Drilling and workover best practices
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ARPO
ENI S.p.A. Agip Division
ORGANISING DEPARTMENT
STAP
TYPE OF ACTIVITY'
ISSUING DEPT.
P
DOC. TYPE
1
REFER TO SECTION N.
M
PAGE.
1
OF
7
6090
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) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue:
28/04/2000
! " # $ % Issued by
REVISIONS
P. Magarini 28-04-2000
C. Lanzetta 28-04-2000
A. Galletta 28-04-2000
PREP'D
CHK'D
APPR'D
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.
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6090
INTRODUCTION PURPOSE OF THE DOCUMENT The purpose of the Best Practices and Minimum Requirements is to guide technicians and engineers, involved in Eni-Agip’s Drilling & Completion worldwide activities, through the Manuals & Procedures and the Technical Specifications which are part of the Corporate Standards. Such Corporate Standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws 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 the main reference document for the Audits on the Drilling & Completion activities that the Corporate 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 have been divided in three main sections: 1)
PLANNING (PL) It includes the fundamental actions preceding the well operations, such as feasibility study, 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 Division Headquarters. 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 information necessary for studies, analysis and evaluations of the operations. This will enable improvement and optimisation of further activities.
For every BP&MR specified, the source (manual, procedure, technical specification) has been listed, to help finding the entire and associated subjects, if required. Where the reference column is blank, this means that there are no reference documents available or they are currently under preparation.
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REVISION STAP-P-1-M-6090
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-Agip Division 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 and related 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/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the BP&MR, when the updating of the document will be advisable.
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ENI S.p.A. Agip Division
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REVISION 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 AHTS API BG BHA BHP BHT BJ BMT BOP BPD BPM BPV BSW BUR BWOC BWOW C/L CBL CCD CCL CDP CET CGR CMT CP CR CRA CSG CT CW DC DE DHM DHSV DIF DLS DLS DM / D&CM DOB DOBC DOR DP
Alternate Current, Direct Current Anchor Handling Towing Supply American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom hole temperature Blast Joint Blue Methylene Test Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment & Water Build Up Rate By Weight Of Cement By Weight Of Water Control Line Cement Bond Log Centre to Centre Distance Casing Collar Locator Common Depth Point Cement Evaluation Tool Condensate Gas Ratio Cement Conductor Pipe Cement Retainer Corrosion Resistant Alloy Casing Coiled Tubing Current Well Drill Collar Diatomaceous Earth Down Hole Motor Down Hole Safety Valve Drill in Fluid Dog Leg Severity Dog Leg Severity Drilling & Completion Manager
NB NDT NMDC NSG NTU OBM OD OEDP OH OHGP OIM OMW ORP OWC P&A P/U PBR PCG PDC PDM PGB PI PKR PLT POB POOH PPB PPG ppm PTR PV PVT Q Q/A Q/C R/D R/U RBP RCP RFT
Near Bit Stabiliser Non Destructive Test Non Magnetic Drill Collar North Seeking Gyro Nephelometric Turbidinity Unit Oil Base Mud Outside Diameter Open End Drill Pipe Open Hole Open Hole Gravel Packing Offshore Installation Manager Original Mud weight Origin Reference Point Oil Water Contact Plugged & Abandoned Pick-Up Polished Bore Receptacle Pipe Connection Gas Polycristalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Packer Production Logging Tool Personnel On Board Pull Out Of Hole Pounds per Barrel Pounds per Gallon Part Per Million Piano Tavola Rotary Plastic Viscosity Pressure Volume Temperature Pump Rate Quality Assurance, Quality Control Rig Down Rig Up Retrievable Bridge Plug Reverse Circulating Position (GP) Repeat Formation Test
Diesel Oil Bentonite Diesel Oil Bentonite Cement Drop Off Rate Drill Pipe
RIH RJ RKB ROE
Run In Hole Ring Joint Rotary Kelly Bushing Radius of Exposure
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DPHOT DRLG DST DV E/L ECD ECP EMS EMW EOC EP ESD ESP ETA ETU FBHP
Drill Pipe Hang off Tool Drilling Drill Stem Test DV Collar Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight End Of Curvature External Pressure Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Endless Tubing Unit Flowing Bottom Hole Pressure
ROP ROU ROV RPM RPSP RT S (HDT) S/N S/O S/S S/V SAFE SBA SBHP SBHT SCBA
FBHT FC FINS
Flowing Bottom Hole Temperature Flow Coupling Ferranti International Navigation System Free Point Indicator / Back Off
SCC SCSO SCSSV
Flowing Tubing Head Pressure Flowing Tubing Head Temperature Guidance Continuous Tool Gas Liquid Ratio Guidelineless Landing Structure Gyro Multi Shot Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Guidelineless Re-entry Assembly Gyro Single Shot Hazard and Operability High Resolution Dipmeter Hydraulic Horsepower Hole Opener High Pressure - High Temperature Horsepower per Square Inches Hewi Wate Drill Pipe
SD SDE SF SG SICP SIDPP SIMOP SN SPM SPV SR SRG SSC SSD SSLV SSR SSSV SSTT SSTV ST STD
Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle Revolutions Per Minute Reduced Pump Strokes Pressure Rotary Table High Resolution Dipmeter Serial Number Slack-off Short String Supply Vassal Slapper Activated Firing Equipment Safe Breathing Area Static Bottom Hole Pressure Static Bottom Hole Temperature Self Contained Breathing Apparatus Stress Corrosion Cracking Single Completion Seal Flange Surface Controlled Subsurface Safety Valve Self Contained Underwater Breathing Apparatus Separation Distance Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Simultaneous Operations Seating Nipple Stroke per Minute Supervisor Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Sliding Sleeve Door Valve Sub Surface Lubricator Valve Sub surface Release Plugs Sub Surface Safety Valve Sub Surface Test Tree Subsea Television Steering Tool Stand
International Drilling Contractor Inside Blow Out Preventer
STG STHP
Short trip gas Static Tubing Head Pressure
FPI/BO FTHP FTHT GCT GLR GLS GMS GOC GOR GP GPM GPS GR GRA GSS HAZOP HDT HHP HO HP/HT HSI HW/HW DP IADC IBOP
SCUBA
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ICGP ID IFR IP IPR JAM KMW KOP L/D L/S LAT LC 50 LCDT LCM LCP LEL LMRP LN LOT LQC LTA LTT LWD M/D M/U MAASP MD MLH MLS MMS MODU MOP MPI MSCL MSL MSS MUT MW MWD N/D N/U NACE
Inside Casing Gravel Packing Inside Diameter Imposta Fabbricazione Ridotta Internal Pressure Inflow Performance Relationship Joint Make-up Torque Analyser Kill mud weight Kick Off Point Lay-Down Long String Lowest Astronomical Tide Lethal Concentration 50% Last Crystal to Dissolve °C Lost Circulation Materials Lower Circulation Position (GP) Lower Explosive Limit Low Marine Riser Package Landing Nipple Leak Off Test Log Quality Control Lost Time Accident Lower Tell Table (GP) Log While Drilling Martin Decker Make-Up Max Allowable Annular Surface Pressure Measured Depth Mudline Hanger Mudline Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Margin of Overpull Magnetic Particle Inspection Modular Single Completion Land Mean Sea Level Magnetic Single Shot Make Up Torque Mud Weight Measurement While Drilling Nipple-Down Nipple-Up National Association of Corrosion Engineers
STHT STT SX TBG TCP TD TDB TDS TFA TG TGB THA TOC TOL TRSV TTBP TVD TW UAR UCP UEL UGF UHF UR UTM VBR
Static Tubing Head Temperature Surface Test Tree Sacks Tubing Tubing Conveyed Perforations Total Depth Total Drilling Control Top Drive System Total Flow Area Trip Gas Temporary Guide Base Tubing Head Adapter (bonnet) Top of Cement Top of Liner Tubing Retrievable Safety Valve Through Tubing Bridge Plug True Vertical Depth Target Well Uncertainty Area Ratio Upper Circulating Position Upper Explosion Level Universal Guide Frame Ultra High Frequency Under Reamer Universal Transverse of Mercator Variable Bore Rams (BOP)
VDL VHF VSP W/L WBM WC WHP WHSIP WL WO WOB WOC WOW WP XO YP
Variable Density Log Very High Frequency Velocity Seismic Profile Wire Line Water Base Mud Water Cut Well Head Pressure Well Head Shut-in Pressure Water Loss Workover Weight On Bit Wait On Cement Wait On Weather Working Pressure Cross Over Yield Point
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REVISION
STAP-P-1-M-6090
SECTION 1
PLANNING (PL)
SECTION 1 OF BP&MR - PLANNING (PL)
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REVISION
STAP-P-1-M-6090
INDEX PL1.
PRELIMINARY
7
PL. 1.1. FEASIBILITY STUDY 1. 2.
NEW WELL WELL RE-ENTRY
PL. 1.2. DRILLING & COMPLETION DEPARTMENT ACTIVITIES 1.
DEPARTMENT RESPONSIBILITIES
PL. 1.3. RIG SELECTION 1.
TECHNICAL SPECIFICATIONS CONTENTS
PL. 1.4. AUTHORISATIONS AND PERMITS 1.
GENERAL
PL. 1.5. TECHNICAL DOCUMENTATION 1. 2.
RIG SITE DRILLING & COMPLETION DEPARTMENT
PL. 1.6. MAIN CONTRACTORS 1. 2. 3. 4.
DRILLING CONTRACTOR MUD LOGGING MUD SERVICE, CHEMICAL SUPPLY, CENTRIFUGES RENTAL CEMENTING SERVICE
PL. 1.7. ESTIMATED COSTS 1. 2.
PL2.
BUDGET COSTS
7 7 7
8 8
10 10
12 12
13 13 13
14 14 18 20 22
25 25 25
GEOLOGICAL AND DRILLING WELL PROGRAMME
26
PL. 2.1. GEOLOGICAL AND DRILLING WELL PROGRAMME STRUCTURE
27
1. 2.
NUMBER OF THE SECTIONS PRINT MODEL
PL. 2.2. GENERAL INFORMATION (SECTION 1) 1. 2. 3. 4. 5. 6. 7. 8. 9.
GENERAL GENERAL WELL DATA GENERAL RECOMMENDATIONS GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND SAFETY EQUIPMENT LIST OF THE MAIN CONTRACTORS CONTACTS IN CASE OF EMERGENCY REFERENCE MANUALS MEASUREMENT UNITS SIGNATURE
PL. 2.3. LAYOUT OF THE DRILLING PROGRAMME (SECTION 4) 1.
BASIC REQUIREMENTS
PL. 2.4. OPERATIVE SEQUENCE (SECTION 4) 1. 2. 3. 4. 5.
PRELIMINARY INFORMATIONS CONDUCTOR PIPE PHASE SURFACE PHASE INTERMEDIATE PHASES FINAL PHASE
SECTION 1 OF BP&MR - PLANNING (PL)
27 27
28 28 28 29 29 29 30 30 30 30
33 33
35 35 35 36 36 37
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REVISION
STAP-P-1-M-6090 6. 7. 8.
TESTING TYPE OF COMPLETION WELL ABANDONMENT
PL. 2.5. SOFTWARE (SECTION 4) 1. 2.
STANDARDS ALTERNATIVES
PL. 2.6. PRESSURE GRADIENTS PROGNOSIS (SECTION 4) 1. 2. 3.
PRELIMINARY DATA COLLECTION DEFINITIONS PRESSURE GRADIENTS PREDICTION & EVALUATION
PL. 2.7. SHALLOW GAS 1. 2. 3.
PRELIMINARY SHALLOW GAS INVESTIGATION SHALLOW-GAS DRILLING GUIDELINES DIVERTER
PL. 2.8. CASING SETTING DEPTH 1. 2. 3.
DETERMINE PROPER SETTING DEPTH FOR EACH CASING TYPE GENERAL GUIDELINES ON CASING SETTING DEPTHS SAFETY REQUIREMENTS
PL. 2.9. DIRECTIONAL WELL PLANNING 1. 2. 3. 4. 5. 6. 7. 8.
PRELIMINARY DIRECTIONAL PLAN INFORMATION DEFINITIONS SURVEY CALCULATIONS SURVEY TOOL SELECTION FREQUENCY AND TYPE OF SURVEYS ANTI-COLLISION BHA ANALYSIS REPORTING
PL. 2.10. CASING DESIGN 1. 2. 3. 4. 5.
CASING SETTING DEPTH AND FUNCTIONS OF CASING STRINGS CASING AND HOLE SIZES CASING DESIGN CRITERIA AND DESIGN FACTORS DECREASING IN THE CASING PERFORMANCE PROPERTIES DRILLING PROGRAMME CONTENTS
PL. 2.11. DRILLING FLUIDS PROGRAMME 1. 2. 3. 4. 5. 6.
GENERAL PRELIMINARY INFORMATION GENERAL PARAMETERS FOR A MUD SYSTEM SURFACE EQUIPMENT FOR TREATING & HANDLING MUD CONTINGENCY PLANS FOR POTENTIAL HOLE PROBLEMS SAFETY REQUIREMENTS
PL. 2.12. HYDRAULIC PROGRAMME 1. 2. 3. 4. 5.
SOFT WARE FLOW REGIME DEFINITION FRICTION PRESSURE LOSSES CALCULATION BIT NOZZLES SELECTION DRILLING PROGRAMME CONTENTS
PL. 2.13. WELLHEAD 1. 2. 3. 4.
37 37 38
39 39 39
40 40 41 43
48 48 48 50
51 51 51 52
53 53 54 55 56 59 59 63 64
70 70 70 70 72 76
80 80 80 80 81 82 82
83 83 83 83 84 84
86
GENERAL SERVICE CONDITION (NO SOUR SERVICE) ONSHORE, OFFSHORE JACK-UP & FIXED PLATFORMS WELLHEAD SYSTEM MATERIAL UNITISED WELLHEAD (COMPACT) FLANGED WELLHEAD
SECTION 1 OF BP&MR - PLANNING (PL)
86 86 87 87
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REVISION
STAP-P-1-M-6090 5. 6. 7. 8. 9.
MATERIAL REQUIREMENTS PRESSURE TESTS DRILLING PROGRAMME CONTENTS UNCONVENTIONAL WELLHEAD SYSTEM SUBSEA WELLHEAD SYSTEM
PL. 2.14. WELL CONTROL 1. 2. 3. 4. 5. 6. 7. 8.
BOP SELECTION CRITERIA EQUIPMENT REQUIREMENTS BOP & CASING TESTS TESTS FREQUENCY DURATION OF TESTS WELL CONTROL DRILLS PRIMARY WELL CONTROL SECONDARY WELL CONTROL
PL. 2.15. CEMENT PROGRAMME 1. 2. 3. 4. 5. 6. 7. 8.
PRELIMINARY INFORMATION SLURRY DESIGN SPACER DESIGN HYDRAULIC CALCULATIONS PLACEMENT TECHNIQUES DOWN HOLE EQUIPMENT SELECTION SURFACE EQUIPMENT SELECTION OPERATING PROGRAMME
PL. 2.16. DRILL STRING DESIGN 1.
DESIGN PARAMETERS
PL. 2.17. BIT SELECTION & DRILLING PARAMETERS 1.
FACTORS AFFECTING BIT SELECTION
PL. 2.18. EXPECTED DRILLING PROBLEMS & RECOMMENDATIONS 1. 2. 3. 4. 5. 6. 7. 8. 9.
DRILLING DIFFICULTIES SUGGESTIONS GENERALITIES LOSSES CIRCULATION DIFFERENTIAL STICKING CAVING HOLE HOLE RESTRICTION HOLE IRREGULARITIES HYDROGEN SULPHIDE GUIDELINES
PL. 2.19. WELL ABANDONING 1. 2. 3.
PL3.
GENERAL GUIDELINES TEMPORARY ABANDONMENT PERMANENT ABANDONMENT - PLUGGING
88 89 89 89 89
91 91 91 92 95 96 96 97 98
99 99 99 100 101 101 101 102 102
104 104
108 108
110 110 110 110 110 111 112 113 113 114
118 118 118 120
COMPLETION DESIGN
124
PL. 3.1. FUNDAMENTAL
124
1. 2. 3. 4. 5.
CONCEPTUAL DESIGN COMPLETION OBJECTIVES FUNCTIONS OF A COMPLETION RESEVOIR CONSIDERATIONS RESERVOIR/PRODUCTION FORECAST
PL. 3.2. RESERVOIR FLUIDS CHARACTERISTICS 1. 2.
GENERAL OIL CHARACTERISTICS
SECTION 1 OF BP&MR - PLANNING (PL)
124 124 125 125 126
130 130 130
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REVISION
STAP-P-1-M-6090 3. 4. 5.
GAS CHARACTERISTICS GAS CONDENSATE CHARACTERISTICS SAMPLING
PL. 3.3. RESERVOIR ROCK CHARACTERISTICS 1. 2. 3. 4.
GENERAL AREA OF INTEREST MAIN CHARACTERISTICS CORE ANALYSIS
PL. 3.4. EFFECTS OF RESERVOIR CHARACTERISTICS 1. 2. 3. 4. 5. 6.
GENERAL DESIGN PARAMETERS COMPLETION DESIGN THROUGH FIELD LIFE NEAR WELLBORE RESTRICTIONS STRATEGY TO MINIMISE THE SKIN EFFECTS WELL INFLOW PERFORMANCE
PL. 3.5. TUBING PERFORMANCE 1. 2. 3. 4. 5. 6. 7.
GENERAL TEMPERATURE GRADIENT PVT DATA CALCULATION PVT PARAMETERS TO BE MATCHED VALIDATION LIMITS OPTIMUM TBG SIZE THROUGH FIELD LIFE
PL. 3.6. STRESS ANALYSIS 1. 2. 3. 4. 5. 6. 7.
GENERAL PARAMETERS CALCULATION METHOD SAFETY FACTOR OPERATIONAL CASES TBG - PACKER INTERACTIONS TUBING MECHANICAL PROPERTIES
PL. 3.7. MATERIAL SELECTION 1. 2. 3. 4. 5. 6.
CORROSION GENERAL CORROSION CONTROL MEASURES MATERIAL SELECTION CORROSION MONITORING ELASTOMER SELECTION ELASTOMER PRACTICAL GUIDELINES
PL. 3.8. LIFTING DESIGN 1. 2. 3. 4. 5. 6. 7.
DEFINITION BASIC METHODS OF ARTIFICIAL LIFT SELECTIONCRITERIA ROD PUMPING GAS LIFTING ELECTRICAL SUBMERSIBLE PUMPING JET PUMPING
PL. 3.9. COMPLETION AND PACKER FLUIDS 1. 2. 3. 4. 5. 6. 7.
