic covers.

3.3. All mud and cement chemicals shall have a technical and ahazardous substance sheet.

3.4. Tanks and bulk handling equipment should be thoroughly cleanedand aerated before receiving liquid or bulk materials, to preventcontamination from other materials used previously.

3.5. Different bulk materials shall be loaded through separateindependent lines.

3.6. Explosive and radioactive materials should be handled andtransported by the supplier direct to the wellsite.

Reference List :





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OP. 4.2. RIGSITE MATERIALS

1. MINIMUM STOCKS Reference

1.1. The minimum barite stock shall be 100t. When overpressurisedformations are anticipated, barite stock shall be based on expectedformation pressure gradients, on the actual mud weight and on thevolume of the active drilling fluid in the system.

P-1-M-6140 6.5-b

1.2. The minimum cement stock shall be 100t or at least enough toprepare 200m of cement plug.

P-1-M-6140 6.5-c

1.3. A minimum volume of 70mc of kill mud at 1.4kg/l shall be stockedwhile drilling surface hole.

P-1-M-6140 6.5-d

1.4. The minimum bentonite stock shall be 25t or at least enough toprepare a volume of new mud equal to the well volume.

1.5. The industrial water stock must be enough to prepare a volume of new mud equal to the well volume.

1.6. A stock of diesel oil, enough to guarantee five days of operation,must be always kept on rig site.

P-1-M-6140 6.5-g

1.7. Pipe freeing agent. The quantity shall be sufficient to prepare twopills, the volume for each one shall be two times the capacity of theannulus open hole/ BHA.

P-1-M-6140 6.5-g

1.8. 20 drums of dispersant. P-1-M-6140 6.5-g

1.9. Mica (fine, medium, and coarse) 1.5t of each P-1-M-6140 6.5-g

1.10. 3t of Wall Nut P-1-M-6140 6.5g

1.11. Viscosifer for salt water (i.e. Biopolymer) the quantity shall besufficient to prepare 200 m

3

P-1-M-6140 6.5-g

1.12. The mud in the pits shall be never less then 50% of the holevolume.

1.13. Should the stocks fall below the minimum requirement, for bariteand diesel oil, drilling operation shall be suspended.

P-1-M-6140 6.5

2. TUBULARS Reference

2.1. Certifications

2.1.1. The Contractor shall provide evidence on the identification code onevery new and used tool.

All rented tools without an identification code shall be rejected.

M-1-SS-5707 6.3M-1-SS-5710 5.3.2



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2.1.2. The Contractor shall operate an appropriate “managementsystem” which records and updates the following information:

• Rotating hours calculations

• Sequence of rig sites/drilled wells

• Movements record between rig sites

• Inspection scheduling

• Inspection results

• Threads re-cutting

• Connection shoulders re-facing

2.1.3. The Contractor must send every tool to the rig site accompaniedwith proper documentation/certification

M-1-SS-5707 1.

2.2. BHA/Drill stem components

2.2.1. All stabilisers shall be the ‘integral type’ and machined from asingle block of material or the ‘integral sleeve type’ fitted by heador hydraulic pressure (not threaded).

P-1-M-6100 10.10-3P-1-M-6140 8.10-c

2.2.2. All stabilisers for hole size up to 121/4” must be the tight type in

order to assure a complete (360°) contact with the borehole.

M-1-SS-5707 5-4.1P-1-M-6100 10.10-5P-1-M-6140 8.10-e

2.2.3. All stabilisers for hole size over 121/4" must be open type but not

less than 210°.

P-1-M-6100 10.10-5P-1-M-6140 8.10-e

2.2.4. The minimum allowed diameter in correspondence of groovesshall be >/= OD of the fishing neck.

P-1-M-6140 8.10-f

2.2.5. All stabilisers should have a fishing neck with the same OD as thedrill collars and a length not shorter than 20” for stabilisers up to 6”hole size and 26” for larger hole size stabilisers.

P-1-M-6100 10.10-6P-1-M-6140 8.10-g

2.2.6. The near bit to be used in shallow holes shall have a back flowvalve seat

M-1-M-5012 3.2

2.2.7. Stabilisers must have a minimum fishing neck length as listed

below:

used

5”3/4 to 6” >>>>>>> 20”

8”3/8 to 28”>>>>>>> 26”

new

5”3/4 to 6” >>>>>>> 24”

8”3/8 to 28”>>>>>>> 36”

M-1-SS-5707 5.4.2



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2.2.8. The use of hard-banded drill pipe is not allowed inside casing. P-1-M-6140 9.4.5

2.2.9. All drill collars, drill stem and BHA components connection musthave stress relive/bore features.

85/8” threads must have ‘low face torque’ features.

M-1-SS-5710 4.2.1.2M-1-SS-5710 5.2

2.2.10. The following minimum length for drill stem subs, from shoulder toshoulder, are required: (Refer to

Figure OP 4.1)

type “A” API >= 30” (762 mm)

type “B” API >= 36” (914,4 mm)

type “C” API >= 6” (152,4 mm)

M-1-SS-5710 4.2.2.4

2.2.11. All rotary drilling equipment (drill string/BHA) shall be marked withthe Contractor’s identification/management code.