DEFINITIONS COMPLETION FLUID DUTY PACKER FLUID BRINE PROPERTIES FORMATION INTERACTIONS BRINE FILTRATION FLUID LOSSES
SECTION 1 OF BP&MR - PLANNING (PL)
130 131 132
133 133 133 133 134
135 135 135 135 135 137 138
141 141 142 142 143 144 145 145
146 146 146 148 149 149 150 151
152 152 156 157 160 161 161
163 163 163 163 166 167 168 169
170 170 171 171 171 172 173 174
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REVISION
STAP-P-1-M-6090 8.
OIL BASE MUD
PL. 3.10. PACKERS 1. 2. 3. 4. 5.
175
DEFINITIONS SINGLE COMPLETION PACKER SINGLE SELECTIVE COMPLETION PACKER DUAL COMPLETION PACKER DUAL SELECTIVE COMPLETION PACKER
PL. 3.11. TUBING JOINT 1. 2.
GENERAL JOINT SELECTION
PL. 3.12. TUBING SAFETY VALVE 1. 2. 3. 4.
GENERAL NOTES SEALING SYSTEM APPLICATION SELECTION CRITERIA
PL. 3.13. ANNULUS SAFETY VALVE 1. 2. 3. 4.
GENERAL NOTES VALVE TYPES APPLICATION SELECTION CRITERIA
PL. 3.14. LANDING NIPPLES AND SLIDING VALVE 1. 2. 3. 4. 5. 6.
TUBING HANGER NIPPLE INTERMEDIATE DOWN HOLE EQUIPMENT TAIL PIPE NIPPLES SELECTION GENERAL WORKING PRESSURE
PL. 3.15. CHRISTMAS TREE 1. 2. 3. 4. 5. 6. 7. 8.
GENERAL GUIDELINES PRESSURE RATING CONFIGURATION ACTUATORS MATERIALS SEALS TUBING HANGER TUBING HEAD ADAPTER SEAL FLANGE
PL. 3.16. WORKOVER AND COMPLETION PROGRAMME 1. 2.
174
GENERAL PROGRAMME CONTENT
SECTION 1 OF BP&MR - PLANNING (PL)
175 175 180 183 184
185 185 185
187 187 189 191 191
192 192 192 192 192
194 194 194 194 194 194 195
196 196 196 196 197 198 198 200 200
201 201 201
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REVISION
STAP-P-1-M-6090
PL1. PRELIMINARY PL. 1.1.
FEASIBILITY STUDY
1. NEW WELL The Drilling & Completion Department (D&C Dept.) obtain input data 1.1. from the Exploration or Reservoir departments, relevant to: • • • • 1.2.
Location co-ordinates. Targets specifications. Reference to offset well information. Potential production.
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 be encountered. Define the type of drilling fluid. Fix preliminary casing points and if necessary, also produce the casing design. Establish a preliminary directional well plan in order to evaluate collision risks. Plan the configuration of the well completion. Carry out an operations optimisation analysis (pre-drilling, early production, simultaneous production, etc.). Estimate expected time of operations. Estimate expected costs.
2. WELL RE-ENTRY Other additional information will be obtained, such as: 2.1. • • • 2.2.
Reference
Purpose of re-entry (reinstate production, workover, abandoning, etc.). Well history and status. Wellhead sketch.
In addition to the normal evaluations, some additional issues must be taken 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.
SECTION 1 OF BP&MR - PLANNING (PL)
Reference
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REVISION
STAP-P-1-M-6090 PL. 1.2.
DRILLING & COMPLETION DEPARTMENT ACTIVITIES
1. DEPARTMENT RESPONSIBILITIES The D&C Dept. is activated by the Exploration Department 1.1. (exploratory wells) or Project Manager (development wells). 1.2.
The D&C Dept. obtain the following from the District Geological Department:
1.2.1.
The ‘Geological Programme’ to include: • • • • • • •
1.2.2.
P-1-M-6100 P-1-N-6001-E
16.4.2 7.2
P-1-M-6100 P-12-N-6001-E
16.4.3 7.3
Geological Framework Seismic Interpretation Source Rocks Sealing Rocks Lithostratigraphic Profile Reference Wells Annexes and/or Figures
The ‘Operational Geological Programme’ to include: • • • • • • • • • • • • • •
Reference
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
SECTION 1 OF BP&MR - PLANNING (PL)
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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 P-1-M-6100 P-1-N-6001-E distribute the Drilling Programme.
16 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
SECTION 1 OF BP&MR - PLANNING (PL)
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REVISION
STAP-P-1-M-6090 PL. 1.3.
RIG SELECTION
1. TECHNICAL SPECIFICATIONS CONTENTS 1.1. General data: • • • • • • • • • • 1.2.
Exploration wells Development wells Single wells Cluster wells Number of wells per cluster Vertical wells Deviated wells.
Well characteristics for rig evaluation: • • • • • •
1.4.
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.
Type of well: • • • • • • •
1.3.
Reference
Rig capacity with 5” DP: Hole diameter Hole depth Casing/liner diameter Casing/liner setting depth Casing/liner weight in air.
Type of mud predicted: • • •
If oil based mud predicted, adequate mixing system. Max predicted mud density. H2S predicted.
SECTION 1 OF BP&MR - PLANNING (PL)
P-1-M-6140 P-1-M-6100
6.4 5.8
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REVISION
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1.5.
Wellhead for each type of well: • • • • •
P-1-M-6140
15
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.
Reference List: ‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘Geological and Drilling Well Programme’
STAP-P-2-N-6001-E
SECTION 1 OF BP&MR - PLANNING (PL)
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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REVISION
STAP-P-1-M-6090 PL. 1.4.
AUTHORISATIONS AND PERMITS
1. GENERAL Authorisations, approvals and documentation necessary to operate in 1.1. the various Countries are usually substantially different and depend upon local laws and rules. Each District / Affiliate have to issue a complete list, specifying the type of documents and the competent authority. 1.2.
Rig site: All the authorisations and permits relative to the current activity shall be available for inspection by any authorised personnel.
1.3.
Well Area Department: All the authorisations and permits relative to the current activity shall be available for inspection by any authorised personnel.
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STAP-P-1-M-6090 PL. 1.5.
TECHNICAL DOCUMENTATION
1. RIG SITE Below is a list of the technical manuals and documentation that shall 1.1. be available on the rig site during any well operations: 1.1.1.
1.1.2.
1. • • • • • • • • • • • •
Drilling And Completion Activities: 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-M6100 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.
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 The D&C Dept. of the District/Affiliate must have available and 2.1. updated 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-Agip Headquarters.
2.3.
All technical reports regarding the current activity received from the rig shall be filed in and then will constitute the ‘Official Well File’ in which 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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STAP-P-1-M-6090 PL. 1.6.
MAIN CONTRACTORS Reference
1. DRILLING CONTRACTOR 1.1. Rig inspections: 1.1.1.
The rig must be inspected by the Company before the operating daily rate commences.
1.1.2.
Any unconformity must be reported and rectified as soon as possible. Any unconformity should be periodically reported to the Company base 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.
Registers
1.3.1.
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 personnel involved 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
Appendix ‘E’ Drilling Contract ‘Drilling and Workover safety requirements to be complied with by the Contractor’
Must be documented and readily accessible at the rig site. The Emergency Procedures must be readily accessible and made aware to all supervisory personnel on the rig location. 1.6.
Personnel Requirements
1.6.1.
All Contractor Personnel at the work site must be fully trained and Appendix ‘E’ Drilling currently qualified for their job function in accordance with the Contract ‘Drilling and Workover safety following minimum standards: requirements to be complied with by the
•
Well control and Blow-out Prevention Contractor’ The rig manager, toolpusher, driller, assistant driller, and subsea engineer (offshore rig), must posses a current certificate in well control and blow out prevention (biannual) issued by an industry training institute recognised by the Company.
•
Fire fighting All supervisory personnel should receive training in Basic Fire Fighting. In addition, those personnel assigned as members of a fire team on offshore rigs should receive formal fire team training.
•
Survival at sea All personnel working on an offshore rig must receive survival at sea training given by an industry training institution recognised by the Company.
•
First aid All supervisory personnel must possess a valid First Aid Certificate.
•
Hydrogen sulphide When drilling operations are to take place in an area where H2S is present or potentially a hazard, all rig personnel must undergo training in the use of breathing apparatus and escape sets.
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1.6.2.
Regularly scheduled safety meetings are required and every person Appendix ‘E’ Drilling Contract ‘Drilling and has to attend a safety meeting at least once per hitch (work cycle). Each meeting must be documented, and the minutes must include a list of the attendees, topics covered, and any safety concerns raised and the follow-up action to be taken. The minutes of each meeting have to be passed to the Company Representative.
Workover safety requirements to be complied with by Contractor”
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 Appendix ‘A’ - section ‘B’ ‘Personnel to be provided their job in accordance with the following minimum standards: by Contractor’
•
Derrickman One year as floorman and shall have attended courses on drilling activities and drilling mud.
•
Assistant Driller Two years as derrickman and shall have attended courses on drilling activities and have an adequate basic knowledge of all rig components. He shall attend theoretical and practical Blowout prevention courses every two years and obtain a Well Control Certificate.
•
Driller Two years as assistant driller and shall have attended courses on drilling activities and have an adequate basic knowledge of all rig components. He shall attend theoretical and practical Blowout prevention courses every two years and obtain a Well Control Certificate.
•
Tourpusher Four years as a driller and shall have undertaken courses and examinations for a toolpusher at a recognised educational Institute. He shall attend theoretical and practical Blow-out prevention courses every two years and obtain a Well Control Certificate.
•
Toolpusher One year as tourpusher or four years as driller; as per tourpusher requirements and also have some years of education in scientific or technical subjects. He shall attend theoretical and practical Blowout prevention courses every two years and obtain a Well Control Certificate.
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•
Rig Manager Five years as a toolpusher or, if coming from years of education in a scientific or technical field, a minimum of one years training after a toolpusher course. He shall attend theoretical and practical Blowout prevention course every two years and obtain the Well Control Certificate.
•
Captain or Barge Master One year as barge engineer; he shall have attended courses in ballast 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 experience in, the operation and maintenance of BOP, BOP control and subsea equipment. He shall have attended appropriate specialised courses on under water equipment. He shall attend theoretical and practical Blowout prevention course every two years 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 Contractors rig personnel shall be sent to the Company Base.
1.8.
Accident reporting
1.8.1.
An accident reporting procedure, consistent with local rules, must be Appendix ‘E’ Drilling instituted. The Contractor must report all incidents occurring to Contract ‘Drilling and Workover safety Contractor’s or ancillary contractor’s personnel, to the Company on requirements’ the day that the incident occurs. The Contractor must provide the Company with a written report of the investigation into each such incident within seven days of the occurrence.
1.8.2.
On the first work day of each month, the Contractor must provide the Appendix ‘E Drilling Contract‘ Drilling and 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.
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Workover safety requirements’
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1.9.
Permit To Work system
1.9.1.
A ‘Permit to work procedure’ for operations such as hot work, Appendix ‘E’ Drilling concurrent operations, confined space entry and handling of Contract. radioactive materials must be in place.
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 the rig site including the subcontractor’s and third party personnel.
2. MUD LOGGING 2.1. Surface logging service
Reference
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 already A-1-SS-1722 existing on the rig.
3-d
2.1.3.
Each measurement system shall be equipped with automatically A-1-SS-1722 operating visual and acoustic alarm.
3-e
2.1.4.
Standard parameters shall be displayed and recorded in a double A-1-SS-1722 data base (function depth and time) with a clear indication of scale and recorded data.
3-i
2.1.5.
All geological and engineering data shall be loaded on software A-1-SS-1722 furnished by the Company. The aim of this activity is the collection, QC and entry of well data into the Corporate DB
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 A-1-SS-1722 well conditions, especially for pit level, pressure and mud return from the well.
3-p
2.2.
Operative service
2.2.1.
The operating service, carry out on 24 hours basis, shall be request A-1-SS-1722 when the Company needs geological surveillance and drilling service with a control of all parameters and recorded data.
3.1
2.2.2.
A team of 4 (four) surface logger; 2 (two) of them can be junior; it is A-1-SS-1722 intended that a surface logger junior can be employed only if on the rig there is in service a surface logger senior
3.1
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2.3.
Reduced service
2.3.1.
The company could require a ‘Restricted Service’ that shall have, at A-1-SS-1722 least, the following configuration: • • • • • • • • •
3.2
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-g
2.3.2.
Stored data shall be available in ASCII format if requested
2.4.
Mud logging unit
2.4.1.
The unit, installed above a skid and in compliance with local laws, A-1-SS-1722 shall be equipped with a no break generating set able to supply electric power for at least for 15 minutes; Contractor shall specify the maximum length, breadth, height and maximum weight.
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 shall A-1-SS-1722 be always available in the Unit for a prompt intervention by on site Contractor personnel, in case of a possible malfunction besides, in case of major malfunctioning, the Contractor shall provide for the immediate replacement of the faulty equipment
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 three A-1-SS-1722 years experience working on surface logging service company
2.1
2.5.2.
A Junior Surface Logger is required to have a minimum of one year A-1-SS-1722 experience working on surface logging service company.
2.1
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A-1-SS-1722
2.1
2.5.4.
Personnel qualification cards shall be duly and accurately filled in A-1-SS-1722 (Annex 9.3), and full details on courses attended, and certificates shall be provided.
2.3
2.6.
Radioactive sources
2.6.1.
In absence of local lows or regulations the following criteria could be a Worldwide guideline:
2.5.3.
Senior Surface Logger and Junior Surface Logger: • •
1. 2. 3. 4. 5. 6.
7. 8.
‘Well control course’ issued by Company IWCF approved. ‘Survival course’ (for offshore activity) issued by Company approved.
Certification to able the use of radioactive sources released from competent authority Particulars of the deputy “Qualified Expert” or his representative Radioactive safety detailed report drawn up by Qualified expert Procedure to adopt in case of tools failure Particulars of the “Qualified Doctor” for the Medical Surveillance Statement that the radioactive source operative activity will be performed by suitable personnel with medical examination performed in the last 6 months Classification of personnel in terms of radioactive exposure. 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 3.1. Personnel
Reference
3.1.1.
Senior Fluid Engineer is required to have a minimum of 5 (five) years A-1-SS-1719 field experience as Fluid Engineer.
4.1
3.1.1.1.
He shall be in possession of the following certificates:
A-1-SS-1719
4.1
• • • •
‘Mud engineer course’ ‘Completion fluid course’ ‘Survival course’ (for offshore activity) issued by approved Company ‘Basic well control course’ IWCF or IADC Wellcap approved
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3.1.2.
Fluid Engineer is required to have a minimum of one years field A-1-SS-1719 experience as Fluid Engineer.
4.2
3.1.2.1.
He shall be in possession of the following certificates:
A-1-SS-1719
4.2
3.1.3.
Technical Supervisor is required to have a minimum of eight years A-1-SS-1719 field experience as Fluid Engineer.
4.3
3.1.4.
Laboratory technician is required to have at minimum three years A-1-SS-1719 experience in laboratory test as per API RP 13I “Standard Procedure for Laboratory Testing Drilling Fluid” and as per API RP 13J ‘Testing Heavy Brines’
4.4
3.1.5.
During the activity, the Contractor shall supply the following A-1-SS-1719 documentation:
6
• • • •
• • • •
‘Mud engineer course’ ‘Completion fluid course’ ‘Survival course’ (for offshore activity) issued by approved Company ‘Basic well control course’ IWCF or IADC Wellcap approved
Fluid program (if requested) Daily mud report. End phase mud report. Final well mud report.
3.2.
Mud chemicals identification
3.2.1.
For each product , contractor shall furnish the following informations:
A-1-SS-1719
5.5
Contractor shall also inform of any possible danger in using the A-1-SS-1719 products offered (HSE information).
5.5
• • • • • • 3.2.2.
Commercial name Chemical name and composition Products classification Product application and recommended concentration Type of packing (sacks, drums etc.) Material safety data sheet.
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3.3.
Equipment
3.3.1.
Contractor shall have the availability, when needed a specific A-1-SS-1719 technical support, of a laboratory able to perform tests according with API RP 13B-1, 13B-2 (Standard Procedure for Field Testing Drilling Fluids) and with API RP13I-2 (Standard Procedure for Laboratory Testing Drilling Fluids).
3.3.2.
The main performance request is: • • • • •
5.3
‘G’ factor up to 3.000 must be able to work on 5 microns size solids high speed 3 must be able to treat up to 18m /h RPM up to 3.300
3.3.3.
On request, Contractor must be able to provide centrifuges with A-1-SS-1719 independent generator.
5.4.1
3.3.4.
Nothing shall relieve the contractor of the responsibility for performing A-1-SS-1719 such analysis, tests, inspections and other activities that he considers necessary to ensure that the product, and workmanship are satisfactory for the service intended, or as may be required by common usage or good practice.
3
Reference
4. CEMENTING SERVICE 4.1. Engineering 4.1.1.
The contractor shall provide an adeguate service for engineering A-1-SS-1729 support which shall include the following duties:
5.1
4.1.2.
• •
5.1
• • •
A-1-SS-1729 Drawing up of cement slurry programmes Supplying all the laboratory equipment necessary for testing slurries, spacers and API tests on chemical products including quality control on cement, Computer monitoring for cementing operations, real time acquisition of data (delivery, pressure, density) for the possible of a subsequent processing of the data recorded, Drawing up of reports concerning the works carried out and relevant evaluation. Drawing up a final well report.
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4.2.
Personnel
4.2.1.
The Contractor shall supply professional curricula for all personnel he A-1-SS-1729 intends to use, indicating background, training and work experience.
5.2
4.2.2.
All personnel involved in offshore operations shall hold a survival at A-1-SS-1729 sea certificate issued by a Company-approved Organisation or Institute.
5.2
4.2.3.
An operator is required to have a adeguate skill acquired through an A-1-SS-1729 appropriate training course and with at least five years of field experience
5.2.1
4.2.4.
Helper is required to have an adequate skill acquired through an A-1-SS-1729 appropriate training course.
5.2.2
4.2.5.
Contractor will guarantee availability of a technical supervisor from a A-1-SS-1729 base close to the area of operation.
5.2.3
4.2.6.
Contractor shall provide a laboratory technician to perform the A-1-SS-1729 required tests on cement, cement additives and cement slurry.
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:
A-1-SS-1729
5.3.1
Recirculation Mixing System shall grant mixing of the cement slurry A-1-SS-1729 and its recirculation before it is pumped into the well.
5.3.2
• • • • • • 4.3.3.
Twin triplex pumping units for pumping the cement slurry. The pumping unit working pressure shall be 10,000 psi and 500 HHP. The engines will be equipped with spark arresting air filters and air 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-select pump cut out system.
It will include a 1,300-1,500ft basin divided into two parts, each supplied with a mixer.
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4.4.
Batch Mixer shall grant the ‘surface’ mixing of determined quantities A-1-SS-1729 of cement slurry, spacers and/or other fluids. It will consist of tanks of 3 capacity ranging from 3 to 30m , each one self sufficient, provided with agitators, centrifugal pump and gauge to measure the pumped quantities.
5.3.3
4.5.
Documentation
4.5.1.
Contractor will prepare and submit for approval, before the execution A-1-SS-1729 of each service, a detailed ‘Operations Program’.
6.2
4.5.2.
After the execution of the service, Contractor shall provide to A-1-SS-1729 Company Operations a ‘Job Report’
6.3
4.5.3.
At the end of the operations, Contractor shall prepare the final report A-1-SS-1729 which shall include all the ‘Job Report’, ‘Operation Program’ and final considerations and suggestions, reason for the deviation from the program
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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REVISION
STAP-P-1-M-6090 PL. 1.7.
ESTIMATED COSTS
1. BUDGET The Well Area Department, requested by the ‘Project’ or ‘Exploration 1.1. Manager’, will make cost estimation of the planned well (based on the best information available at the time), this will be inserted into the yearly budget.
Reference
2. COSTS Before starting the activity, the Well Area Department, requested by the 2.1. ‘Project’ or ‘Exploration Manager’, will make a cost estimation of the forthcoming well. It will be split by class of cost, based on the progress chart included in the drilling (or completion, or workover) program, on the selected rig rates and on the other acquired contracts.
Reference
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, will check the conformity with the original budget (at this point a budget revision may be made) and will start the procedure for the Job centre opening.
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 the actual daily costs comparing the same with the previously estimated costs, 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 well and 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 being prepared. The Geological and Drilling Well Programme defines the objectives/targets of the well, reports the basic engineering data, specifies equipment and procedures necessary to drill safely a well, provides a realistic forecast of its final cost. The last column in the document indicates the available reference documents covering the particular topic. The list of reference documents and available computer programmes are reported at the end of each section. Continuous references to operating document sections are necessary for further investigation by the user.
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STAP-P-1-M-6090 PL. 2.1.
GEOLOGICAL AND DRILLING WELL PROGRAMME STRUCTURE
Reference 1. NUMBER OF THE SECTIONS 16 The ‘Geological and Drilling Well Programme’, from now on defined P-1-M-6100 1.1. P-2-N-6001E as ‘G&DWP’, comprises of four sections:
• • • • 1.2.
(introduction)
GENERAL INFORMATION GEOLOGICAL PROGRAMME OPERATION GEOLOGY PROGRAMME DRILLING PROGRAMME
(Section 1) (Section 2) (Section 3) (Section 4)
The G&DWP will be drawn in accordance with local regulations, and P-1-M-6100 P-2-N-6001E ENI Agip District or affiliate internal rules, taking into account:
16
(introduction)
1.
IGUs Operation Geology Procedures (Specific Agip Rules Nr. 1.4.15.3-8; Procedure Di Geologia Operativa Vers. 0.0 07/94 GESO) 2. FGUs Subsurface & Operation Geology Procedures. 3. STAP-P-1-M-6060 (Best Practices and Minimum Requirements for Drilling & Completion Activities) and all the documents concerning the planning and execution of the well, cited in the same 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 decrees 8. Well Name Designation 9. Rules for Management and Control of Technical Documents 10. Standardisation of documents Reference 2. PRINT MODEL 16 Whenever Microsoft Office products are available in the Eni Agip P-1-M-6100 2.1. P-2-N-6001E 1 districts or Affiliates, for preparing each section of the ‘G&DWP’’, it is recommended to use the model built in “WORD 6”, titled ‘WLPR_ING.dot’
2.2.
The four sections composing the G&DWP’, are identified by the name P-1-M-6100 P-2-N-6001E of the well.
16 3
2.3.
In order to make the Well Drilling Programme easily manageable’ P-1-M-6100 either in E-Mail or with shared network disks, the graphic P-2-N-6001E representations must be in an electronic format
16 5
Reference List: ‘Drilling Design Manual’ ‘Operative Procedure for Preparing the Geological and Drilling Well Programme’
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STAP-P-1-M-6100 STAP-P-2-N-6001E
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STAP-P-1-M-6090 PL. 2.2.
GENERAL INFORMATION (SECTION 1)
Reference 1. GENERAL 16 This section will be written in close co-operation by the Drilling & P-1-M-6100 1.1. P-2-N-6001E 7.1 Completion and Subsurface Geology Departments of the Affiliate.
1.2.
All depths, both for offshore and on-shore wells must be referred to P-1-M-6100 P-2-N-6002E the Rotary Table.
16 7.1
1.3.
Section 1 comprises the chapters numbered and titled as follows:
P-1-M-6100 P-2-N-6001E
16 7.1
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 Reference 2. GENERAL WELL DATA 16 The ENI Agip District or Affiliate’s Drilling & Completion Department P-1-M-6100 2.1. 7.1.1 will give the Well Profile, the Time Vs Depth Diagram, and the P-2-N-6001E Location Layout.
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)
SECTION 1 OF BP&MR - PLANNING (PL)
P-1-M-6100 P-2-N-6001E
16 7.1.1
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REVISION
STAP-P-1-M-6090
2.3.
Well Profile
2.3.1.
The Well Profile contains a Table showing, against the depth (total vertical depth), at least the following data: • • • • • • • • •
2.3.2.
Pore pressure gradient Formation fracture gradient Overburden gradient Mud weight MAASP Max differential pressure Drilling balance pressure Casings setting depth Static temperature gradient
Diagram showing all above information, including expected lithology.
Reference 3. GENERAL RECOMMENDATIONS 16 Will be written in close co-operation between the Drilling & P-1-M-6100 3.1. P-2-N-6001E 7.1.3 Completion and Subsurface Geology Departments.
3.1.1.
LWD operation joint Considerations: • • • • • •
3.1.2.
P-1-M-6140
13.1.2
P-2-N-6001E
7.1.3
The more suitable tools. Their positioning in the BHA. The drilling parameters to be used. The stabilisers are correctly positioned in the BHA, according to LWD tools. The maximum admissible flow through the LWD tools must not be exceeded, otherwise substantial erosion damage will occur inside the tool. Limiting the solid content in the mud in order not to exceed the LWD tools limitations.
To highlight the possible operative problems envisaged
4. GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND SAFETY EQUIPMENT Contains the information of Tables PL.02.02-1 and PL.02.02-2 4.1.
Reference P-2-N-6001E P-2-N-6001E
7.1.4.1 7.1.4.2
Reference 5. LIST OF THE MAIN CONTRACTORS 16 Will be written by the Affiliate’s Drilling & Completion Department in P-1-M-6100 5.1. P-2-N-6001E 7.1.5 co-operation with the Subsurface Geology Department.
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REVISION
STAP-P-1-M-6090 Reference 6. CONTACTS IN CASE OF EMERGENCY P-1-M-6100 16 Will be written by the ENI Agip District or Affiliate’s Drilling & 6.1. P-2-N-6001E 7.1.6 Completion Department and shows:
1. The ‘flow chart’ of emergency contacts 2. The telephone numbers of the people in charge of the emergency.
Reference 7. REFERENCE MANUALS 16 Will be written by the ENI Agip District or Affiliate’s Drilling & P-1-M-6100 7.1. P-2-N-6001E 7.1.7 Completion Department. It consists of a list of basic manuals to be referred for planning and implementation phases of the well. Reference 8. MEASUREMENT UNITS 16 Will be written in strict co-operation between the ENI Agip District or P-1-M-6100 8.1. P-2-N-6001E 7.1.8 Affiliate’s Drilling & Completion and Subsurface Geology Departments. It will contain a list of the units of measurement of the main parameters used in the Geological Operation and Drilling sections. Reference 9. SIGNATURE 16 The names and signatures of the technicians and managers involved P-1-M-6100 9.1. 7.1.9 in the preparation and control of the section will always be specified. P-2-N-6001E
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Operative Procedure for Preparing the Geological and Drilling Well Programme’
STAP-P-2-N-6001E
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STAP-P-1-M-6090
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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STAP-P-1-M-6090
ITEM
DESCRIPTION
Diverter type Diverter size Diverter working pressure BOP stack type BOP size BOP working pressure Choke Manifold size and working pressure Kill 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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REVISION
STAP-P-1-M-6090 PL. 2.3.
LAYOUT OF THE DRILLING PROGRAMME (SECTION 4)
Reference 1. BASIC REQUIREMENTS 16 The Drilling Program must accomplish with basic requirement setforth P-1-M-6100 1.1. 6 in the Geological Program in terms of total depth, targets and P-1-N-6001E reservoir specified needs.
1.2.
Particularly, paragraphs 4.2.1 (Forecast on pressure and temperature P-1-M-6100 gradients) and 4.2.2 (Drilling problems) will be made in co-operation P-1-M-6100 between Drilling & Completion and Geology District/Afiiliate Departments
16 16.4.4
1.3.
All depths, both for offshore and on-shore wells must be referred to P-1-M-6100 the rotary table. If the rotary table elevation is not yet available, it will P-1-N-6001E be assumed based on past experiences with similar drilling rig types
16 6
1.4.
Section 4 will comprise the sub-sections numbered and titled as P-1-M-6100 P-1-N-6001E follows:
16 6.1
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. Testing 4.1.7. 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. BOP 4.2.8. 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
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REVISION
STAP-P-1-M-6090
1.5.
The Drilling Programme index and numbering of sections must be laid P-1-M-6100 down as shown above; whenever a topic is not applicable to the P-1-N-6001E actual programme, the relevant sections/paragraphs shall be marked with ‘not applicable’.
16 6.1
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
‘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 It will detail operations to be undertaken before the spud-in. 1.1. 2. CONDUCTOR PIPE PHASE The following information must be provided: 2.1. 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
SECTION 1 OF BP&MR - PLANNING (PL)
Reference P-1-M-6100
16
Reference P-1-N-6001E
6.2.2
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REVISION
STAP-P-1-M-6090
3. SURFACE PHASE The following minimum information must be included: 3.1. • • • • • • • • • • •
• • • • • • • • • • • • • • •
P-1-N-6001E
6.2.3
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 the end 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 phase length Survey and directional drilling requirements, if any Well head test pressure value Diverter/BOP stack installation Remarks
4. INTERMEDIATE PHASES The following minimum information must be included: 4.1. •
Reference
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) Brief description of operations (drilling, casing run, cementing) 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
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Reference P-1-N-6001E
6.2.4
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REVISION
STAP-P-1-M-6090 5. FINAL PHASE The following information is included: 5.1. • • • • • • • • • • • • • • • • •
Reference P-1-N-6001E
6.2.5
Description of difficulties and reference to a specific paragraph for further details Reference to anticollision procedures (if applicable) Hole size and other requirements tied with drilling operations in target/reservoir (e.g. target details, eventual use of non damaging fluids, depth of multiple targets, etc.) Vertical and measured total depth Brief description of operations (drilling, casing run, cementing) 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 phase length Survey and directional drilling requirements, if any Hanging casing in well head (if applicable, with or without overpull) Hanging of liner and liner head seal test pressure (if applicable) Casing and well head test pressure values BOP stack test Remarks
Reference 6. TESTING 6.2.6 On the basis of information available during the planning phase this P-1-N-6001E 6.1. paragraph should describe operations related to the well testing. Reference 7. TYPE OF COMPLETION 6.2.7 On the basis of information available during the planning phase, this P-1-N-6001E 7.1. paragraph should describe the sequence of operations and main information on the type of the foreseen completion.
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Reference 8. WELL ABANDONMENT 6.2.8 On the basis of information available during the planning phase sets P-1-N-6001E 8.1. out a programme for well abandoning, describing 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.
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
‘Operating Procedure for Drawing the ‘Well Drilling Programme’’
STAP-P-1-N-6001E
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REVISION
STAP-P-1-M-6090 PL. 2.5.
SOFTWARE (SECTION 4) Reference
1. STANDARDS As concerns:
P-1-N-6001E
6.3
• 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 formats of the IWIS system if available. Reference 2. ALTERNATIVES 6.3 COMPASS for the design of directional drilling and anticollision analysis P-1-N-6001E 2.1. for wells.
2.2.
P-1-N-6001E
6.3
These evaluations must be run for all the deviated/deep wells and duly P-1-N-6001E checked for calibration while drilling.
6.3
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.
2.2.1.
Reference List: ‘Operating Procedure for Drawing the ‘Well Drilling Programme’’
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REVISION
STAP-P-1-M-6090 PL. 2.6.
PRESSURE GRADIENTS PROGNOSIS (SECTION 4)
1. PRELIMINARY DATA COLLECTION 1.1. Geological data
Reference
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 and P-1-M-6130 give an indication of any pore pressure abnormalities. In all cases, it must be considered an approximate solution.
3.6
1.2.2.
1 Offshore seismic data can be used to determine the possible P-1-M-6130 presence of shallow gas.
3.6
1.2.3.
Seismic data are usually given as vertical average velocity (RMS- P-1-M-6130 -3 velocity, m/s), Vs ‘two way travel time’ (10 sec), for a single 2 CDP (Common Depth Point).
3.6
1.3.
Offset/reference well data
1.3.1.
Drilling records - Drilling reports:
ARPO-02/A P-1-M-6130
4.1
The drilling parameters, the recording and interpretation of which only give a qualitative evaluation of overpressure (i.e., its possible presence and the location of its top), include the following: • • • • • • • • • • • •
1 2
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.
In this case, a high resolution seismic is performed, which usually investigates formations down to 500 meters depth below the seabed. 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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REVISION
STAP-P-1-M-6090
1.3.2.
Drilling records - Mud logs: • • • • • • • •
P-1-M-6130
4.2
lithology of formations drilled gas shows mud weights ROP drilling parameters bit records formation temperature other relevant parameters (torque, mud temperature, etc.).
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:
P-1-M-6130
5.2
• • • 1.3.5.
Resistivity (induction) Sonic Density. P-1-M-7130
RFT/DST data. The repeat formation test (RFT), and drill stem testing are direct measurements that provide accurate information on pressure values.
1.3.6.
Interpreted formation pressure profile.
P-1-N-6001E
6.3.1
Wireline logs interpretation, sigmalog or similar. Reference
2. DEFINITIONS 2.1. Kick tolerance volume 2.1.1.
Kick tolerance is the term used to define the maximum kick volume P-1-M-6110 which can be safely controlled by any well control method with constant BHP without fracturing the formation below the last casing shoe. The most dangerous situation is when the top of the kick reaches the casing shoe.
2.1.2.
Kick tolerance volume at total depth: (hypothesis vertical well) − 4 Ca Gfs Hs [ Hs (Gfs − G m )] + ( H G m ) − (10 Pp ) Vi, H =
10
[ ]
Pp
Gm − G g
Vi, H = m3
[ m] annular capacity beneath the shoe
Ca = l
2 Gfs = kg/cm formation fracture gradient at shoe 10m Hs = [ m] shoe depth Pp = kg 2 formation pressure at total depth cm
Gm = kg mud weight l H = [ m] total depth
Gg = [ S.G.] influx (gas) gradient
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2.2
12.2
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STAP-P-1-M-6090
2.2.
Leak off tests (LOT)/Formation Integrity Tests
P-1-M-6140
11
2.2.1.
A Leak-Off Test (LOT) will be performed On Wild-Cat wells at each P-1-M-6140 casing shoe after setting the surface casing. LOTs are also recommended to be carried out on both appraisal and development wells.
11
2.2.2.
Leak Off Tests and Formation Integrity Tests (FIT), also termed the P-1-M-6140 Limit Test, are for formation strength pressure tests made just below the casing seat prior to drilling ahead.
11
2.2.3.
1 Record and plot pressure values vs. cumulative volume (bbls, /4 bbl P-1-M-6140 1 1 scale), pumping at /2bpm constant rate in 17 /2” (16”) hole sections 1 1 and /4 bpm in 12 /4” hole sections. LOT pressure doesn’t exceed the pressure to which the casing was P-1-M-6140 tested.
11
Stop pumping when a deviation from linear trend is recorded (two or P-1-M-6140 three points).
11
2.2.4. 2.2.5.
11
Pump uniform volumes of mud and wait for the pressure to stabilise. 1 Flow rates range from /8 bbl/min (20l/min) up to a maximum of 1 1bbl/min (160 l/min), however values of 0.25bbl (12 /4” and smaller 1 holes) or 0.50bbl (17 /2” hole) are commonly used. Wait for two minutes, or the time required for the pressure to stabilise. 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: standing P-1-M-6140 pressure.
11.1
2.2.8.
Calculate the formation strength in terms of ‘Equivalent Mud Weight’ P-1-M-6140 using the lowest between leak off point pressure and stabilised pressure.
11.1.
2.2.9.
LOT/FIT Test procedure.
P-1-M-6140
11.1
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STAP-P-1-M-6090
P-1-M-6130
2.3.
Fracture gradient
2.3.1.
Equations used by the Company for fracture gradient calculation, P-1-M-6130 once overburden gradients and pore pressure gradients have been defined are:
2.1.5.
2.1.5.
When dealing with elastic formations, the fracture gradient Gfr is obtained by an equation derived from the more general Terzaghi equation: Terzaghi equation:
Equation
2.18
If the drilling fluid is water or wherever water deeply invades the formation, Gfr is given by: Equation Gfr = Gp + 2 ν (Gov − Gp )
2.19
G fr = Gp +
2ν (Gov − Gp ) 1− ν
With plastic formations, such as clays, marls, etc.: Gfr = Gov
Equation
2.20
P-1-M-6130
2.1.5.
Gfr = fracture pressure gradient. Gov = overburden gradient. Gp = formation pressure gradient. ν = Poisson’s module 2.3.2.
The Poisson’s modulus may have the following values: ν = 0.25 for clean sands, sandstone and carbonate rocks down to medium depth. ν = 0.28 for shaly sands, sandstone and carbonate rocks at great depth.
3. PRESSURE GRADIENTS PREDICTION & EVALUATION 3.1. Seismic data 3.1.1.
Reference
The seismic data transformed, in accordance with what has been P-1-M-6130 discussed above, in terms of depths, interval velocities and/or interval transit times, at this point are ready to be used for pressure gradient calculation, that is of: • • •
Overburden gradient Pore pressure gradient Fracture gradient.
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STAP-P-1-M-6090
P-1-M-6130
3.6.2
3.1.3.