M-1-SS-5710 9.

2.2.12. Drilling jars shall have both a jarring up action and a bumpingdown mechanism.

M-1-SS-5707 5.5.1

2.2.13. Minimum OD of non-magnetic drill collars/sub shall be the same asthe drill collars to be connected.

M-1-SS-5707 5.7.2

2.2.14. PDM motors shall be suitable for use with all water and oil base

drilling mud

M-1-SS-5707 5.10

2.2.15. An appropriate fishing tool/extension, able to engage anykind/profile of PDM, must be available on the rig site.

M-1-SS-5707 5.10.3

2.2.16. All BHA / drill stem components must be stored on the pipe rack or on wood with doped thread protectors.

2.2.17. In no circumstances lift tubulars with hooks in their ends. A-1-M-1000 3.5.2

2.2.18. When rolling pipe along stringers, ensure that connection (eventhough fitted with protectors) do not contact adjacent lengths.

P-1-M-7120 8.2.5

2.2.19. The following materials for current hole size shall be available onrig site while drilling:

• One super junk mill

• One drilling jar

• One complete set of stabilisers.

2.2.20. Whenever possible maintain constant the ID of the string and inany case never less than:

• 31/2” If and bigger 2

1/4”

• less than 31

/2” IF 2”



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3. MATERIAL CARE Reference

3.1. Rubber packing elements, slips, pressure gauges, ring joints and

other materials particularly delicate must be stored in a dry areaand protected from accidental damaging.

3.2. Wellhead parts, liner and cementing equipment shall be carefullystored in a dedicated area, protected from accidental damaging.

3.3. Bits, centralises and other materials packed in cartons mustprotected from rain with a plastic cover.

3.4. Mud chemicals and cement additive must be stocked in adedicated area, possibly on a cement slab (on-shore) with drainditches and protected from rain with a plastic cover.

3.5. For each mud and cement chemical on rig site shall be present atechnical and dangerousness sheet.

3.6. Casings and tubing’s whenever possible shall be placed on rack.

Thread protectors must be in place when moving or handling pipesand shall be removed just before run.

3.7. Prior to being returned from the rig, tubulars shall be properlycleaned and prepared for transport with doped thread protectors inplace.

A-1-M-1000 2.8.2

3.8. Barite bulk equipment must be operational at any moment.

Dust filters must be kept clean and working efficiently at all times.

Air blowers must be kept clean and free of obstructions.

3.9. A sample of barite must be take and its pH checked beforedischarging in bulk.

Any barite contaminated buy cement shall be rejected.

4. EXPLOSIVES Reference

4.1. All explosives must be transported by authorised means asspecified by ICAO (International Civil Aviation Organisation).

Transport by helicopter is forbidden.

4.2. Local legislation may dictate storage and transporting procedures P-1-M-6140 13.2.4-3

4.3. Only authorised personnel shall handle explosives P-1-M-6140 13.2.4-8

4.4. When handling explosives, everybody, if not directly involved in theoperations, shall stay away from the area.

P-1-M-6140 13.2.4-8



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4.5. The area should be marked off with barrier tape. P-1-M-6140 13.2.4-8

4.6. Explosives are to be transported unarmed and clearly labelled tothe site in secure and protective containers. Extreme care must beapplied during loading and off-loading.

P-1-M-7120 5.3-k

4.7. Explosive and detonators shall always be transported and stored inseparate containers.

P-1-M-6140 13.2.4-3P-1-M-7120 5.3-e

4.8. Explosive shall be kept on rig site for the minimum time requiredfor operations and during such time they shall be stored in adesignated locked container in a security area

P-1-M-6140 13.2.4-5P-1-M-7120 5.3-d

4.9. Explosives should never be stored in the vicinity of other hazardous materials.

P-1-M-6140 13.2.4-5

4.10. Any remaining at the end of the operation shall be removed fromthe installation.

P-1-M-6140 13.2.4-d

4.11. The quantity of explosives stored must be kept to a minimum. P-1-M-6140 13.2.4-4

4.12. The wellhead, derrick and logging unit must be earthed together during operations involving explosives.

P-1-M-6140 13.2.4-6

4.13. If the electric potential between wellhead, derrick and logging unit

exceed 0.25 Volts, operations involving the use of explosive shallbe suspended.

4.14. Any source of electric potential, including radio transmitter andwelding equipment, shall be switched off, while guns are beingprimed and down to 30m (100ft) below rotary table.

P-1-M-6140 13.2.4-11

4.15. A complete record must be kept of all explosives received, stowedor off-loaded.

4.16. Platform should be equipped with an emergency system to dropexplosive’s container directly in the sea in case of an

uncontrollable dangerous situation.

5. RADIOACTIVE SOURCES Reference

5.1. Radioactive sources must be transported by authorised means asspecified by ICAO (International Civil Aviation Organisation).

Transport by helicopter is forbidden.

5.2. Whenever the radioactive source is not in use, it shall be stored ina locked shield container clearly marked with standard radioactivewarning signs on all sides.

P-1-M-6140 13.2.4-3



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5.3. Offshore

5.3.1. When transported by ship, radioactive sources shall be secured ina shipping container properly marked with radiation warning signs.

P-1-M-6140 13.2.4-1

5.3.2. Whenever the radioactive sources is not in use, it shall be storedin a locked shield container, welded to rig deck and clearly markedwith standard radioactive warning signs on all visible sides.

The container shall be stored far away from crew’s quarters,regularly occupied workspace or food stuffs stowage.

The keys of the container shall be kept by the Barge Master.

P-1-M-6140 13.2.4-3

5.3.3. During transfer of shipping container from supply vessel to the rigand vice versa, shall be very carefully to prevent loss of container.

P-1-M-6140 13.2.4-2

5.4. Radiation levels shall be monitored on a regular basis. A logshould be kept of the results of this monitoring.

P-1-M-6140 13.2.4-4

5.5. Radioactive sources shall be kept on rig site only the time strictlynecessary.

P-1-M-6140 13.2.4-5

5.6. During transfer of source from the container to the tool, only theContractor personnel shall be present.

P-1-M-6140 13.2.4-7

5.7. If a radioactive tool has been lost in the hole and all the attemptsto fish have proven unsuccessful, the tool must be insulated in thehole by setting a cement plug of at least 150m (500ft) length aboveit, in two separate operations, and at least 50m (150ft) over thefirst non permeable zone.

While circulating with the source in hole, the mud shall becontinuously and carefully monitored by the Contractor engineer using a Gamma-Ray tool immersed in the header tank of the shaleshaker.

P-1-M-6140 13.2.4-9

Reference List :




‘Specification for Rental of Drilling and

Completion Downhole Equipment’ STAP-M-1-SS-5707

‘Specification for Rental and Contractor – Owned

Rotary Drilling Equipment STAP-M-1-SS-5710



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Figure OP 4.1 - Dril l Stem Sub Types

TYPE “A” TYPE “B” TYPE “C”



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OP. 4.3. TRANSPORTATION

1. PERSONNEL Reference

1.1. Air transport

1.1.1. The onshore base, before the helicopter departure, shall informthe offshore rig about:

• Passenger’s list

• Departure time

• Route

• ETA

1.1.2. The helicopter captain is responsible for safety during the flight,

and, before taking off, will organise a briefing with the passengersto explain them the main safety and emergency instructions duringflight and landing on the rig

1.1.3. During the flight, the offshore rig will activate its radio beacon andkeep in constant connection, through VHF, with the helicopter

1.1.4. Assistance should be given, by the person in charge, to thepassengers during embarking and disembarking operations

1.2. Sea transport

1.2.1. The onshore base shall inform the offshore rig (and vice versa)about the crew boat travel:

• Passenger’s list

• Departure time

• Route

• ETA

1.2.2. The boat captain is responsible for safety during the trip and,before leaving, will organise a briefing with the passengers toinform them about:

• Life jacket position

• Lifeboats arrangement

• Safety instructions

• Emergency instructions

1.2.3. During the travel, the offshore rig will keep in constant radioconnection with the boat



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1.2.4. Assistance should be given, by the personnel in charge, to thepassengers during embarking and disembarking operations.

1.2.5. Passengers shall pass from crew boat to the platform (and viceversa) by using the boat landings

1.2.6. In case of boat landing not accessible, the crew basket can beused; in this case:

• Passengers will wear the life jacket

• Passengers will stand on the outside ring and fasten thesafety belt to the basket

• Personal luggage will be placed inside the basket

1.3. Road transport

1.3.1. In particular environmental conditions (desert, snow, long andhazardous trips) the travelling personnel shall inform the point of destination regarding:

• Departure time

• Route

• Expected arrival time (ETA)

1.3.2. For trips in particular environmental conditions the following

equipment requirements shall be taken into consideration:• Radio

• Fuel, lubricants and water emergency supplies

• Desert or snow dotation

• First aid kit

1.3.3. Ensure the vehicle is in good condition and has been properlymaintained.

1.3.4. Observe the local traffic regulations on the public roads.

1.3.5. All the vehicles on location shall be parked inside the proper areaand should not impede other normal activity and rig safety.

2. MATERIALS Reference

2.1. Tubulars

2.2. Handling, transportation, and temporary storage of tubular goodswill comply with Section 3 of API RP 5C1.

P-1-M-7120 8.2.1

2.2.1. In no circumstances lift tubulars by hooks in their ends A-1-M-1000 3.5.2



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2.2.2. Ensure that the closed-end thread protectors are kept in placeduring transportation

A-1-M-1000 3.6.2

2.2.3. Chrome tubulars will be dispatched from the mill in specialtransport frames. These will be loaded into wooden crates for shipment. The tubulars will be covered by nylon sheets, andwrapped with Drilltec Econorap.

P-1-M-7120 8.2.2

2.3. Chemicals

2.3.1. Where possible, mud and cement chemicals will be on pallets andprotected from rain with plastic covers

2.3.2. Tanks and bulk equipment must be thoroughly cleaned andaerated before receiving liquid or bulk materials, to preventcontamination from previous materials.