3 The first purpose of interpretation is to determine ‘interval transit time P-1-M-6130 (ITT)’ trend. The normally pressurised shales will be plotted as a trend line on depth vs. ln (ITT) graph. An increase in ITT values away from the trend line will indicate the presence of abnormal pressures. (A draw back in using this method is the difficulty of determining the correct trend line.)
3.6.2
3.1.4.
The second step of interpretation is the pressure gradient calculations:
3.1.2.
Two methods of analysis of the data can be applied; these are: 1. 2.
• • •
Plotting of ‘Interval Velocity versus Depth’ or, more commonly, ‘Interval Transit Times versus Depth’ graphs; Method of ‘Interval Velocity/Theoretical Velocity Ratio, V1/V2’.
Overburden gradient Pore pressure gradient, calculation is based on equivalent depth method Fracture gradient.
3.2.
Wireline logs
3.2.1.
Induction and sonic logs are used to identify any deviation from the P-1-M-6130 normal compaction trend. The pressure transition is usually clearly indicated by increased conductivity and sonic transit time.
3.2.2.
Sonic log
3.2.2.1.
Sonic log method (SL): also termed ‘∆t shale’, is the most widely used P-1-M-6100 as, from experience, it gives the most reliability. It consists of the plotting, 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 in normal compaction zones and increases with the depth in overpressure zones.
3.2.2.2.
Several plots for wells drilled in the same area can be used to determine the ‘average regional trend line’.
3.2.2.3.
Once the top of the overpressures is fixed, the next phase concerns P-1-M-6130 the pore pressure gradient calculation as a function of depth. The method generally used is based on the ‘principle of equivalent depth’
3
Interval transit time is given in [µsec/ft].
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5.2
2.2.5
3.6.2
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STAP-P-1-M-6090
3.2.3.
Resistivity logs
3.2.3.1.
Under a normal pressure environment shale resistivity will increase P-1-M-6130 4 with depth as porosity decreases .
4.2.15
3.2.3.2.
Shale resistivities are plotted on semi-log scale versus depth (vertical P-1-M-6130 depth). The normal trend line can be straight or curved. Only resistivity values obtained in good clean shales must be used.
4.2.15
3.2.3.3.
Limitations in using resistivity plots are: • •
P-1-M-6130
5.2.2
5.2.2
Establishing the shape and position of the normal trend Variations in pore water salinity can give false abnormal pressure indications.
3.2.3.4.
Several methods can be used to estimate the magnitude of any abnormal pressure.
3.2.4.
Density logs
3.2.4.1.
The bulk density readings (g/cc), must be plotted on semi-log scale P-1-M-6130 versus depth, a straight normal trend in shale’s is observed. A decrease in shale bulk density away from the normal trend will indicate overpressure.
3.2.4.2.
The equivalent depth method can then be used to calculate the value of 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:
P-1-M-6100 P-1-M-6130 P-1-M-6130
2.2.3 4.2.3 4.2.4
The corrected ‘d’ exponent and Eni-Agip Sigmalog eliminate the effects of drilling parameter variations and give a representative measure of formation drillability. The TDC Engineer is responsible for continuous monitoring and shall immediately report to Company Drilling Supervisor, if any change occur. A copy of corrected Eni-Agip sigma-log/d-exponent shall be sent on daily basis to Company Drilling Office.
4
Formation resistively depends primarily on porosity and salinity of the pore water. Temperature also has a minor influence.
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REVISION
STAP-P-1-M-6090
3.3.1.2.
Drilling break:
P-1-M-6100
2.2.3
P-1-M-6100
2.2.3
P-1-M-6100
2.2.3
P-1-M-6100
2.2.3
P-1-M-6100
2.2.3
P-1-M-6100 P-1-M-6130
2.2.4 4.2.16
P-1-M-6100 P-1-M-6130
2.2.4 4.2.18
Any time a drilling break is noticed, drilling is to be suspended and a flow check shall be carried out. 3.3.1.3.
Torque: Torque sometimes increases when an abnormally pressured shale section is penetrated.
3.3.1.4.
Tight hole on connections: A tight hole when making connections can indicate that an abnormal pressure shale is being penetrated using low mud weight.
3.3.1.5.
Hole fill: During connections cave ins may have settled preventing the bit from returning to bottom. Wall instability in an area of abnormal pressure may cause sloughing.
3.3.1.6.
MWD: MWD can provide a wide range of bottom hole drilling parameters and formation evaluation: bottom hole weight on bit, torque at bit, gamma ray, resistivity, mud pressure and temperature. If the true weight and torque at bit are known, drilling rate can be normalised with more accuracy.
3.3.2.
Indicators depending on lag time
3.3.2.1.
Mud gas: • • • • • •
3.3.2.2.
Background gas. Drilling gas. Gas shows. Trip gas. Connection gas. Mud weight out & involved total volume.
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 with overlying normally pressured sequences.
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3.3.2.3.
Mud resistivity/chlorides:
P-1-M-6130
4.2.14
P-1-M-6100 P-1-M-6130
2.2.4 4.2.11
When a salinity contrast exists between mud filtrate and formation fluid, is possible to detect overpressure zones by monitoring levels of mud chlorides. 3.3.2.4.
Cutting analysis: • • • •
3.3.2.5.
Lithology Shale density Shale factor Shape, size and volume of cuttings.
In the mud logging a technical specifications document is included in the detection and evaluation of formation pressure that must be done with sigma-log/dc-exponent method.
Reference List: ‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘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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REVISION
STAP-P-1-M-6090 PL. 2.7.
SHALLOW GAS
1. PRELIMINARY SHALLOW GAS INVESTIGATION 1.1. Possibility of encountering shallow gas 1.1.1.
Reference
Well proposals shall always include a statement on the possibility of P-1-M-6150 encountering shallow gas.
9.1
Statement contents: 1. 2. 3. 4.
Assessments drawn from the shallow gas survey All relevant seismic surveys All offset well data records Geological probability of a shallow cap rock.
1.1.2.
Pilot holes may be drilled, up to the conductor string depth, as part of P-1-M-6150 a preliminary shallow gas investigation programme prior to spudding a well where platforms are planned to be installed, in areas with high probability of shallow gas or only a little geological information is available.
9.1
1.1.3.
A rig that can move away safely in case of shallow gas blow out P-1-M-6150 should be used to drill pilot holes (mobile offshore drilling unit or a dedicate soil boring vessel).
9.1
1.2.
Gas pocket pressure
1.2.1.
The amount of overpressure at the top of the shallow gas P-1-M-6150 accumulation depends on the vertical thickness of the gas column (h):
9
∆p=0.1 (1.03-Ggas) h 2. SHALLOW-GAS DRILLING GUIDELINES 2.1. Decision-making guidelines
Reference P-1-M-6150
9.3.1
2.1.1.
The following drilling practices may be modified for development wells P-1-M-6150 where it is confirmed that no shallow gas is expected.
9.3.1
2.2.
Pilot hole
2.2.1.
• •
•
P-1-M-6150 It should be drilled in areas with potential shallow gas. P-1-M-6150 Pilot holes may be drilled, up to the conductor string depth, as part of a preliminary shallow gas investigation programme, in areas with high probability of shallow gas or only a little geological information is available. 1 Generally, it is recommended that a drill 12 /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). P-1-M-6150 Particular care should be taken to avoid an excessive build-up of solids in the hole. Drilling with heavier mud returns could also obscure indications of drilling through higher pressured formations.
2.4.
Swabbing
2.4.1.
• •
• •
Pumping at the optimum circulating rate is recommended for all P-1-M-6150 upward pipe movements (e.g. making connections and tripping). 1 In larger hole sizes especially (i.e. larger than 12 /4”), it is important to check that the circulation rate is sufficiently high and the pulling speed sufficiently low to ensure that no swabbing will occur. A top drive system will facilitate efficient pumping while tripping out of hole operations. The minimum required number of stabilisers should be used.
2.5.
Drilling Fluid
2.5.1.
• • • •
P-1-M-6150 Accurate measurement and control of drilling fluid. Properly calibrated and functioning gas detection equipment and a 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 data transmission system is used) and at any specific depth referred to in the drilling programme (taken from the shallow seismic survey), it is recommended to flow check at each connection
2.6.
Float Valve
2.6.1.
A float valve must be installed in all bottom hole assemblies, which P-1-M-6150 are used in top hole drilling. The float valve is the only down hole mechanical barrier available.
2.7.
BHA
2.7.1.
BHAs, used for kick-off operations, have flow restrictions which will P-1-M-6150 considerably reduce the maximum possible flow through the drillstring. Dynamic well killing operation will then be very unlikely.
2.8.
Shallow Kick-offs
2.8.1.
Shallow kick-offs should be avoided in areas with probable shallow P-1-M-6150 gas.
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9.3.1-c
9.3.1-d
9.3.1-e
9.3.1-f
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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 P-1-M-6150 depth and riser size shall be prepared before commencement of drilling.
2.10.
Pre-spud meeting
2.10.1.
Before spudding the well, a meeting should be held in order to alert P-1-M-6150 key personnel (Drilling Contractor personnel, mud engineer, mudlogging operator included).
3. DIVERTER 3.1. Specific contingency plans
9.3.1-h
Reference
3.1.1.
Specific contingency plans for dealing with emergencies which may P1M6150 occur during diverter operations should be prepared for each rig and each well.
3.2.
Main Types of Diverter
3.2.1.
Main types of diverter: • • •
9.3.1-g
9.4
P-1-M-6150
9.4.1
P-1-M-6150
9.4.3
Surface diverter. Marine diverter. Subsea diverter, which is not common and available only on few rigs.
3.3.
Diverter Test (before start of operations).
3.3.1.
Before start of drilling operations perform a diverter test.
3.4.
Operation without the riser
3.4.1.
Riserless drilling is considered to be the safest way to cope with the P-1-M-6150 shallow gas problem since the vessel can quickly move away from a subsea blow-out.
9.3.5
3.4.2.
Water depth has some influence on buoyancy loss, but it has greater P-1-M-6150 influence on vessel instability, especially at very shallow water depth.
9.3.5
3.5.
Conductor pipe
3.5.1.
Running and cementing the 30” casing in a pre-drilled hole, after P-1-M-6150 having drilled a pilot hole, is the recommended technique in areas where shallow gas might be encountered.
9.3.6
Reference List: ‘Well Control Policy Manual’
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REVISION
STAP-P-1-M-6090 PL. 2.8.
CASING SETTING DEPTH
1. DETERMINE PROPER SETTING DEPTH FOR EACH CASING TYPE 1.1. Preliminary information
Reference
1.1.1.
When planning, all available information should be carefully P-1-M-6110 documented and considered to obtain knowledge of the various P-1-M-6100 uncertainties.
3 3
1.1.2.
The selection of casing setting depths is based on:
P-1-M-6110 P-1-M-6100
3 3
• • • • • • • • • • •
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 completion programme (production well). Casing availability (grade and dimensions). Economy, i.e. time consumption to drill the hole, run casing and cost of equipment. Reference
2. GENERAL GUIDELINES ON CASING SETTING DEPTHS 2.1. Conductor Pipe 2.1.1.
The driving depth of the conductor pipe which is specified in the P-1-M-6140 Drilling Programme is established with the following formula:
Hi =
4.1.2
[MW x (E + H) - 103 x H] [1.03 - MW + 0.67 x (GOVHi - 1.03)]
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 = 2.1.2.
3
integrated density of sediments (kg/dm /10m)
Drive the conductor pipe till the final depth or the refusal point of P-1-M-6140 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 gradient P-1-M-6110 sufficient enough to allow drilling to the next casing setting point and P-1-M-6100 to provide reasonable assurance that broaching to the surface will not occur in the event of BOP closure to contain a kick.
2.3.
Intermediate Casing
2.3.1.
In general practice, drilling is allowed until the mud weight is within P-1-M-6100 50gr/l of the fracture gradient measured by conducting a leak-off test at the previous casing shoe.
3. SAFETY REQUIREMENTS Evaluate ‘kick tolerance volume’ at the end of each hole section. 3.1.1.
3.2 3.2
3.3
Reference PL.02.01
2.1
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
‘Casing Design Manual’
STAP-P-1-M-6110
‘Drilling Procedures Manual’
STAP-P-1-M-6140
Software: CASCADE-IWIS (ADIS)
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STAP-P-1-M-6090 PL. 2.9.
DIRECTIONAL WELL PLANNING
Reference 1. PRELIMINARY DIRECTIONAL PLAN INFORMATION 3.5 The SDE will ensure that the Directional Contractor is provided with P-1-M-6120 1.1. all data necessary for an initial well profile.
1.2.
The well deviation diagram (plan and vertical section) is included, P-1-N-6001E along with output tables.
6.3.12
In the case of cluster wells, diagrams and tables for vertical wells are also given. 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, platform slots Expected lithology - with a clear indication of subsea or RKB depths 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 directional profile. Definitive survey data of all well bores which may constitute a collision risk.
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1.4.
Topographic References
1.4.1.
Will comprise the following information: • • • • • • • • • • • • • • • •
P-2-N-6001E
7.1.1
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
2. DEFINITIONS 2.1. UTM (Universal Transverse of Mercator)
Reference
2.1.1.
The co-ordinates for each UTM grid sector are given in metres with P-1-M-6100 the origins (i.e. the zero value) at a line 500,000m West of the centre P-1-M-6140 meridian to avoid negative values and at the equator. The coordinates are given as Eastings and Northings.
2.2.
Convergence angle
2.2.1.
The convergence angle is the angle between UTM North (Grid North) P-1-M-6100 and True North (Geographic North). In carrying out the projection P-1-M-6140 there is some distortion of the axes such that UTM North is slightly offset from Geographic (True) North. This small difference is significant over large distance and so must be taken into account when converting co-ordinates from one system to another.
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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. P-1-M-6120 latitude and departure of the well to be drilled. This will be the zero point on the horizontal well plan used to plot the well while drilling.
3.2.4
2.3.1.1.
Isolated wells:
P-1-M-6120
3.4.3
P-1-M-6120
3.4.3
P-1-M-6120
3.4.3
P-1-M-6120
3.4.3
The initial ORP will be the planned RKB location. 2.3.1.2.
Template wells: The ORP is the designated template centre.
2.3.1.3.
Platform wells: The ORP is the slot area centre or a designated slot.
2.3.2.
Onshore cluster wells: The ORP is a designated slot.
2.4.
Local Magnetic Declination Correction
2.4.1.
The magnetic declination will be individually calculated for each new P-1-M-6120 P-1-M-6140 location. P-1-M-6100
4.4.12 9.1 12.1
Since it is a time based measurement, the date used for the calculation will be an estimated mid-point for the drilling operation period. Subsequent surveys will require the re-calculation of magnetic declination if taken more than six months after the well is drilled. It is obtained from actual geomagnetic field maps. 3. SURVEY CALCULATIONS 3.1. Calculation techniques 3.1.1.
Eni-Agip standard survey calculation method:
Reference
P-1-M-6120 P-1-M-6120
4.4.4 3.4.1
‘minimum radius of curvature method’ 3.2.
Source of survey errors
3.2.1.
Algorithm used to calculate position.
3.2.2.
Survey tool uncertainty.
Tab. OP.02.02-3 Tab. OP.02.02-4 P-1-M-6120 4.4.4
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3.3.
Surveying requirements
3.3.1.
General Surveying Requirements:
P-1-M-6120
4.4.1
•
All magnetic surveys will have to be reported after being corrected for magnetic declination. Magnetic declination must be specified. • For other surveys, ensure that magnetic declination is considered while aligning. • Gyro survey output does not need to be corrected for magnetic declination. • The depth of a survey is the survey instrument depth not the bit depth. 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 bottom hole location the dipmeter can be used as it can survey down to around 5m from TD if hole conditions allow. For drilling purposes ‘depth’ will always be quoted as drilled depth and not confused with wireline depth. 4. SURVEY TOOL SELECTION 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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Reference
P-1-M-6120
4.2.9
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4.1.2.
Survey programme for vertical holes: • • • • • •
TOTCO will be acceptable only in vertical wells for surface holes if 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 FINDS will be used
4.2.
Factors affecting survey tool selection
4.2.1.
Maximum inclination.
P-1-M-6120 P-1-M-6120 P-1-M-6120 P-1-M-6120
4.5.3 4.7 4.8 4.6.2
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
Survey accuracy requirement will differ between vertical and deviated wells. 4.2.2.
Casing size. 3
FINDS inertial surveying system can be run only in 13 /8" casing or larger. 4.2.3.
Survey depth. GSS will not be run deeper than 400m due to excessive drift rates.
4.2.4.
Hole inclination. Maximum inclination for GSS, GMS and SRG is 70° (stability limit).
4.2.5.
Potential drilling problems: Differential sticking problems precludes the use of wireline based surveys with drillpipe in open hole (GSS, SRG, MSS and EMS).
4.2.6.
High pressure reservoirs: In an isolated deviated well, GMS or SRG will be run in the previous casing to establish minimum uncertainty before drilling through a high pressure zone (in case of a blow out and a relief well is required). A more accurate tool (NSG/GCT) may be used for accuracy improvement.
4.2.7.
Temperature limitation. Maximum borehole temperature must be within specification for the survey tools proposed for the programme.
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4.2.8.
Well proximity.
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120
4.5.3
P-1-M-6120 P-1-M-6140
4.6.1 9.4.1
P-1-M-6120
4.6.1
Template/platform wells, which are drilled in the neighbourhood of other wells, must maintain a minimum separation with respect to the other wells. This may require additional surveys (e.g. NSG in drill pipe) more often than with individual wells. 4.2.9.
Survey accuracy. Installations will be most crowded immediately below the platform/template and will require greater survey accuracy to fix well bore locations. The most accurate tools (FINDS or NSG) may be necessary for minimum uncertainty in critical situations.
4.2.10.
Magnetic Influence. Magnetic based surveying instruments will not be used, in any situation, as the prime source of well location calculations when within 8m of any adjacent casing string.
4.2.11.
Target size and depth: The accuracy of the surveying tools used on a well will be such that the total horizontal uncertainty at target depth is reasonable compared to the target size. The smaller and the deeper the target, the more stringent the survey requirements.
4.3.
Non-magnetic drill collars requirements
4.3.1.
See proper charts in reference documents. Non-magnetic stabilisers will be the only type permitted for use between NMDC's.
4.4.
Quality control
4.4.1.
Magnetic Survey Tools: Magnetic azimuth values will be considered invalid when the survey instrument is within 8m of an adjacent casing shoe: When magnetic influence is expected from adjacent casing (or when the well is separated less than 8m horizontally from an adjacent casing string), provision will be made to run a gyro based survey tool on 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 Standard minimum survey programme for vertical exploration wells: 5.1.
Reference P-1-M-6120
4.7
P-1-M-6120
4.8
(Refer to Figure PL 2.3 ) 5.2.