2.4. Other materials

2.4.1. Where possible, small loose items shall be carried in containers or baskets, to facilitate transport and handling

2.4.2. Baskets shall be periodically inspected; certification, load capacity,and date of inspection clearly exhibited



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OP. 4.4. CORROSION PREVENTION & INSPECTION

1. CORROSION PREVENTION Reference

1.1. Most corrosion problems which occur in oilfield productionoperations are due to the presence of water.

P-1-M-6110 9.1.3

1.2. Handling, transportation, and temporary storage of tubular goodswill comply with Section 3 of API RP 5C1.

P-1-M-7120 8.2.1

1.3. The existence, if any, of the following conditions alone, or in anycombination may be a contributing factor to the initiation andperpetuation of corrosion: O2, H2S, CO2, Temperature, pressure,velocity of fluids within the environmental.

P-1-M-6110 9.1.3

1.4. Corrosion can be influenced by dissimilar metals in close proximityto each other (galvanic corrosion). Therefore it is recommendedthat the same or equivalent materials should be assembled incasing string (i.e.: CRA casing and liner accessories).

A1M1002 2.2.4

1.5. In presence of corrosive environment, the use of inhibitors in themud must be considered.

P-1-M-6150 10.3

2. NDT Reference

2.1. Tubulars

2.1.1. BHA and drill pipe must be inspected by Non Destructive Testingmethods.

All inspection/maintenance operations required for the complianceof rotary drilling equipment shall be carried out at the beginning of the Drilling Contract, before the start up of drilling operations,repeated every six months.

P-1-M-6140 4.9

2.1.2. Copy of the inspection report must be consigned to the Companyrepresentative.



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2.1.3. For severe or particular difficult drilling conditions refer to the ‘DrillString/Bottom Hole Assembly Monitoring Procedures For Severe

or Particular Drilling Condition (M-1-M-5008)’. As a general rule,the following guidelines should be used:

• Before the start of the Drilling Contract and every 1,500rotating hours thereafter, all Drill Pipe bodies shall beultrasonically inspected. They can be replaced by another previously inspected string to allow the NDT.

• Heavy weight drill pipe bodies shall be ultrasonicallyinspected every 3,000 rotating hours. They also may bereplaced by previously inspected pipe to allow NDT.

• Before the start of the Drilling Contract and every 300 rotatinghours, thereafter, all drill collars, drill-stem-subs and heavyweight drill pipe thread connections shall be magneticallyinspected. They also may be replaced by previouslyinspected pipe to allow NDT.

• All stabilisers shall also be inspected every 300 hours asabove.

• After 200-300 drilling hours (depending on the severity of work) remove four stands of 5” DP from the top of the BHAand replace them with new ones. The removed DP must besent to the Contractor’ s workshop for inspection.

P-1-M-6140 4.9-4

2.1.4. All rotary drilling equipment (drill string/BHA) shall be marked with

a Contractor’s identification/managing code.

M-1-SS-5710 9.

2.1.5. The Contractor must send the tool on rig site accompanied byproper documentation/certification.

M-1-SS-5707 1.

2.1.6. The Contractor shall give evidence to have an identification codeon each new and used tool. All rented tools without identificationcode shall be rejected.

M-1-SS-5707 6.3M-1-SS-5710 5.3.2

2.1.7. The Contractor shall use an appropriate ‘management system’which allows the record and the up to dating of the followinginformation’s:

• Rotating hours calculations

• Sequence of rig sites/drilled wells

• Movements record between rig sites

• Inspection scheduling

• Inspection results

• Threads re-cutting

• Connection shoulders re-facing.

M-1-SS-5707 6.3



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2.2. Hoisting equipment and pipe handling tools

2.2.1. All hoisting equipment and pipe handling tools shall be marked andidentified.

M-1-SS-524E 7

2.2.2. All inspections/maintenance operations shall be carried out at thebeginning of the Drilling Contract, before the start up drillingoperation and periodically in accordance with Manufacturer’srecommendations/suggestions

M-1-SS-524E 5.2

2.2.3. The Contractor shall develop a schedule for inspections, repairs,remanufacture, etc.

M-1-SS-524E 5.2.3

2.2.4. All repair, rebuilding and re-manufacturing shall be submitted tothe Customer.

2.2.5. The contractor shall provide the inspection certificate relevant toevery kind of inspection/maintenance operations run during thelast inspection operation.

M-1-SS-524E 5.3.2

2.2.6. All inspection certificate must contain the operative identificationcode of each hoisting equipment and pipe handling tools.

2.2.7. Critical areas of hooks, elevators, elevators links, bails, etc. shallbe inspected peculiarly using magnetic particles inspection wet

method.

M-1-SS-524E 5.4.1

2.2.8. Any surface defect detected by NDT, shall be removed by grindingor machining.

2.2.9. Magnaflux inspection of links, elevators, hook’s pad eyes anddrawwork brakes shall be carried out prior to running particularlyheavy casing strings.

P-1-M-6140 12.1.1-18

Reference List :



‘Acceptance Specification for New and Used

Hoisting Equipment and Pipe Handling Tools’ STAP-M-1-SS-524E



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OP5. WASTE TREATMENT AND DISPOSAL

OP. 5.1. GUIDELINE


1.1. All waste treatment and disposal activities, and/or re-utilisation of the waste produced during the drilling and production operations,aim at avoiding whichever type of pollution and reducing to theminimum the environmental impact.

1.2. All waste treatment and disposal activities, and/or re-utilisation of the waste produced during the drilling and production operations(debris, dehydrated solids, waters or both oil and water basedmud, special waste, sweepings) must be carried out in compliance

with local laws.

1.3. Where foreseen by the legislation and when the wastecharacteristics allow it, reutilization must be preferred to disposal.

1.4. Primary target is to reduce to the minimum the waste production,compatibly with the operative constraints. Such reduction will bepursued by endowing the rig with a double circuit suitable for utilisation of recycled water.

1.5. Technical, economic and logistic evaluations will be performed inorder to define the proper solution when selecting: the type of treatments on solids, waters, and muds; the place where treatmentis carried out (rig site or authorised platform); the equipment for treatment on rig site; the sites for the final destination of waste(reutilization or disposal).

1.6. Even if technical operative constraints and/or environmentallimitations are not expected, the selection of drilling/productionfluids must always be carried out taking into account all theaspects related to debris and exhausted mud reutilization/disposal.

1.7. It will be duty of the operative base to verify the suitability of the

selected contractors for the waste treatment and recovery/disposalas regards the law requirements.

1.8. The documentation and both Company and Contractor reports willbe in accordance with requirements of the local legislation andCompany specifications.



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2. ONSHORE Reference

2.1. For the stocking and eventual treatment of waste, on rig site a

“waste treatment and disposal area” must be provided. Such areawill be equipped with catch basins, a treatment dedicated zone andsufficient areas for movement of the vehicles employed for thetreatment and transport of solids and liquids.

2.2. Number, capacity and disposition of the catch basins for solids andliquids will depend on type of treatment and disposal adopted andon the characteristics of the available area.

2.3. The selection of the catch basins structure will depend onconsiderations related to the well typology and/or environmentalregulations.

2.4. When contra-indications are not expected, it will be preferred arecovery system including a rig site treatment of exhausted mudand debris (close loop) suitable to recover and recycle the water phase for washing purposes and mud preparation.

3. OFFSHORE Reference

3.1. On the basis of the local laws, rig distance from the shore andshore disposal facilities, it must be considered the opportunity of discharging to sea or a zero discharge adoption.

3.2. The drilling fluids selection, among WBM, OBM, SBM or estersbased, will be made considering the possibility and the opportunityof discharging to sea or a waste transport to shore.

3.3. In case of zero discharge, all necessary provisions will be adoptedto avoid sea pouring off; moreover the rig will have to be equippedin a way suitable for stocking and moving an adequate number of waste containers taking into account the foreseen ROP times andtransport conditions on shore.



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SECTION 3 OF BP&MR - REPORTING & FEEDBACK (RF)

SECTION 3

REPORTING & FEEDBACK (RF)



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INDEX

RF1. REPORTING & FEEDBACK 3

RF.1.1. REPORTING AND FEEDBACK FORMS 4

RF.1.2. FINAL DRILLING REPORT 61. INTRODUCTION 62. PRINT MODEL 63. PAGE NUMBERING 64. IDENTIFICATION 65. GRAPHIC REPRESENTATIONS 6

6. PREPARATION OF THE WELL ‘FINAL REPORT’ 67. GENERAL FINAL REPORT STRUCTURE 7



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RF1. REPORTING & FEEDBACK

INTRODUCTIONThe purpose of this section is to highlight Eni/Agip’s standard Reporting and Feedback forms.

The accuracy, rapidity and spreading of information, through the homogeneity of the forms, isconsidered to be very important, in order to compare and evaluate performances in real time,throughout all the different countries and operating contests.

All Eni/Agip supervisory and technical personnel involved in Drilling and Completion activitiesare expected to be familiar with both ARPO and FB forms listed in this section.

In addition to the official ARPO and FB forms (RF.01.01) and the ‘Final Drilling Report’(RF.01.02), which are considered to be the company’s minimum requirement, additional formscan be implemented if Affiliate’s procedures, local legislation or partner’s requirements dictate

otherwise. However, this even more particularly applies if innovative techniques or tools areemployed, in order to spread information and experience within the Company amongpersonnel involved in Drilling and Completion activities.

The rules for the correct filling in and issuing of the standard forms and reports are specifiedin:

• STAP-G-1-F-9057 - “Rules for Filling in the ARPO Reporting Forms”

• STAP-G-1-F-9058 - “Rules for Filling in the FB Feedback Forms”

• STAP-P-1-N-6002 - “Well Final Report Procedure”

The correct filling in and issuing of the standard forms and reports is considered to bemandatory, as it is through this system that easy access to information useful for new studies,analyses or well programmes is gained.

The Corporate Headquarters Drilling & Completion Standards Department (STAP) has anorganised filing systems able to receive all the Reporting & Feedback Forms from the Districtsand Affiliates, both in electronic and paper format.