Standard minimum survey programme for directional wells: (Refer to Table PL 2.4)
Reference
6. ANTI-COLLISION 6.1. Objectives 6.1.1.
Anti-collision procedures will be implemented, in all cases where is a P-1-M-6120 potential collision risk according to the policies outlined in this manual.
5.1
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 trajectories of already existing wells. Establish a common procedure that discriminates between interference from completed/producing wells and plugged/abandoned/uncompleted wells.
6.2.
Definitions
6.2.1.
Current Well (CW):
P-1-M-6120
5.2.5
P-1-M-6120
5.2.5
P-1-M-6120
5.2.5
P-1-M-6120
5.2.4
The well being planned or drilled. 6.2.2.
Target Well (TW): Any well being considered for anti-collision purposes or proximity calculations.
6.2.3.
Radius of Uncertainty (ROU): The ROU is the radius of a sphere, at a specific vertical depth, which has the probability of containing the well-path. It is a cumulative calculation based on the product of the Horizontal Uncertainty Factor of the survey instrument used to that point and the surveyed depth to that point.
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 with depth and depends only on the type of survey instrument and on the hole inclination.
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6.2.5.
Separation ratio (SR): • • SR
6.2.6.
P-1-M-6120
5.2.8
P-1-M-6120
5.2.7
P-1-M-6120
5.2.8
Separation Ratio > 1 = No interference between ROU’s. Separation Ratio < 1 = Interference between ROU’s. =
CCD/(CW ROU + TW ROU)
Separation Distance (SD): The SD is the distance, in the plane of the expected closest approach, between ROU of the CW and the TW at a given vertical depth. SD = CCD -[ROU (CW) + ROW(TW) ]
6.2.7.
Centre To Centre Distance (CCD): The CCD is the distance, in the plane of the expected closest approach, between the centres of CW and TW paths at a given vertical depth.
6.2.8.
Curve A - Threshold of separation:
P-1-M-6120
5.2-F5.2
P-1-M-6120
5.2-F5.2
P-1-M-6120
5.2-F5.2
P-1-M-6120
5.2-F5.2
P-1-M-6120
5.2-F5.2
P-1-M-6120
5.2-F5.2
Is the curve that, at any depth represent the condition SR = 1 At any depth define the distance of potential collision. 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
6.2.10.
Curve C - Threshold of danger: Is the curve where, at any depth, condition SR = coefficient C Usually coefficient. C = 2
6.2.11.
Zone X - Field of danger: The field between Curve C and Curve B
6.2.12.
Zone Y - Field of alert: The field between Curve B and Curve A
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 a P-1-M-6120 probabilistic analysis of the occurrence of potential well collision situations. The Uncertainty Area Ratio (UAR) concept could be used to evaluate the probability of the occurrence of potential well collision situations. The UAR is the ratio of the sum of the two Uncertainty Area to the sum of the two hole sizes.
UAR =
5.2.10
(CWROU2 + TWROU2) (CWOD2 + TWOD2) where:
CWOD
=
the outside diameter of the current well
TWOD=
the outside diameter of the target well
6.4.
Responsibilities (well planning stage)
6.4.1.
The DM will have overall responsibility for the maintenance of safe P-1-M-6120 P-1-M-6120 operations while drilling in proximity to other wells.
6.5.
Planning wells with interference producing/completed wells and new wells
6.5.1.
Directional Well Plans in which trajectories fall into zone X is only P-1-M-6120 allowed when the target well (TW) has been properly plugged.
5.5.1-b
6.5.2.
The SDE will define any CWs falling within the zone X, during the well P-1-M-6120 planning stage and will prepare necessary recommendation according to the following guideline:
5.5.1-c
• • •
• 6.5.3.
between
5.5.1-a 5.2.9
existing
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 position within zone X. While drilling within zone X to assure adequate quality and frequency of the surveys, MWD will be used.
The SDE will prepare a contingency plan for plugging appropriate P-1-M-6120 P-1-M-6120 TWs. The contingency plan will specify procedures, timing and responsibilities of other Eni-Agip Division and Affiliates departments in suspending the appropriate TWs and will be included in the well programme for the CW.
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6.5.4.
Planning directional wells in which trajectories fall into the zone Y are P-1-M-6120 P-1-M-6120 not allowed as a part of normal procedure.
5.5.1-f 5.5.1-g
Dispensation will require approval by the DM and must be clearly stated and documented. 6.5.5.
Planning and drilling with separation falling in the zone Z is P-1-M-6120 unacceptable under any circumstance.
6.6.
Planning wells with interference between existing, completed/plugged & abandoned wells and new wells
6.6.1.
Planning new wells within zone Y is allowed when the target well P-1-M-6120 (TW) is a plugged and abandoned, suspended or not completed well.
5.5.1-b
6.6.2.
During the well planning stage, the SDE will define any CWs falling P-1-M-6120 within the zone Y and will prepare necessary recommendation according to the following guidelines:
5.5.1-d
• • • •
non P-1-M-6120
5.5.1-n
5.5.2
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 the wellsite while drilling the CW in order to confirm the CW position within zone Y. While drilling within zone Y to assure adequate quality and frequency of the surveys, MWD will be used.
6.6.3.
Planning and drilling with separation falling in the zone Z is P-1-M-6120 unacceptable under any circumstance.
6.7.
Suspension of wells
6.7.1.
Suspension of target wells (TW):
5.5.1-c
P-1-M-6120 Figure. 5.6
5.6
P-1-M-6120 Figure. 5.6
5.7
(Refer to Figure PL 2.3 ) 6.7.2.
Suspension of current well (CW): (Refer to Figure PL 2.3 )
6.8.
Projection technique
6.8.1.
Additional hole uncertainty due to maximum dogleg potential of the P-1-M-6120 assembly will be added to the ROU of the current well.
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6.9.
Planning a multi-well site
6.9.1.
Reduce potential well collision situations:
P-1-M-6120
5.4
6.9.2.
Spacing of wells for the surface vertical phases will not be subjected P-1-M-6120 to SR < 1 limit, in case drilling is planned/performed from a multi-well site where all the surface phases have to be drilled subsequently at once time.
5.4
6.9.3.
Antic collision procedures will apply, for the surface vertical phase, in P-1-M-6120 case drilling is planned/performed from a multi-well site where production from adjacent wells is on going or during any production while drilling activity.
5.4
6.10.
Well site procedure
6.10.1.
Proximity calculations will be done at regular intervals depending on P-1-M-6120 the risk of collision but, at least twice daily while drilling.
5.8-5
6.10.2.
Proximity calculations and projections are to be performed on each P-1-M-6120 survey
5.8-8
6.10.3.
Unless required for directional control, the use of drilling motors will P-1-M-6120 be avoided while drilling in this situation. If motor use is unavoidable then a low torque motor will be the preferred option
5.8-15
6.10.4.
Whenever possible use PDC bits instead of tricone bits
P-1-M-6120
5.8-16
• • • •
The slot allocations will account for final target displacement and direction. Higher displacement wells will be drilled from the outer slots whenever possible. The kick-off points of wells will be spaced vertically depending on final target displacement. Larger displacement wells will be kicked off at shallower depths whenever possible. If crossing of trajectories is unavoidable, the tangent section on both 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.
7. BHA ANALYSIS 7.1. Bottom hole assembly response
Reference
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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REVISION
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Reference
8. REPORTING 8.1. Survey 8.1.1.
Surveys of all wells will be filed in printed copy and in electronic P-1-M-6120 format.
6.1.1
Data must be available on floppy disks (two copies) formatted according to Eni-Agip specification. Write protected form is suggested. 8.1.2.
SDE will be responsible for the correct archival and retention of P-1-M-6120 survey files and final report.
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 directional contractor.
8.2.1.
Contents of final report.
P-1-M-6120
6.5
8.3.
Contractors evaluation.
8.3.1.
Planning requirements:
P-1-M-6120
3.4.1
Minimum required software capabilities.
Reference List: ‘Directional Control & Surveying Procedures Manual’
STAP-P-1-M-6120
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘Operating Procedure for Drawing the ‘Well Drilling Programme’’
STAP-P-1-N-6001E
‘Operative procedure for Preparing the ‘Geological and Drilling Well Programme’’
STAP-P-2-N-6001E
Software: 3-D
IWIS (ADIS)
Compass
SECTION 1 OF BP&MR - PLANNING (PL)
30
MSS MWD
150 30
MSS MWD
150 30
7” CSG
MSS MWD
150 30 150
5” Liner
MSS MSS/MWD
As required
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
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REVISION
Note: 1. Records after casing set may be omitted if it is not dictated by local condition, legislation, the well is clear of other 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 suppose the well vertical and the others survey records should be omitted.
PAGE
HDT/MMS
GMS/SRG NSG/GCT
IDENTIFICATION CODE
13”3/8 intermediate CSG 9”5/8 CSG
MWD
Individual Wells While Drilling After Casing set Type of Frequency Type of Frequency instrument instrument MSS At shoe Tocto MWD 150M (and each trip) MSS MWD 150M (and each trip) MSS MWD 150M (and each trip) MSS MWD 150M (and each trip) MSS MWD 150M (and each trip) MSS
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20”-13”3/8 Surface CSG
Vertical Wells
STAP-P-1-M-6090
SECTION 1 OF BP&MR - PLANNING (PL)
Table PL 2.3 - Frequency and Types of Surveys for Vertical Wells
30” C.P.
Platform/Cluster Template Wells While Drilling After Casing set Type of Frequency Type of Frequency instrument instrument Tocto Bottom (template) GMS/SRG 30m
ENI S.p.A. Agip Division
FREQUENCY AND TYPE OF SURVEYS
7” CSG
5” Liner
30
MSS MWD
150 30
MSS MWD
150 30
MSS MWD
150 30
MSS MSS/MWD
150 As required
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
GMS/SRG NSG/GCT
30m
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Note: 1. Records after casing set may be omitted if it is not dictated by local condition, legislation, the well is clear of other 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 equivalent
PAGE
HDT/MMS
GMS/SRG NSG/GCT
IDENTIFICATION CODE
13”3/8 intermediate CSG 9”5/8 CSG
MWD
Individual Wells While Drilling After Casing set Type of Frequency Type of Frequency instrument instrument MSS At shoe GMS/SRG 30m Tocto MWD GMS/SRG 30m 150M (and each trip) MSS MWD GMS/SRG 30m 150M (and each trip) MSS MWD 150M GMS/SRG 30m (and each trip) MSS MWD 150M GMS/SRG 30m (and each trip) MSS MWD 150M (and each trip) MSS
ARPO
20”-13”3/8 Surface CSG
Deviated wells
STAP-P-1-M-6090
SECTION 1 OF BP&MR - PLANNING (PL)
Table PL 2.4 - Frequency and Types of Surveys for Deviated Wells
30” C.P.
Platform/Cluster Template Wells While Drilling After Casing set Type of Frequency Type of Frequency instrument instrument Tocto Bottom GMS/SRG 30m
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FREQUENCY AND TYPE OF SURVEYS
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Figure PL 2.1 - Anti-Collision Responsibilities (when there is Interference Between Existing Completed/Productive Wells and New Wells)
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Figure PL 2.2 - Anti-Collision Responsibilities (when there is Interference Between Existing Non Completed/Plugged & Abandoned Wells and New Wells)
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REVISION
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Figure PL 2.3 - Anti-Collision during Well Suspension
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REVISION
STAP-P-1-M-6090 PL. 2.10. CASING DESIGN 1. CASING SETTING DEPTH AND FUNCTIONS OF CASING STRINGS Determine proper setting depth for each casing type. 1.1. 1.2.
Define the purpose of each casing string.
1.3.
Safety requirements.
2. CASING AND HOLE SIZES 2.1. Define each casing diameter according to hole sizes. 2.1.1.
• •
2.2.
Exploration well
2.2.1.
The 6” hole should be planned as contingency
2.2.2.
Evaluate hole size-casing clearance.
2.2.3.
Avoid all the problems connected with too large/small clearance.
2.2.4.
Size of tubing & completion equipment.
Casing selection chart. 30” x 1” conductor pipe is assumed as standard.
3. CASING DESIGN CRITERIA AND DESIGN FACTORS 3.1. Guidelines
Reference
PL.02.08
Reference
P-1-M-6110
3.6
P-1-M-6110
3.6
P-1-M-6110
3.6
Reference
3.1.1.
Casing design is actually a stress analysis procedure. The objective is P-1-M-6110 to produce a pressure vessel which can withstand a variety of external, internal, thermal, and self weight loading, while at the same time being subjected to wear and corrosion.
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 fracturing P-1-M-6110 operations may be necessary, the fracture pressure at perforation depth and at the wellhead pressure minus the hydrostatic head in the 2 casing plus a safety margin of 70kg/cm (1,000psi), will be assumed.
3.3.
Max acting collapse pressure
3.3.1.
Refer to Table PL 2.6
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8.1.2
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Biaxial stress:
3.3.2.
P-1-M-6110
8.4.1
Total tension load affects burst and collapse resistance of the casing, (effects of axial stress on burst resistance are considered negligible). 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 pressure P-1-M-6110 exerted by salt on the casing equal to overburden pressure.
3.4.
Total TENSION load
3.4.1.
Total tension load is given by adding to the weight of casing in air:
8.7.3
(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 effect .
P-1-M-6110
8.5.2
3.4.4.
Tension load due to bump plug after displacing cement does not P-1-M-6110 affect biaxial stress evaluation.
5
8.3.3-3
Take in to account eventual pressurisation about both opening /closing DV operations and setting ECP. 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 tests .
P-1-M-6110
11.3
6
The worst situation assumes the casing totally free to move. 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’.
P-1-M-6110
11.1
It is normal to consider an overpull contingency of 100000lbs.
5
6
= 15,52 α OD Af ;
TB : additional tension [kg] OD : outside diameter [in] 2 α : build-up/drop-off rate [deg/30m] Af : cross section area [cm ] α TB : [lb] OD : [in] TB = 218 OD Af ; 2 α : [deg/100ft] Af : [in ] 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.
B
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3.5.
Required & actual design factors
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 4.1. Casing wear
Reference
4.1.1.
Reduction in collapse resistance due to wear will be critical at shallow P-1-M-6110 depths, the reduction in burst resistance will be critical at the lower end of the casing string.
4.1.2.
Eni-Agip design procedure.
8.6
P-1-M-6110
8.6.8
4.1.3.
The percentage casing wear at each point along the casing is then P-1-M-6110 calculated from the volumetric wear. Eni-Agip acceptable casing wear limit is 30psi - usually indicates corrosion. Partial pressure 3 – 30psi - may indicate corrosion. Partial pressure < 3psi - no corrosion.
Hydrogen sulphide (H2S): The combination of H2S with CO2 is more aggressive than H2S and is frequently found in oilfield environments. Attack due to presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion.
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4.2.3.
Factors affecting corrosion rates: • • • •
Acceptable casing for ‘sour’ service Vs operating temperature.
4.2.5.
Eni-Agip design procedure.
4.2.5.1.
CO2 corrosion:
4.2.5.2.
•
P-1-M-6110
Table 9.B
P-1-M-6110
9.8.1
P-1-M-6110
9.8.2
Exploration wells - no influence on material selection. Producing wells - selection of high alloy chromium steels resistant to corrosion, inhibitor injection.
H2S environment: •
9.1.3
Temperature Pressure pH Fluids velocity.
4.2.4.
• •
P-1-M-6110
Exploration wells: with high probability of encountering H2S, it should be considered to limit casing yield strength according to API-5CT and NACE standard MR-01-75. Producing wells: casing and tubing material will be selected according to the amount of H2S and other corrosive media present.
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:
P-1-M-6110
10.2
Use high ductility steel to prevent brittle failures during transport and handling.
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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 casing P-1-M-6110 string, if (after the cement has set): • • • •
4.4.1.2.
Internal pressure increases. Annular fluid density reduction. Casing is landed with less than full hanging weight. Temperature increases.
Buckling of long uncemented portions of the casing string (in vertical P-1-M-6110 wells), can be prevented by: • • •
11.4.1
11.4.1
Cementing the casing up to the neutral point. Pre-tensioning the casing on landing. Rigidly centralising the casing below the neutral point.
4.4.2.
Compression
4.4.2.1.
Wells with the wellhead at ground level or sea bed.
P-1-M-6110
11.4.2
P-1-M-6110
11.4.2
P-1-M-6110 P-1-M-6140
11.4.1 15.5
The surface casing must be cemented to surface / seabed. 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.
4.4.2.3.
Wells with mudline suspension. The weight of the casing is taken at the seabed, but the wellhead is above seabed. The C.P. must be cemented to seabed. The tieback strings may be subject to buckling, a full structural analysis should be carried out (commissioned).
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Reference 5. DRILLING PROGRAMME CONTENTS 6.3.4 If the procedures for calculating casing stress are not directly based P-1-M-6001E 5.1. on the corporate ‘Casing Design Manual’, reasons must be given in an introductory sub-paragraph.
The present paragraph shall include: 1. 2.
3.
Stress diagrams, with relative reports. 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) Hang-off load (if applicable)
5.2.
Design operational programme for casing running.
5.2.1.
Recommended casing running speed to optimise surge pressure due A-1-M-1000 to pipe motion.
5.2.2.
Tension load applied on casing string while is landed on the casing spool.
5.2.3.
Always, check maximum planned pull against rig capacity, also according to cantilever position.
4
Reference List: ‘Casing Design Manual’
STAP-P-1-M-6110
‘Operating Procedures for Drawing the ‘Well Drilling Programme’’
STAP-P-1-N-6001E
‘Drilling Procedures Manual’
STAP-P-1-M-6140
Software: CASCADE-IWIS (ADIS)
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BURST PRESSURE (IP-EP) Internal Pressure Wellhead Bottom-hole fracture Working pressure rating of Predicted SURFACE BOP equipment7 or wellhead gradient below the CASING P-1-M-6110-8.1.2 but with 2 a minimum of casing shoe. 140Kg/cm
INTERMEDIATE Surface wellheads: CASING 60% of difference between P-1-M-6110-8.1.2 fracture pressure at casing shoe and gas column pressure to the wellhead. Subsea wellheads: as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to the wellhead minus the seawater pressure. limit = PRODUCTION Wellhead burst difference between the pore CASING P-1-M-6110-8.1.2 pressure of the reservoir fluid and the hydrostatic pressure produced by a column of fluid 9 Stimulation or hydraulic fracturing operations.