The filling in of the ARPO and FB forms shall be carried out with a preference to theelectronic format and, when available, to computerised data collection systems. The followingshows (in order of preference) the methods available for filling in the forms:

• Using ‘POWER’, the corporate electronic data collection system

• Using Microsoft Excel files (available in STAP Department at Eni/Agip’s Headquarters)

• In paper format.

The “POWER” system allows automatic transmission of data to an electronic data base in thecorporate Headquarters.

ARPO forms, prepared on either Excel files or paper formats, shall be forwarded by E-mail,fax or by conventional mail to the base office and to STAP department at the Eni/Agipcorporate Headquarters. These forms will be filed in SIDAP, the corporate Drilling &Completion electronic and optical-electronic archive.

The Italian Districts already have an organised system for autonomous filing in SIDAP of their

report forms.



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RF.1.1. REPORTING AND FEEDBACK FORMS

Form Title Activity1

Frequency2 References

1. IADC IADC - Daily DrillingReport

D-C-WO D

2. ARPO-01 Initial Activity Report D-C-WO-WL-WT

E STAP-P-1-M-6140

STAP-P-1-M-7120

STAP-P-1-M-7110

3. ARPO-02/A Daily Report (Drilling) D D STAP-P-1-M-6140

4. ARPO-02/B Daily Report WellTesting, Workover and

Completion

WT-C-WO D STAP-P-1-M-7120

STAP-P-1-M-7130

STAP-P-1-M-7110

5. ARPO-03/A Casing Running Report(General Data)

D-C-WO E STAP-P-1-M-6140

6. ARPO-03/B Casing Running Report(Job Data)


7. ARPO-04/A Cementing Job Report(General Data)


8. ARPO-04B Cementing Job Report(Job Data)


STAP-P-1-M-7120

9. ARPO-05 Bit Record D-WO EOP STAP-P-1-M-6140

10. ARPO-06 Waste DisposalManagement Report

D-WO EOW STAP-P-1-M-6140

STAP-P-1-M-7120

STAP-P-1-M-7130

11. ARPO-07 Perforating Report C-WT-WO E STAP-P-1-M-7120

12. ARPO-08 Gravel Pack Report C-WO E STAP-P-1-M-7120

13. ARPO-09 Matrix Stimulation/Hydraulic FracturingReport

C-WO-WT E STAP-P-1-M-7120

1

Activity: D = Drilling; C = Completion; WL = Wireline; WO = Workover; WT = Well testing2 Frequency: D = Daily; SM = Six month; EOP = End Of Phase; EOW = End Of Well; E = Event; SB = Shift Basis



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Form Title Activity3

Frequency4 References

14. ARPO-10/A Well Test Report(General data)

WT-WO E STAP-P-1-M-7130

15. ARPO-10/B Well Test Report (DSTData)


16. ARPO-10/C Well Test Report(Record Data)


17. ARPO-11 Wire Line Report WL D STAP-P-1-M-7110

18. ARPO-12 Pressure and

Temperature SurveyReport

WL E STAP-P-1-M-7110

19. ARPO-13 Well Problem Report D-C-WL-WO-WT

E STAP-P-1-M-6140

STAP-P-1-M-7120

STAP-P-1-M-7130

20. ARPO-20/A Well Situation Report(Well)

D-C-WO SM-EOW STAP-P-1-M-6140

21. ARPO-20/B Well Situation Report(Well Head)


22. ARPO-20/C Well Situation(Completion)


23. ARPO-20/D Well Situation(Completion Schedule)


24. ARPO-20/E Well Situation (TubingTally)


25. ARPO-FB/01 Contractor Service andEquipment Evaluation

D-C-WL-WO-WT

E STAP-P-1-M-6140

STAP-P-1-M-7120

STAP-P-1-M-7130

STAP-P-1-M-7110

26. ARPO-FB/02 Contractor PerformanceEvaluation

D-C-WL-WO-WT

SM STAP-P-1-M-6140

STAP-P-1-M-7120

STAP-P-1-M-7130

STAP-P-1-M-7110

3

Activity: D = Drilling; C = Completion; WL = Wireline; WO = Workover; WT = Well testing4 Frequency: D = Daily; SM = Six month; EOP = End Of Phase; EOW = End Of Well; E = Event; SB = Shift Basis



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RF.1.2. FINAL DRILLING REPORT

1. INTRODUCTION Reference

1.1. Whenever possible and applicable, the well final report shallinclude both Drilling and Completion activity. In this case it will betitled as ‘Well Final Drilling and Completion Report’ or, in case of workover, as ‘Workover Well Final Drilling and Completion Report’.

P-1-M-6100 17P-1-N-6002

2. PRINT MODEL Reference

2.1. The Well ‘Final Report’, will be made using the model built in‘Word 6’, called:

• ‘WFR-ITA.dot’; for Italian activities

• ‘WFR-ING.dot’ for foreign activities

P-1-N-6002 1

3. PAGE NUMBERING Reference

3.1. The page numbering must indicate the actual and the total number of pages of the document. This function is automaticallyaccomplished by the ‘Model’ in print pre-view or print.