Fracture pressure at perforations depth minus hydrostatic pressure plus safety margin of 1000 psi. 1.05 1.10 DESIGN FACTOR P-1-M-6110-7.2.1 1.20
External Pressure
Surface wellhead: = hydrostatic pressure of a column of drilling mud. Subsea wellhead: = Water Depth x Seawater Density x 0.1 (if atm) seawater (1,03 3 kg/dm ).8 Predicted fracture Formation pressure gradient of formation With a subsea below the casing shoe. wellhead, at the wellhead, hydrostatic seawater pressure should be considered.
Wellhead pressure burst limit plus annulus hydrostatic pressure exerted by the completion fluid.
Formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered
Fracture pressure at perforations depth.
H40 - J55 - K55 C75 - L80 - N80 - C90 Casing grade - C95 - P110 Q125
Table PL 2.5 - Burst Pressure When testing or producing through a liner, the casing above the liner will be a part of the production string and must be designed according to this.
7 8
If an oversize BOP is selected: (IP)wellhead=60% [(fracture pressure at casing shoe)-(hydrostatic pressure of gas column to 3 surface)]; methane gas with density of 0,3 kg/dm is normally used. At shoe =(Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm) 3 Usually gas (density = 0.3kg/dm ). 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 Pressure SURFACE CASING P-1-M-6110-8.2.1
INTERMEDIATE CASING P-1-M-6110-8.2.1
PRODUCTION CASING P-1-M-6110-8.2.1 DESIGN FACTOR P-1-M-6110-7.2.1
The casing for onshore operation is considered completely empty. In offshore wells with subsea wellheads, the internal pressure assumes that the mud level drops due to a thief zone
Surface wellhead: External pressure equal to the hydrostatic pressure of a column of drilling mud. Subsea wellhead: At the wellhead - Water Depth x Seawater Density x 0.1 (if atm). At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm). Hydrostatic pressure of mud in which casing is run. The uniform external pressure exerted by salt on the casing or cement sheath through overburden pressure, should be given a value equal to the true vertical depth of the relative point.
The mud level inside the casing dropping to an equilibrium level where the mud hydrostatic equals the pore pressure of the thief zone When thief zones cannot be confirmed assume the casing to be half-empty and the remaining part of casing full of heaviest mud scheduled to drill the section below the shoe. The casing string is considered Hydrostatic pressure of mud in which completely empty. casing is run.
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 the production string and must be designed according to this.
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TENSION (P1M6110-8.3)
1. Calculate casing string weight in air
2. Calculate casing string weight in mud
3. Add additional load due to bumping the plug
4. Deviated wells : "bending effect"
DESIGN FACTOR
1.70
• C95
P1M6110-7.2.1
1.80
> C95
Table PL 2.7 – Tension
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REVISION
STAP-P-1-M-6090 PL. 2.11. DRILLING FLUIDS PROGRAMME Reference 1. GENERAL The mud programme is drawn up for each phase on the basis of the P-1-N-6001E 1.1. following aspects:
• • • •
• •
Geological information about chemical, physical and natural characteristics of the expected lithology sequence and depths. Drilling site: specify on-shore and offshore characteristics. Environmental aspects: concerning waste disposal procedures in compliance with local, current legislation. Drilling programme: resuming the expected pressure gradients, casing profiles, deviation design, hydraulic programme, time Vs depth diagram, drilling difficulties and rig equipment. Minimum stock of mud products at the rigsite and at base Required fluids volumes
1.2.
The mud programme shall be submitted to the Company Drilling P-1-M-6100 Office for approval before to integrate into the Drilling Programme.
5.1
1.3.
No variation from the mud programme is permitted without previous P-1-M-6100 discussion with and approval of the Company Shore Base Drilling office.
5.1
1.4.
The hydrostatic pressure applied by the mud must be greater than the P-1-M-6100 highest formation pressures to effect pressure control.
5.2.2
2. PRELIMINARY INFORMATION Pore pressure profile. 2.1.
Reference 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 Drilling fluid type in each hole section. 3.1. 3.2.
Mud weight in each hole section [kg/l].
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Reference
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STAP-P-1-M-6090
3.3.
Chemical & physical properties.
3.3.1.
Funnel viscosity
[seconds/lt.].
3.3.2.
Plastic viscosity
[centipoise], [centipoise @ ....°C], for OBM.ó
3.3.3.
Yield point
[g/100cm ].
3.3.4.
Gel strengths / 0-10”-10’ OBM.
[g/100cm ],[g/100 cm @ ... °C], for
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
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)
2
2
2
3
[kg/m ].
.
[H2SO4 N/10].
4. SURFACE EQUIPMENT FOR TREATING & HANDLING MUD 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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Reference
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STAP-P-1-M-6090
5. CONTINGENCY PLANS FOR POTENTIAL HOLE PROBLEMS 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. Reference
6. SAFETY REQUIREMENTS Minimum stocks. 6.1. 6.2.
Reference
Special safety actions.
Reference List: ‘Drilling Fluids Operation Manual’
STAP-P-1-M-6160
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Operating Procedure for Drawing the ‘Well Drilling Programme’’
STAP-P-1-N-6001E
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REVISION
STAP-P-1-M-6090 PL. 2.12. HYDRAULIC PROGRAMME Reference 1. SOFT WARE 6 The Eni-Agip IWIS (ADIS) software programme is currently used for P-1-M-6100 1.1. all hydraulic programmes and provides all the necessary information to be input into the ‘Geological Drilling Programme. Reference
2. FLOW REGIME DEFINITION 10 2.1. Optimum flow rate evaluation in each hole section 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
Reference
3. FRICTION PRESSURE LOSSES CALCULATION 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 tripping speed.
10
Common flow rate:
hole size [ins]
17 /2”
1
15
12 /4”
1
9 /8”
7
8 /2”
1
7 /8”
6 /4”
6
flow rate [l/min]
3000÷4000
2800÷3500
2200÷2600
1500÷1900
1200÷1600
1200÷1600
800÷1000
600÷800
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3
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REVISION
STAP-P-1-M-6090 4. BIT NOZZLES SELECTION Optimise jet-impact force. 4.1. 4.2.
Maximise hydraulic bit horsepower.
4.2.1.
1.
Evaluate suitable pump rate & max operating pressure (check P-1-M-6100 pressure rating of all surface equipment). Calculate the friction pressure loss in surface equipment, pipe & annulus. Calculate the amount of pressure available for friction pressure drop across the bit; Solve the bit pressure drop equation for the flow area.
6.4.4
Eni-Agip design criteria assume (rotary drilling using roller cone bits): P-1-M-6100
6.4.4
2. 3. 4. 4.2.2.
Reference
• • • • •
Max available pump pressure equal to 90% of nominal pump pressure. Min nozzle velocity 100 m/s. 1 2 Hole section Ø 8 /2” → HSI=8 ÷ 9 (HHP/in ). 1 2 Hole section Ø 12 /4” → HSI=5 ÷ 6 (HHP/in ). 1 2 Hole section Ø 17 /2” (16”) → HSI=3 ÷ 4 (HHP/in ).
Reference 5. DRILLING PROGRAMME CONTENTS For each hole section & depth interval, the drilling programme should P-1-N-6001E 5.1. contain the following information:
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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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 & bit nozzles.
5.1.5.2.
Hydraulic power. Total & bit, including: • •
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STAP-P-1-M-6090
5.1.2.6.
PAGE
Percentage of bit hydraulic power on total hydraulic power. 2 Bit hydraulic power/ins (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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REVISION
STAP-P-1-M-6090 PL. 2.13. WELLHEAD Reference 1. GENERAL SERVICE CONDITION (NO SOUR SERVICE) ONSHORE, OFFSHORE JACK-UP & FIXED PLATFORMS WELLHEAD SYSTEM 2.3 The standard for exploration and development well are “Multibowl M-1-M-5020 1.1. Wellhead” (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. 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 P-1-M-6100 M-1-SS-5701E
1.3.
Pressure Rating
1.3.1.
Definition of Working Pressure for Unitised Wellhead Housing is M-1-M-5020 based on following criteria:
2.1.1 8.2 1.1
2.1.2
WP= Static Bottom Hole Pressure (SBHP) or WP= Max Static Tubing Head Pressure x S.F. (STHP x Safety Factor) For gas wells S.F. = 1.1 For oil wells S.F. = 1.3 (recommended) 1.3.2.
Pressure rating definition, for spool of a Flanged Wellhead, is based M-1-M-5020 on maximum anticipated surface pressure.
Reference
2. MATERIAL 2.1. General Service 2.1.1.
Casing Head & casing spool: • •
2.1.2
Temperature Classification Class P (-29°C/+82°C) - as per API 6A Material Class DD - Sour Service - as per API 6A as defined by NACE MR-01-75
2.2.
Sour Service
2.2.1.
To be defined according to the specific service condition.
SECTION 1 OF BP&MR - PLANNING (PL)
M-1-M-5020 P-1-M-6100
2.2.1 8.2.1
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STAP-P-1-M-6090
Reference
3. UNITISED WELLHEAD (COMPACT) 3.1. Unitised wellhead components 3.1.1.
Wellhead Housing (with lateral flanged outlet for control line): Diam e WP
Bottom
Casing Hanger
slip lock 13 /8“ or pup joint 10’ welded/on
5
slip lock 13 /8“ or pup joint 10’ welded/on
3
slip lock 18 /8“ Suitable to install Hub profile or pup joint 10’ 5 a 13 /8” Housing welded/on
13 /8” 10,000psi
18 /4” 5.000 psi (option depend on csg programme)
5
9 /8”-7”-tbg
3
9 /8”-7”-tbg
Hub profile
5
Hub profile
5
Reference
4. FLANGED WELLHEAD 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
3
26 /4”
3,000psi
24 /2”
1.2
1
21 /4”
5,000psi
20” & 18 /8”
1.3
13 /8”
5
5,000psi
13 /8” & 9 /8”
4.1.2.
Casing head spool
4.1.2.1.
Ref. No.
Bottom flange
2.1
13 /8”
5
5,000 psi
13 /8”
2.2
13 /8”
5
5,000 psi
2.3
5
13 /8”
2.4
1
21 /4”
5,000 psi
13 /8”
2.5
21 /4”
1
5,000 psi
13 /8”
2.6
3
3,000 psi
26 /4”
2.3.1
Top
5
13 /8” 5,000psi
3
M-1-M-5020
Max WP
10,000 psi
Top flange
3
M-1-M-5020
2.3.2
M-1-SS-5701E (TABLES 5-6-7)
1.2.2
5
Max WP 5,000 psi
13 /8”
5
10,000 psi
5
10,000 psi
5
5,000 psi
5
10,000 psi
1
5,000 psi
21 /4”
2.3.2
5
5
13 /8”
M-1-M-5020
1
4.1.3.
Other wellhead components.
4.1.3.1.
Outlets for casing head/spool (flanged system) and housing (unitised system). 1
The standard are two outlets studded 2 /16”, threaded for VR plug with the same WP of the casing spool or of the housing.
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STAP-P-1-M-6090
4.1.3.2.
Cutting operation on c.p. or on casing will be done with mechanical device.
4.1.3.3.
Sealing material: environments.
4.1.3.4.
Painting:
4.1.3.5.
Standardised completion equipment including sequences of casing M-1-SS-5701E (FIG.1-10) head / spool is reported in Table PL 2.8
4.1.3.6.
Abbreviations used in Table PL 2.8 • • • •
4.1.4.
MSCL DCSFSL SCSO DCSO
Elastomer
selected
according
to
well
Suitable for offshore environment.
M-1-SS-5701E
1.2.1
1.5
modular single completion land dual completion seal flange solid block land single completion seal flange offshore dual completion solid block offshore
Eni-Agip standards give a minimum tubing spool bottom flange Ø=13”5/8. Reference
5. MATERIAL REQUIREMENTS General service: 5.1.
P-1-M-6100
8.2.1
M-1-SS-5701E
1.5
M-1-SS-5701E
1.5
Operating context: (NACE MR-01-75) • • • 5.2.
–29 - 82 °C < 7psia < 0,05psia.
Chemical composition: • •
5.3.
Range of operating temperature: Partial pressure of carbon dioxide: Hydrogen sulphide partial pressure:
Casing head: AISI 4130 AISI 4125 Casing spool: AISI 4140 AISI 4135
Sour service: Metallic material specification • •
5.4.
Chemical composition Hardness: HRC < 22
Marine Environment: Protection from marine environment: use coating suitable for salt spray fog.
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REVISION
STAP-P-1-M-6090
6. PRESSURE TESTS Hydraulic oil must be used. 6.1.
Reference P-1-M-6140
15.2.3
P-1-M-6140
15.2.3
6.2.
Pressure test value doesn’t exceed 70% casing collapse resistance.
6.3.
During primary & secondary packing group’s test, previous casing P-1-M-6140 spool valve must be kept open.
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
7. DRILLING PROGRAMME CONTENTS Includes the following, minimum information:
Reference P-1-N-6001E
6.3.8
• 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 Reference 8. UNCONVENTIONAL WELLHEAD SYSTEM 8.5 Mudline casing suspension system: The system makes possible the P-1-M-6100 8.1.1. temporary abandonment of the well in a short time and without casing cutting. Reference
9. SUBSEA WELLHEAD SYSTEM Functional requirements 9.1.
M-1-SS-5708
4
Engineering requirements
M-1-SS-5708
5
9.2.
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘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
SECTION 1 OF BP&MR - PLANNING (PL)
1.2
1.2
1.2
1.2
1.2
DCSFSL 3
SCSO 1
DCSO 1
DCSO 2
DCSO3
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
2.1 2.4
5000 13 3/8 & 9 5/8
20 & 18 5/8
SECTION 1 OF BP&MR - PLANNING (PL)
3000
5000
5000
5000
5000
5000
5000
5000
5000
24 1/2
20 & 18 5/8
20 & 18 5/8
20 & 18 5/8
20 & 18 5/8
20 & 18 5/8
20 & 18 5/8
2.6
2.5
2.4
2.4
2.4
2.4
2.4
2.4
2.1
5000 13 3/8 & 9 5/8
20 & 18 5/8
2.1
13 3/8 & 9 5/8
5000
26 3/4
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
21 1/4
13 5/8
13 5/8
13 5/8
3000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
Max. W.P. (psi)
21 1/4
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
Top flange (in)
CASING HEAD SPOOL Btm Flange (in)
5000
10000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
Max. W.P. (psi)
2.5
2.3
2.2
2.2
2.1
2.1
2.1
2.2
2.1
Ref. nr
21 1/4
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
5000
10000
5000
5000
5000
5000
5000
5000
5000
Max. W.P. (psi)
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
Top flange (in)
CASING HEAD SPOOL Btm flange (in)
10000
10000
10000
10000
5000
5000
5000
10000
5000
Max. W.P. (psi)
2.3
5.2
5.5
5.4
5.4
5.3
5.2
5.1
5.1
5.1
5.1
Ref. nr
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
13 5/8
Btm Flange (in)
9
7 1/16
7 1/16
7 1/16
11
9
9
9
9
9
Top flange (in)
10000
10000
5000
5000
5000
10000
5000
5000
5000
5000
Max. W.P. (psi)
10000
13 5/8
10000
3° CASING HEAD SPOOL
10000
10000
5000
5000
5000
10000
5000
5000
5000
5000
Max. W.P. (psi)
TUBING SPOOL
6.8
6.7
6.9
6.4
6.5
6.8
6.6
6.3
6.2
6.1
Ref. nr
5000 10000
7 1/16 7 1/16
10000
5000
7 1/16
9
5000
2 x 2 3/8
2 x 2 3/8
2 x 2 3/8
3 1/2
2 x 3 1/2
2 x 2 3/8
2 x 2 3/8
5000 10000
5
3 1/2
2 7/8
Diam tbg (in)
5000
5000
5000
11
9
9
9
9
9
Max. W.P. (psi)
TUBING HANGER Diam (in)
IDENTIFICATION CODE PAGE
(*) Typical wellhead configuration for deep wells (po Valley)
26 3/4
1.2
DCSFSL 2
21 1/4
1.1
1.2
DCSFSL 1
13 5/8
21 1/4
1.3
MSCL 3
13 5/8
1.2
1.3
MSCL 2
13 5/8
Ref. nr
Btm (CSG) (in)
Max. W.P. (psi)
CASING HEAD
Top flange (in)
ENI S.p.A. Agip Division
(*)
1.3
Ref.nr
MSCL 1
AGIP CODE
Typical outlines for on-shore, off-shore single and dual completion class -A and class -B (STAP -M-1-SS-5701E)
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Table PL 2.8 - Typical Outlines for single and duel completions class A and B
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PL. 2.14. WELL CONTROL Reference
1. BOP SELECTION CRITERIA 1.1. Pressure rating 1.1.1.
The working pressure of any blow-out preventer shall exceed the P-1-M-6110 maximum anticipated surface pressure to which it may be subjected
1.2.
Eni-Agip BOP-selection criteria
1.2.1.
The maximum theoretical pressure at the casing head occurs when P-1-M-6110 the well is full of gas and the fracture pressure has been reached at the weakest point (generally the last casing shoe).
1.2.2.
Production test operations: see point 1.2.1
1.2.3.
Drilling operations: 60% of maximum theoretical head pressure has P-1-M-6110 been chosen as limit value.
12.1
1.2.4.
A first approximate determination of BOP size for a wildcat well is P-1-M-6110 given in the graph reported on the Casing design manual, both for P-1-M-6100 drilling operations and production tests. The anticipated casing setting depths and pore pressure values are the required information.
12.1 9.1
2. EQUIPMENT REQUIREMENTS 2.1. Minimum BOP stack requirements 2.1.1.
Land rigs, Jack-up / Fixed platforms: • • •
12.1
12.1
Reference
P-1-M-6150
6.1.1
5,000psi WP stack should have at least 2 ram type preventer (1 blind or shear ram type and 1 pipe ram type) and 1 bag preventer 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 bag preventer 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 bag preventer
2.1.2.
Land rigs: the shear rams installation will be evaluate with reference M-1-M-5005 to local law or deduced by ‘risk analysis’ computations.
1.1
2.1.3.
The pipe rams preventers shall be equipped, at all times, with the P-1-M-6150 correct sized rams to match string in use.
6.1.1-b
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REVISION
STAP-P-1-M-6090
2.1.4.
P-1-M-6150
Floating drilling rigs:
6.1.2
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 (one annular 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 retrievable on Lower Marine Riser Package.) 2.2.
Diverter general requirements
2.2.1.
• • •
The diverter must be equipped with two lines facing opposite P-1-M-6150 directions (offshore applications). Minimum diverter outlets 12” ID Diverter valves shall be full opening valves, preferably ball valves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden.
2.3.
Choke / kill lines & manifold
2.3.1.
Choke / kill lines, choke manifold shall have a working pressure rating P-1-M-6150 equal or greater than preventers in use.
2.3.2.
Minimum diameter: • •
Inside pipe shut-off devices
2.4.1.