P-1-N-6002 3

3.2. In the presence of annexes, the number of pages of the documentwill be that of the sole document without annexes, followed by ‘+ ANN’.

P-1-N-6002 3

4. IDENTIFICATION Reference

4.1. The WELL ‘FINAL REPORT’ specifying if per: Drilling or Completion or Drilling and Completion whichever applies is

identified by the name of the well, platform or cluster to which itis referred

P-1-N-6002 4

5. GRAPHIC REPRESENTATIONS Reference

5.1. In order to make the document easily manageable also in ‘e mail’or with shared network disks, the graphic representations shall bein electronic format using Agip’s standard software ‘Windows’ tools(Power Point, Excel, etc.).

P-1-N-6002 6

6. PREPARATION OF THE WELL ‘FINAL REPORT’ Reference

6.1. The Well Final Report is prepared by the ’Engineering Section’ of the ‘Drilling and Completion Department’ in co-operation with the‘Operations Section’.

P-1-M-6100 17P-1-N-6002 8



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7. GENERAL FINAL REPORT STRUCTURE Reference

7.1. General informationP-1-M-6100 17P-1-N-6002 8.2.1

7.1.1. General well data: this chapter includes for a single well the datareported below

P-1-M-6100 17P-1-N-6002 8.2.1

7.1.1.1. Name and acronym of the well P-1-N-6002 8.2.1

7.1.1.2. District/Affiliated company in charge P-1-N-6002 8.2.1

7.1.1.3. Agip code P-1-N-6002 8.2.1

7.1.1.4. Total Vertical Depth P-1-N-6002 8.2.1

7.1.1.5. Total Measured Depth P-1-N-6002 8.2.1

7.1.1.6. Ground level (onshore wells) P-1-N-6002 8.2.1

7.1.1.7. Water Depth (offshore wells) P-1-N-6002 8.2.1

7.1.1.8. Reference seismic line P-1-N-6002 8.2.1

7.1.1.9. Starting latitude (geographic) N/S P-1-N-6002 8.2.1

7.1.1.10. Starting longitude (geographic) E/W P-1-N-6002 8.2.1

7.1.1.11. Bottom latitude (geographic) N/S P-1-N-6002 8.2.1

7.1.1.12. Bottom longitude (geographic) E/W P-1-N-6002 8.2.1

7.1.1.13. Starting grid co-ordinates (metric) N/S P-1-N-6002 8.2.1

7.1.1.14. Starting grid co-ordinates (metric) E/W P-1-N-6002 8.2.1

7.1.1.15. Bottom grid co-ordinates(metric) N/S P-1-N-6002 8.2.1

7.1.1.16. Bottom grid co-ordinates(metric) E/WP-1-N-6002 8.2.1

7.1.1.17. Geodetic references P-1-N-6002 8.2.1

7.1.1.18. Max. hole inclination P-1-N-6002 8.2.1

7.1.1.19. Well type P-1-N-6002 8.2.1

7.1.1.20. Spud-in classification P-1-N-6002 8.2.1



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7.1.1.21. Final classification P-1-N-6002 8.2.1

7.1.1.22. Well status P-1-N-6002 8.2.1

7.1.1.23. Spud-in date P-1-N-6002 8.2.1

7.1.1.24. Drilling end date P-1-N-6002 8.2.1

7.1.1.25. Testing end date P-1-N-6002 8.2.1

7.1.1.26. Rig release date P-1-N-6002 8.2.1

7.1.1.27. Permission/concession P-1-N-6002 8.2.1

7.1.1.28. Operator P-1-N-6002 8.2.1

7.1.1.29. Partners & Shares P-1-N-6002 8.2.1

7.1.1.30. Municipality (onshore wells) P-1-N-6002 8.2.1

7.1.1.31. Province (onshore wells) P-1-N-6002 8.2.1

7.1.1.32. Port Authority P-1-N-6002 8.2.1

7.1.1.33. Zone (offshore wells) P-1-N-6002 8.2.1

7.1.1.34. Distance from the coast (offshore wells) P-1-N-6002 8.2.1

7.1.1.35. Distance from the operative base P-1-N-6002 8.2.1

7.1.2. General rig specification: the rig unit basic data to be reported arelisted hereafter.

P-1-M-6100 17P-1-N-6002 8.2.2

7.1.2.1. Contractor name P-1-N-6002 8.2.2

7.1.2.2. Rig name P-1-N-6002 8.2.2

7.1.2.3. Rig code P-1-N-6002 8.2.2

7.1.2.4. Rig type P-1-N-6002 8.2.2

7.1.2.5. Ground level rotary table elevation (onshore rigs) P-1-N-6002 8.2.2

7.1.2.6. Sea level rotary Table elevation (offshore rigs) P-1-N-6002 8.2.2

7.1.2.7. Cellar bottom (onshore rigs) P-1-N-6002 8.2.2

7.1.2.8. Top of the first flange (onshore rigs) P-1-N-6002 8.2.2



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7.1.2.9. Top housing (subsea well head or MLS system) P-1-N-6002 8.2.2