While drilling shallow holes a float valve is used.
2.4.2.
Blowout equipment available on drill floor:
•
P-1-M-6150
6.1.1-g
P-1-M-6150 P-1-M-6140 M-1-M-5012 P-1-M-6150
9.3.1-e 4.1.5-1 2.5 6.4-b-d-e
Additional lower kelly cock, kept in open position at all time. Gray type inside BOP, with appropriate connection for pipe in use. Drop-in type back pressure valve.
3. BOP & CASING TESTS 3.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests 3.1.1.
6.3-a
Choke line diameter 3” ID Kill line diameter 2” ID
2.4.
• •
6.6-b-e-g
Reference
All BOP stacks will be pressure tested at their rated working pressure, P-1-M-6150 prior to use, on test stumps.
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3.2.
Floating Rig BOP Surface Test
3.2.1.
The complete BOP stack assembly shall be tested at the surface on P-1-M-6150 test stumps: • •
7.3
At low pressure of 300psi (21kg/cm2). At their rated working pressure
3.3.
Ram type preventer tests after installation on the wellhead
3.3.1.
Pipe rams shall be tested with open-end cup testers to a low pressure P-1-M-6150 2 of 300psi (21kg/cm ) and to a high pressure at least equal to the maximum anticipated wellhead pressure.
7.2.2
3.3.2.
In all cases, the maximum test pressure for each BOP test will not P-1-M-6150 exceed 70% of the rated WP of the lowest rated item of equipment in the wellhead assembly, casing or preventer stack assembly, whichever is the lower.
7.2.2
3.3.3.
•
7.2.3
•
An open-end cup tester is required or a blind test plug may be P-1-M-6150 always used for BOP testing before or after the shoe is drilled out. Tests will be carried out with water.
3.3.4.
The accumulator system should be capable of closing each ram BOP P-1-M-6150 within 30 sec
3.4.
Bag type annular preventer tests
3.4.1.
The preventer will be tested to low pressure (300 psi), and to a high P-1-M-6150 pressure at least equal to the maximum anticipated wellhead pressure.
7.2.2
3.4.2.
Closing time on 5” DP should not exceed 30secs for annular P-1-M-6150 3 preventers smaller than 18 /4” nominal bore and 45secs for annular 3 preventers of 18 /4” and larger
6.2.1-a
3.5.
Blind/Shear ram type preventer tests after installation on the wellhead
3.5.1.
Blind/shear rams shall be tested using blind plug testers to the same P-1-M-6150 pressure as stated above for pipe rams.
7.2.2
3.5.2.
Where a plug tester is not available, blind/shear rams will be tested P-1-M-6150 against 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 be 2 succeed 1,500psi (105kg/cm ).
7.2.2
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3.6.
Floating BOP Test During and After Installation
3.6.1.
While running BOP stacks on the riser joints, the choke/kill and P-1-M-6150 buster lines from surface to the fail-safe shall be pressure tested to their rated working pressure.
7.3.1-1
3.6.2.
After the BOP stack is landed on the wellhead, a full function test on P-1-M-6150 both pods shall be carried out.
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, P-1-M-6150 equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.
7.3.2-1
3.7.2.
All BOP components, shall be pressure tested to a low pressure of P-1-M-6150 2 300psi (21kg/cm ) 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.
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 associated P-1-M-6150 P-1-M-6150 equipment shall also be tested, with water.
7.4.4-c 7.5
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 pressure applied for the BOP test. 3.9.
Casing tests
3.9.1.
In all cases the test pressure will be no higher than 70% of API P-1-M-6150 minimum internal yield pressure of the weakest casing in the string or to 70% of the BOP working pressure.
3.10.
BOP operating equipment
3.10.1.
All BOP operating equipment hoses, control panels, regulator P-1-M-6150 connections, shall be regularly checked and tested to the maximum manufacturers recommended values for closing and opening BOP.
3.11.
Diverter tests
3.11.1.
They mainly consist on function test and closing time evaluation. P-1-M-6150 Closing time (on 5” DP): • •
30 seconds : diverter type • < 20” 45 seconds : diverter type • • 20”
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Reference
4. TESTS FREQUENCY 4.1. BOP-stack 4.1.1.
• • • • •
4.2.
Kill/choke lines, choke manifold, rig floor and cementing manifold
4.2.1.
Every time tests are carried out on the BOP stack, the associated P-1-M-6150 equipment shall also be tested, with water (see point 4.1.1).:
4.3.
Casing
4.3.1.
Each casing shall be pressure tested at the following times:
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
7.4.4
P-1-M-6150
7.5
4.3.2.
A cemented liner overlap will be positively tested applying a pressure P-1-M-6150 greater than the lea-off pressure of the previous casing. If there is any doubt, an inflow test could be carried out, with a sufficient drawdown to test the liner top to the most severe negative differential pressure that will exist during the life of the well.
7.6
4.4.
BOP operating equipment
4.4.1.
Every time BOP stack is nippled up, and after repairing operations.
4.5.
Function tests
4.5.1.
1.
• • •
2. 3.
When cement plug bumps on bottom with a pressure stated in the drilling programme. When testing blind/shear rams of the BOP stack against the casing. After having drilled out a DV collar.
P-1-M-6150
The pipe ram and BOP valves should be operated at least once P-1-M-6150 every shift. Blind/shear rams shall be operated every round trip in the hole. The annular preventer shall be operated when the scheduled routine BOP tests are performed.
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Reference 5. DURATION OF TESTS 7.4.1 The BOP 300psi low-pressure tests will be performed first. They are P-1-M-6150 5.1. to be held for a min period of 5min
5.2.
High-pressure tests are held for a minimum of 10mins. The maximum P-1-M-6150 acceptable pressure drop over this 10mins period is 100psi.
7.4.1
Reference
6. WELL CONTROL DRILLS 6.1. Familiarity drills 6.1.1.
The purpose of these drills is to familiarise rig personnel with the P-1-M-6150 various equipment and with the techniques that will be employed in the event of a kick.
7.1.1.b
6.1.2.
These tests shall be carried out on an each shift basis, at the P-1-M-6150 beginning of any new activity, any time experienced personnel are replaced with new recruits, especially when key position 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.
8.6.1
6.2.
Emergency “On-the-rig” drills
6.2.1.
Simulate potential blowout situation. Drilling Contractor’s crew should P-1-M-6150 follow the close-in procedure according to the current operations (bit on bottom, tripping).
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 crew P-1-M-6150 should follow the close-in procedure according to the current operations (bit on bottom, tripping).
8.3.1
6.3.2.
Tests shall be carried out:
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 at P-1-M-6150 intermediate casing string
8.6.1
• •
Each shift basis every fortnight. When the well is nearing or entering high-pressure zones.
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6.5.
Drills evaluation
6.5.1.
Drills evaluation is mainly based on performing time. Correct timing P-1-M-6150 should be defined in Drilling Contractor’s procedures according to the equipment.
8.6.2
6.5.2.
Pit drills:
P-1-M-6150
8.6.2
P-1-M-6150
8.6.2
Not more than 2.5 minutes from a readable change in drilling fluid volume to the time the well is closed-in or drill pipe started running back in hole if during trip. 6.5.3.
‘On-the-rig’ drills : One minute time from giving the alarm signal to have the preventer closed.
Reference
7. PRIMARY WELL CONTROL 7.1. General remarks 7.1.1.
Underbalance drilling operations, which are not admitted on wildcat P-1-M-6150 wells, shall be approved by Company Operative Base Drilling Superintendent through a detailed drilling programme.
2.1.1
7.1.2.
Primary well control is mainly based on prediction of formation P-1-M-6150 pressure. It depends on correct mud weight evaluation and proper operating practices.
2.1.1
7.2.
Trip margin & equivalent mud weight
7.2.1.
If while tripping out a swabbing is noted (the well is not flowing): • • • •
P-1-M-6150
2.2.3
Stop the trip Run back to bottom Circulate bottom up Resume tripping carefully.
7.3.
Mud volume control
7.3.1.
3 A minimum kill mud volume of 70m at 1.4kg/ft shall be stocked while P-1-M-6140 drilling surface hole without BOP-stack. Anyway, at least minimum P-1-M-6150 mud volume must be equal to three times internal drillstring volume.
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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 depends P-1-M-6150 on the following factors: • • • •
2.1.4
Last casing shoe depth mud weight Minimum formation fracture gradient below the casing shoe minimum last casing burst pressure resistance.
7.5.
Circulating pressure at reduced pumping rate
7.5.1.
Reduced pump stroke pressure (RPSP).
P-1-M-6150
2.1.5
7.5.2.
On floater rigs, the RPSP shall be measured by circulating, first P-1-M-6150 through the riser and then through the choke/kill line.
2.1.5
7.6.
Drilling break
7.6.1.
Any time a drilling break is noticed:
1
Normal circulation flowrate reduced to Q/3 in 12 /4” hole and Q/2 in 1 8 /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 mud properties. 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
2.1.3
Drilling shall be stopped immediately Static control shall be carried out.
8. SECONDARY WELL CONTROL Well control decision tree 8.1.
Reference
8.2.
Well shut-in procedures
P-1-M-6150
3
8.3.
Killing procedures
P-1-M-6150
5
Reference List: ‘Well Control Policy Manual’
STAP-P-1-M-6150
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘Casing Design Manual’
STAP-P-1-M-6110
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STAP-P-1-M-6090 PL. 2.15. CEMENT PROGRAMME Reference 1. PRELIMINARY INFORMATION 7.8 In a cementing job the factors, that guide the selection of the P-1-M-6100 1.1. additives for the control of the slurry, flow properties and thickening time are:
• • • •
The annular configuration Wellbore conditions The mud type and density Temperature gradient
2. SLURRY DESIGN 2.1. Total slurry volume calculation (lead/tail slurry volumes) 2.1.1.
Reference
Always a percentage increment in volume must be considered for the P-1-M-6100 open hole section. In absence of relevant data, can be assumed: • • •
7.8.1
Surface casing: 100 % Intermediate casing: 50 % Production casing: 30 %.
2.1.2.
If logs are available, assume a percentage increment in volume equal P-1-M-6100 to 10%.
2.2.
Slurry density evaluation.
2.2.1.
Circulating bottom hole and static temperatures need to be P-1-M-61007.8.3 considered as well as the temperature differential between the bottom and top of the cement column.
2.2.2.
Circulating temperatures by calculation in accordance temperature schedules published in API 10 Specification
with P-1-M-6100
7.8.3
2.2.3.
One rule of thumb which should apply to the slurry design, is to P-1-M-6100 ensure that the static temperature at the top of the cement exceeds the circulating bottom hole temperature
7.8.3
2.3.
Type & amount of cement
2.3.1.
The cement type selection is mainly based on estimated bottom hole P-1-M-6100 temperature.
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 P-1-M-6100 using samples of actual cement, water and additives.
7.6
3. SPACER DESIGN 3.1. Spacer volume calculation 3.1.1.
Reference
Unless an effective mud density is required to control the formation P-1-M-6140 P-1-M-6100 pressure, all cement jobs shall be flushed with a water spacer.
12.3.1-6 7.4
The spacer volume shall be equivalent to, more or less, tree minutes of contact time or 150m of annulus capacity. 3.2.
Spacer density evaluation
3.2.1.
The best spacer is a spacer that has a density higher than the mud P-1-M-6100 but less than the cement slurry.
3.3.
Chemical composition
3.3.1.
The spacer fluid must be compatible with both the mud and the slurry P-1-M-6100 system, laboratory test shall be carried out.
7.4
3.4
Spacer fluid rheology properties evaluation
P-1-M-6100
7.4
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4. HYDRAULIC CALCULATIONS 4.1. Flow rates for cement displacement 4.1.1.
Displace at maximum allowable flow-rate. Normally turbulent flow in the annulus is preferred, in any case always monitor return.
4.2.
Estimated pressure profile
4.2.1.
Plot versus time/volume the following parameters: • • • •
Reference
Surface circulating pressure Bottom hole pressure Previous casing shoe pressure Any critical zone.
5. PLACEMENT TECHNIQUES 5.1. Single or multistage cementing operation
Reference
5.1.1.
Perform second stage operations as soon as cement setting time of P-1-M-6140 first stage is expired (at least twice the time thickening time). Lab test is recommended.
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 150m P-1-M-6140 overlap into the previous casing. If a smaller overlap is necessary due to a particular situation, it shall never be less than 50m
12.7.1-3
5.3.2.
If the rat hole exceeds the overlap length, set a cement plug at a P-1-M-6140 distance from the liner shoe setting depth shorter than the overlap itself.
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 6.1. Casing shoe 6.1.1.
Guide shoe.
6.1.2.
Float shoe.
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Reference
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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 be limited. Avoid the use of scratchers.
6.4.
Cementing plugs
6.4.1.
Non rotating PDC drillable plugs are recommended.
7. SURFACE EQUIPMENT SELECTION 7.1. Type & pressure rating of cementing head.
P-1-M-6140
Reference
7.1.1.
As alternative the circulating head can be requested with a bottom A-1-SS-1729 quick seal connection (without thread).
7.2.
Number of cementing units.
7.2.1.
It must be provided with twin triplex pumping units for pumping the A-1-SS-1729 cement slurry, for high pressure mixing and for general pumping operations
7.3.
Number & volume of available 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 8.1. Summary of operations
5.3.7
5.3.1-1
Reference
P-1-M-6140
8.1.1.
Testing pressure for surface lines: 5,000psi.
8.1.2.
Stop displacement in advance only if pressure exceeds 70% of P-1-M-6140 casing burst pressure or 5,000psi, whichever is less.
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8.1.3.
Prior to mix cement, water shall be checked. When mixing cement, P-1-M-6140 samples of slurry shall be collected. Also take mixing water samples and dry cement samples from each tank used.
12.3.1-11
8.1.4.
In jack-ups and fixed platforms drilling operations, at end of surface P-1-M-6140 casing cementing job, carefully wash the annulus between CP and surface casing to at least 5meters below the sea bottom, in order to 11 allow well abandoning operations according to specifications .
12.3.1-28
8.2.
Displacement
8.2.1.
• •
The displacement volume (for 30” CP and surface casing) P-1-M-6140 should be 1 bbls less than the theoretical volume. 1 Max over displacement volume equal to /2 of shoe-collar volume.
8.3.
Surface pressure at bump plug
8.3.1.
The bumping pressure values are always given in the Drilling P-1-M-6140 Programme.
8.4.
Parameters recording
8.4.1.
Record all mixing, displacing and bumping operations (pressure, flow P-1-M-6140 rate, total volume versus time).
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.
• • •
12.3.1-28
12.3.1-23
12.3.1-29
According to laboratory tests results (if done) or 2-3 times thickening time (check the samples, for surface jobs). Check always annulus level. Whenever it is possible close BOP and pressurise up to 100200psi according to weakest fracturing point.
Reference List:
11
‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘Cementing and Pumping Service For Drilling Completion and Workover Activity
STAP-A-1-SS-1729
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 1.1. Anticipated total depth. 1.1.1.
Reference
The design of the drill string for static tensile loads requires sufficient P-1-M-6100 strength in drill pipe to support the submerged weight of drill pipe and drill collar below.
10.11
P-1-M-6100
10.11
P-1-M-6100
10.8
10.9.
1.1.1.1. P = [(L dp W dp ) + (L c W c )]K b where: P
=
Submerged load
Ldp
=
Length of drill pipe in feet
Lc
=
Length of drill collar in feet
W dp
=
Weight per foot of drill pipe in air
Wc
=
Weight per foot of drill collar in air
Kb
=
Buoyancy factor
1.2.
Hole size.
1.2.1.
Drill string acceptability (Refer to Table PL 2.9)
1.3.
BHA Buckling
1.3.1.
In the design of BHA, it is important to determine the critical values of P-1-M-6100 weight on bit at which buckling occurs.
1.4.
Formation type & dip.
1.4.1.
Crooked hole drilling tendencies.
P-1-M-6100
10.12
Standard packed hole assembly should be: Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K Monel DC + String Stab + 2 DC + String Stab 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.
P-1-M-6140
8.5-b
P-1-M-6140
8.3
Degree of drillability of the formations. •
•
Hard to medium hard formations - Abrasive - Non abrasive Medium hard to soft formations
1.5.
Hole deviation
1.5.1.
Hole angle control. • •
Packed bottom hole assembly. Pendulum bottom hole assembly.
1.5.2.
BHA analysis in directional drilling
1.6.
Concentrations in bending stresses
1.6.1.
The (I/C) ratio bending. • •
12
is assumed as criterion to evaluate the resistance at P-1-M-6100
Soft formation Hard formation
10.8 8.8
P-1-M-6100 P-1-M-6140
10.11 8.11
13
Margin of overpull (MOP) .
1.7.1.
The minimum recommended value of MOP is 6,0000lbs
1.8.
Torque & drag evaluation
1.8.1.
Software applications.
1.9.
Differential sticking.
1.10.
Hydraulic requirements.
(
PL.02.13
π OD 4 − ID 4 64 OD C= 2
I, moment of inertia;
C, radius of tube;
I=
)
(I/C)ratio (I/C)large pipe/(I/C)small pipe 13
P-1-M-6140
(I/C)ratio < 5,5 (I/C)ratio < 3,5
1.7.
12
PL.02.01-8.1
MOP=Pa-P P, acting tension load Pa,max allowable design tension load; Pa=90% Pt Pt, theoretical max tension load
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REVISION
STAP-P-1-M-6090
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: ‘Drilling Procedures Manual’
STAP-P-1-M-6140
‘Drilling Design Manual’
STAP-P-1-M-6100
‘Casing Design Manual’
STAP-P-1-M-6110
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REVISION
STAP-P-1-M-6090
Hole Size (ins)
Drill Collar/Drill Pipe (ins)
I/C
I/C Ratio
83.8
1.5
DC 8 /4 x 21 /16
55.9
9.8
DP 5 x 19.5lbs/ft
5.7
-
Not
DC 9 /2 x 3
83.8
1.5
Recommended
1
55.9
7.1
DP 5 /2 x 19.5lbs/ft
7.8
1.4
DP 5x 19.5lbs/ft
5.7
-
83.8
1.5
OK for
DC 8 /4” x 2 /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
-
1
DC 9 /2 x 3 1
3
1
13
DC 8 /4 x 2 /16 1
1
17 /2
1
DC 9 /2 x 3 1
13
1
DC 9 /2 x 3
Remarks
83.8
1.5
” /16
55.9
2.5
OK For HARD
13
DC 6 /4 x 2 /16”
22.7
1.9
Formations
DP 5” x 19.5lbs/ft
5.7
-
81
13
DC /4 2 1
Note: For every hard formations, add HWDP 91
DC /2” x 3” 1
12 /4”
83.8
1.5
1
13
55.9
2.5
OK For HARD
1
13
DC 6 /4 x 2 /16
22.7
3.9
Formations
DP 5” x 19.5lbs/ft
5.7
-
DC 8 /4 x 2 /16”
Note: For every hard formations, add HWDP 91
DC /2” x 3” 1
12 /4”
83.8
1.5
DC 8 /4 x 2 /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
-
1
1
5
8 /8
13
13
DC 6 /4 x 2 /16”
22.7
DP 5” x 19.5lbs/ft
5.7
1
13
DC 6 /4 x 2 /16”
22.7
HWDP 5” x 42.6lbs/ft
10.7
DP 5” x 19.5lbs/ft
5.7
Not 3.9
Table PL 2.9 - Drill String Acceptability
SECTION 1 OF BP&MR - PLANNING (PL)
Recommended Recommended
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REVISION
STAP-P-1-M-6090 PL. 2.17. BIT SELECTION & DRILLING PARAMETERS 1. FACTORS AFFECTING BIT SELECTION 1.1. Main factors to consider and evaluate 1.1.1.