7.1.2.10. Power installed P-1-N-6002 8.2.2

7.1.2.11. Type of drawworks P-1-N-6002 8.2.2

7.1.2.12. Rig potential with 5” DP’s P-1-N-6002 8.2.2

7.1.2.13. Max. & min. operating water depth (offshore rigs) P-1-N-6002 8.2.2

7.1.2.14. Clearance under rotary beam (onshore rigs) P-1-N-6002 8.2.2

7.1.2.15. Type of top drive system P-1-N-6002 8.2.2

7.1.2.16. Diameter of the rotary table P-1-N-6002 8.2.2

7.1.2.17. Number and type of mud pumps P-1-N-6002 8.2.2

7.1.2.18. Total mud storage P-1-N-6002 8.2.2

7.1.2.19. Drinking water storing capacity (offshore rigs) P-1-N-6002 8.2.2

7.1.2.20. Industrial water storing capacity P-1-N-6002 8.2.2

7.1.2.21. Gas oil storing capacity P-1-N-6002 8.2.2

7.1.2.22. Barite storing capacity P-1-N-6002 8.2.2

7.1.2.23. Bentonite storing capacity P-1-N-6002 8.2.2

7.1.2.24. Cement storing capacity P-1-N-6002 8.2.2

7.1.3. Bop sketch P-1-M-6100 17

7.1.3.1. BOP sketch drawings, showing main components and for off-shorewells, significant distance from RKB. and sea bottom must bereported here

P-1-N-6002 8.2.3

7.1.4. List of main contractors P-1-M-6100 17P-1-N-6002 8.2.4

7.1.5. Operations organisation chart P-1-M-6100 17P-1-N-6002 8.2.5

7.1.6. Location map P-1-M-6100 17P-1-N-6002 8.2.6



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7.1.7. Cluster/platform well bay lay-out and orientation: P-1-M-6100 17

7.1.7.1. In this chapter the cluster/platform well bay lay-out is reportedindicating the following main data:

P-1-N-6002 8.2.7

7.1.7.1.1 Orientation angle (from North) of the cluster/platform well bay P-1-N-6002 8.2.7

7.1.7.1.2 The distance among wells heads. P-1-N-6002 8.2.7

7.1.7.1.3 The foot print position of the eventual jack-up that has drilled thewells

P-1-N-6002 8.2.7

7.1.7.1.4 The top view plan of the wells pat in a radius of 200m from centrecluster/platform indicating the relative vertical depths

P-1-N-6002 8.2.7

7.1.7.1.5For existing wells the cluster/platform lay-out indicating the livingmodule position.

P-1-N-6002 8.2.7

7.2. Well history P-1-M-6100 17

7.2.1. Final well status P-1-M-6100 17

7.2.1.1. Well Sketch P-1-M-6100 17P-1-N-6002 8.3.1.1

7.2.1.2. Well Head Sketch P-1-M-6100 17P-1-N-6002 8.3.1.2

7.2.1.3. Well Completion Sketch P-1-M-6100 17P-1-N-6002 8.3.1.3

7.2.1.4. In case of cluster or platform, a general time Vs depth diagram willbe reported.

P-1-N-6002 8.3.1.4

7.2.2. Detailed operations history P-1-M-6100 17P-1-N-6002 8.3.2

7.2.2.1. In case of new well: P-1-N-6002 8.3.2

7.2.2.1.1 Moving P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.2 Conductor Pipe Phase P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.3 Surface Phase P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.4 Intermediate Phases P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.5 Final Phase P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.6 Well Testing P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.7 Completion P-1-M-6100 17P-1-N-6002 8.3.2.1



PAGE 11 OF 12ARPO

ENI S.p.A.

Agip Division

IDENTIFICATION CODE

REVISION

STAP-P-1-M-6090

7.2.2.1.8 Abandoning P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.9 Drilling problems and recommendations P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.1.10 Completion remarks P-1-M-6100 17P-1-N-6002 8.3.2.1

7.2.2.2. In case of workover: P-1-N-6002 8.3.2.2

7.2.2.2.1 Moving and anchoring (when applicable) P-1-N-6002 8.3.2.2

7.2.2.2.2 Reason for the workover P-1-N-6002 8.3.2.2

7.2.2.2.3 Well decompletion (when applicable) P-1-N-6002 8.3.2.2

7.2.2.2.4 Well preparation P-1-N-6002 8.3.2.2

7.2.2.2.5 Intermediate phases P-1-N-6002 8.3.2.2

7.2.2.2.6 Final phases P-1-N-6002 8.3.2.2

7.2.2.2.7 Testing P-1-N-6002 8.3.2.2

7.2.2.2.8 Completion P-1-N-6002 8.3.2.2

7.2.2.2.9 Abandoning P-1-N-6002 8.3.2.2

7.2.2.2.10 Well decompletion remarks P-1-N-6002 8.3.2.2

7.2.2.2.11 Well preparation remarks P-1-N-6002 8.3.2.2

7.2.2.2.12 Drilling problems and recommendations P-1-N-6002 8.3.2.2

7.2.2.2.13 Completion remarks P-1-N-6002 8.3.2.2

7.3. Data analysis P-1-M-6100 17