• • • • •
Reference
P-1-M-6100
11.1
1.2.
To optimise the drilling operations.
1.2.1.
Monitoring the drilling performance and conditions on the prospect P-1-M-6100 well so that the performance is equal to or above the average in the area.
11.1
1.2.2.
Implementing a bit weight-rotary speed programme based on P-1-M-6100 theoretical calculations that will improve the performance above the existing best performances in the area.
11.1
1.3.
Parameters involved in the selection of drill bits
1.3.1.
In hard and abrasive formations roller bits in IADC code range 6-1-7 P-1-M-6100 or higher are usually more successful.
11.4.1
1.3.2.
Oil based mud is actually believed to enhance the performance of P-1-M-6100 PDC bits since they inhibit clay hydration and stickiness.
11.4.2
1.4.
Directional drilling considerations
1.4.1.
Rotary drilling to right-hand walk is increased when using roller bits P-1-M-6100 are used as cone offset from the bit centre increases.
11.4.3
1.4.2.
PDC bits with their relatively lower bit weights and no cones, hence P-1-M-6100 cone offset problems are favoured.
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 as P-1-M-6100 PDC, diamond and journal bearing insert bits.
11.4.4
1.5.2.2.
Turbine drilling may have a tendency to left-hand walk. This is P-1-M-6100 controlled by the turbine used, bit gauge length, and BHA stabilisation
11.4.3
Bit cost Method of drilling (turbine, rotary, air) Formation type and properties Mud system Rig cost
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REVISION
STAP-P-1-M-6090
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 P-1-M-6100 PDC bits since they inhibit clay hydration and stickiness.
1.8.
Available bit records analysis.
1.9.
Drilling cost optimisation
1.9.1.
Representative bit-cost curves.
P-1-M-6100
11.4.2
11.6
Reference List: ‘Drilling Design Manual’
STAP-P-1-M-6100
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REVISION
STAP-P-1-M-6090 PL. 2.18. EXPECTED DRILLING PROBLEMS & RECOMMENDATIONS Reference 1. DRILLING DIFFICULTIES Describe the drilling difficulties encountered in reference wells, P-1-M-6001E detailed by phases. Reference 2. SUGGESTIONS Suggestions must be provided in order to prevent or manage at best P-1-M-6001E all the expectable difficulties. Reference 3. GENERALITIES In the operative sequence of the drilling programme, for each phase P-1-N-6001E 6.2 3.1. in a specific paragraph will be reported the drilling problems that will include a specific contingency plan to cover each of them. Reference
4. LOSSES CIRCULATION 4.1. Preventive measures 4.1.1.
Mud characteristics
4.1.1.1.
Particularly in surface holes, maintain high mud viscosity values.
4.1.1.2.
Keep the mud weight as low as possible providing for adequate P-1-M-6140 overbalance.
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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OP.02
12-9.1.2
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REVISION
STAP-P-1-M-6090
Reference
5. DIFFERENTIAL STICKING 5.1. Preventive measures 5.1.1.
Mud characteristics.
5.1.1.1.
Use mud with minimum solids content and low filtrate in order to have P-1-M-6160 P-1-M-6140 a thin wall cake.
7.1 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 minimum P-1-M-6160 P-1-M-6140 differential pressure necessary for a safe trip margin.
7.1 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 to P-1-M-6140 well situation.
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 P-1-M-6160
16.4.1 7.1
5.2.1.2.
Heavy oil pills used for specific gravity greater than 1350 g/l.
P-1-M-6140 P-1-M-6160
16.4.2 7.1
5.2.1.3.
Operational planning:
P-1-M-6140 P-1-M-6140 P-1-M-6160
16.4.1 16.4.2 7.1
volume evaluation • Hydrostatic pressure balance • Displacement techniques. 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 across P-1-M-6140 of a carbonate formation. This method should be carried out only if P-1-M-6160 others will be ineffective, unless former experiences.
16.4.3 7.1
5.2.2.2.
The proper amount of corrosion inhibitor must be used and the acid P-1-M-6140 pill will be spaced with oil or water ahead and behind.
16.4.3
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REVISION
STAP-P-1-M-6090
5.2.2.3.
Operational planning see point 3.2.1.3.
P-1-M-6140
16.4.3
Whenever acid is handled, the appropriate safety measures shall be adopted Reference
6. CAVING HOLE 6.1. Preventive measures 6.1.1.
Mud characteristics
6.1.1.1.
Possible mud changes are:
P-1-M-6140
16.3
P-1-M-6140 P-1-M-6160
16.3 7.1
P-1-M-6140
16.3
If the string gets stuck in front of carbonate formation: spot an acid P-1-M-6140 P-1-M-6160 pill, see point 3.2.2.
16.3 7.1
• • • • • •
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 asphalt sulphonate). Increase the mud weight.
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.
6.1.3.
Drilling parameters
6.1.3.1.
Possible changes in parameters are: • • • • •
6.1.3.2.
Reduce rotary speed, if possible, to 80rpm or less. Reduce the mud flow rate to obtain laminar flow in the annulus between 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.
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REVISION
STAP-P-1-M-6090
Reference
7. HOLE RESTRICTION 7.1. Preventive measures 7.1.1.
Mud characteristics
7.1.2.
Reduce mud filtrate and solids content.
P-1-M-6140 P-1-M-6160
16.2 7.1
7.1.3.
Increase mud weight if possible.
P-1-M-6140 P-1-M-6160
16.2 7.1
7.1.4.
Use inhibited mud.
P-1-M-6140 P-1-M-6160
16.2 7.1
7.1.5.
Drilling parameters:
7.1.6.
Increase flow rate.
P-1-M-6140 P-1-M-6160
16.2 7.1
7.1.7.
Miscellaneous
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 P-1-M-6160
16.2 7.1
7.2.2.
Work the pipe applying slack-off if the string has become stuck P-1-M-6140 pulling out, and overpull if it stuck while running in.
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 acid P-1-M-6140 P-1-M-6160 pill, see point 3.2.2.
16.4.3 7.1
Reference
8. HOLE IRREGULARITIES 8.1. Preventive measures 8.1.1.
Bottom hole assembly
8.1.1.1.
The formation of dog legs can be prevented by the use of packed P-1-M-6140 P-1-M-6160 bottom hole assemblies.
16.3.1 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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STAP-P-1-M-6090
8.1.2.
Miscellaneous
8.1.2.1.
A key seat can be eliminated by reaming it with a key seat wiper or an P-1-M-6140 P-1-M-6160 under-gauge stabiliser installed on the top of the drill collars.
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 string P-1-M-6140 becomes stuck pulling out) and overpull if running a new BHA (the string becomes stuck while running in the hole).
8.2.2.
Spot oil-based mud or oil containing a surfactant around the BHA.
P-1-M-6140 P-1-M-6160
16.3.1 7.1
8.2.3.
If the stuck point is in a calcareous section, spot an acid pill. (see P-1-M-6140 P-1-M-6160 point 3.2.2).
16.3.1 7.1
9. HYDROGEN SULPHIDE GUIDELINES 9.1. Generalities
16.3.1.1
Reference
9.1.1.
It is compulsory that the Drilling Contractor has an ‘Emergency Safety P-1-M-6150 P-1-M-6160 Plan’ including a specific procedure for the presence of H2S.
9.1.2.
Adoption of safety measures while circulating bottom-up.
9.2.
Drillsite location
9.2.1.
Surface elevation / wind direction / access road / briefing area.
9.3.
Material specifications ‘sour service’
9.3.1.
Tubular goods / wellhead / blowout preventer equipment / choke P-1-M-6110 manifolds.
9.3.2.
Drill pipe inspections.
9.4.
Drilling fluids
9.4.1.
Use H2S scavengers.
9.4.2.
Use corrosion inhibitors.
10.1 4.1.4
P-1-M-7130 P-1-M-6150
20.6.3 10
P-1-M-6150
10.1
P-1-M-6150
SECTION 1 OF BP&MR - PLANNING (PL)
16.3.1 7.1
9
10.9.6
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REVISION
STAP-P-1-M-6090
9.5.
Safety requirements for particular operations
9.5.1.
Core Recovery In Presence Of H2S
P-1-M-6150
10.2.3
After coring in a H2S bearing formation, it is necessary to wear the Cascade System masks (if available ), or Self Breathing Apparatus with 30-45min bottles, during the whole core recovery operation, both using a rubber type core barrel or a inner tube core barrel. 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 P-1-M-7130
10.10.1 20.2.1
9.6.1.2.
The system measuring capacity must be 0-50ppm in air.
P-1-M-6150
10.10.2
Danger thresholds are set as follows: • •
Pre Alarm: for a concentration between 10ppm and 20ppm in air; Alarm: for a concentration upper of 20ppm. in air
9.6.2.
Breathing apparatuses.
P-1-M-7130 P-1-M-6150
20.7.2/4 10.11
9.6.3.
Wind direction indicators.
P-1-M-7130 P-1-M-6150
20.7.6 10.14
9.6.4.
Ventilation equipment.
P-1-M-7130 P-1-M-6150
20.7.3 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 the P-1-M-6150 dedicated form. It is important to measure the time required for personnel gathering and being accounted at the meeting point.
10.9.3
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REVISION
STAP-P-1-M-6090
9.7.2.
Drills frequency
9.7.2.1.
Alert or emergency drills when the presence of H2S is either P-1-M-6150 predictable or ascertained are to be performed weekly (during a trip), no-routine drills shall be performed before: • • • •
10.9.3
Entering in a H2S zone Coring job DST or well testing Drilling an overpressured zone.
9.8.
Operating procedures
9.8.1.
Pre Alarm: for a concentration between 10ppm and 20ppm in air;
P-1-M-7130 P-1-M-6150
20.5.2 10.3.2
9.8.2.
Alarm: for a concentration upper of 20ppm. in air
P-1-M-7130 P-1-M-6150
20.5.3 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
SECTION 1 OF BP&MR - PLANNING (PL)
DOBC
GEL CEMENT DOBC
AERETED FLUIDS STIFF-FOAM
SPOT PILL WITH LCM
HIGH/VERY HIGH FILTRATION MIXTURE
SECTION 1 OF BP&MR - PLANNING (PL) AERETED FLUIDS STIFF-FOAM
DOBC
CEMENT + GELSONITE
CEMENT/GEL CEMENT SLURRIES
HIGH FILTRATION MIXTURE
- HIGH FILTRATION FLUID
AERETED FLUIDS STIFF-FOAM
DOBC
DOB
HIGH FILTRATION MIXTURE
SET TIME LOW LOADING
LOW DENSITY FLUIDS
HIGH FILTRATION MIXTURE
FLUID THINNING AND/OR UNWEIGHTING
HIGH DENSITY FLUIDS
HYDRAULICALLY-INDUCED FRACTURES
ENI S.p.A. Agip Division
- LCM IN CIRCULATION
GEL-CEMENT SLURRIES
HIGH FILTRATION MIXTURE
SPOT PILLS WITH LCM
HIGH VISCOSITY FLUID
HIGH VISCOSITY FLUID AND HIGH GELS
CAVERNS
TOTAL
FRACTURES
FRACTURES
ALMOST TOTAL more than 50%
FRACTURES
HIGHLY PERMEABLE
SURFACE AREAS
SEEPAGE LOSS less than 50%
ARPO
IDENTIFICATION CODE PAGE
STAP-P-1-M-6090
Figure PL 2.4- Lost circulation control techniques
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REVISION
STAP-P-1-M-6090 PL. 2.19. WELL ABANDONING 1. GENERAL GUIDELINES 1.1. Consent for well abandonment
Reference
1.1.1.
On the basis of information available during the planning phase set P-1-N-6001E out a program for well abandoning (temporary or permanent)
1.2.
Purposes in well abandoning operations
1.2.1.
To ensure full and permanent isolation of formation fluids and P-1-M-6100 P-1-M-6140 different pressure regimes.
1.2.2.
To free, in offshore operations, the seabed from any obstructions.
1.3.
Abandonment programme contents
1.3.1.
Well identification data.
1.3.2.
6.2.8
P-1-M-6140 P-1-M-6100 P-1-M-6140 P-1-M-6100 P-1-M-6140
14.1.2 14.1.2 14.2.2 14.2.2 14.2.2 14.1.2 14.1.2
P-2-N-6001E
7.1.1
The operations to perform for the abandonment (temporary or P-1-N-6001E permanent) of the well, including the following minimum information:
6.2.8
• • • • • • • • • •
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.
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 a P-1-M-6100 mechanical plug. Them a cement plug shall be set at last 50- P-1-M-6140 100metres in length into the casing and between 20-50meters below ground level/sea bed.
14.1.1 14.1.1
2.1.2.
Last casing string above open hole section shall be sealed with a P-1-M-6100 cement plug extending at least 50metrers above and below the P-1-M-6140 casing shoe.
14.1.1 14.1.1
2.1.3.
The top of cement plug shall be located and verified by mechanical P-1-M-6100 P-1-M-6140 loading.
14.1.1 14.1.1
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STAP-P-1-M-6090
2.1.4.
If hole/formation conditions make cementing difficult, a mechanical P-1-M-6100 plug must be positioned in the lower part of casing (not more than 50 P-1-M-6140 meters above the shoe).
14.1.1 14.1.1
2.1.5.
A cement plug at least 20meters long shall be placed on top of P-1-M-6100 P-1-M-6140 mechanical plug.
14.1.1 14.1.1
2.1.6.
A cement plug, at least 50-100meters long, shall be set with its top P-1-M-6100 P-1-M-6140 placed at least 20-50meters below the ground level / seabed.
14.1.1 14.1.1
2.1.7.
The top of cement plug shall be located and verified by mechanical P-1-M-6100 P-1-M-6140 loading.
14.1.1 14.1.1
2.1.8.
In case a liner has been set, a cement plug shall be placed, it is P-1-M-6100 P-1-M-6140 extending at least 50meters above and below the top liner.
14.2.2 14.2.2
2.2.
Plugging programme before a production test
2.2.1.
Open hole with permeable zones containing fluid: all zones shall be P-1-M-6100 individually isolated with cement plugs. Each plug shall be located at P-1-M-6140 least 50 meters above and below the zone.
14.1.2 14.1.2
2.2.2.
The top of each cement plug shall be located and verified by P-1-M-6100 P-1-M-6140 mechanical loading.
14.1.2-1 14.1.2-1
2.2.3.
Last casing string above open hole section shall be sealed with a P-1-M-6100 cement plug, it is extending at least 50meters above and below the P-1-M-6140 casing shoe.
14.1.2-1 14.1.2-1
2.2.4.
The top of each cement plug shall be located and verified by P-1-M-6100 P-1-M-6140 mechanical loading.
14.1.2-1 14.1.2-1
2.2.5.
If hole/formation conditions make cementing difficult, a mechanical P-1-M-6100 plug must be positioned in the lower part of casing (not more than P-1-M-6140 50meters above the shoe).
14.1.2-1 14.1.2-1
2.2.6.
A cement plug at least 20meters long shall be placed on top of P-1-M-6100 P-1-M-6140 mechanical plug.
14.1.2-1 14.1.2-1
2.2.7.
The above mentioned plugs shall be verified by mechanical loading P-1-M-6100 P-1-M-6140 and pressure tested.
14.1.2-1 14.1.2-1
2.3.
Plugging Programme after a production test
P-1-M-6140
14.1.2.2
2.3.1.
Uninteresting perforated zones. All intervals shall be isolated by P-1-M-6100 P-1-M-6140 means of a mechanical plug and shall be squeeze cemented.
14.1.2-2 14.1.2-2
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2.3.2.
If the injection through formation is expected to be negative, a cement P-1-M-6100 plug shall be placed with its upper and lower ends located at least 50 P-1-M-6140 meters above and below the perforated zone respectively, or down to the nearest plug if the distance is less than 50meters.
14.1.2-2 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 P-1-M-6140
14.1.2-2 14.1.2-2
2.3.5.
Interesting perforated zones.
P-1-M-6100 P-1-M-6140
14.1.2-2 14.1.2-2
2.3.6.
A cement plug, at least 20meters long, shall be set above the bridge P-1-M-6140 plug.
14.1.2-2
2.3.7.
A cement plug, 50-100meters long, shall be set between 5-50meters P-1-M-6100 P-1-M-6140 below the seabed (jack-up rigs & fixed platforms).
14.1.2-2 14.1.2-2
2.3.8.
The top of the cement plug shall be located and verified by P-1-M-6100 P-1-M-6140 mechanical loading.
14.1.2-2 14.1.2-2
These intervals shall be isolated by means of mechanical plug.
3. PERMANENT ABANDONMENT – PLUGGING 3.1. General information When static bottom hole temperature exceeds 110°C, use Geoterm 3.1.1. type cement. Water spacers should be used ahead and behind the slurry. The 3.1.2. spacers should be normally 100 m long The slurry volume should be calculated using a calliper log, if 3.1.3. available. When a calliper log is not available, use a slurry volume excess based on local experience. Plugs exceeding 200 meters in length should not be set in one stage. If the hole is badly washed out or when potential losses are expected, 3.1.4. it is preferable to set two short plugs instead of one long one. All cement plugs shall be set using a tubing stinger 3.1.5. 3.1.6. 3.1.7. 3.1.8. 3.1.9. 3.1.10.
As soon as the plug is set, pull out slowly 30-50 m above theoretical top and circulate Using drilling or workover rig each cement plug shall be located and verified, (WOB: 20,000-40,000 lbs, depending on hole size). Slurry volume calculations in squeeze cement jobs assume roughly, 100 litres slurry/meters perforated formation. A cement plug, at least 150 meters long, shall be placed with its top 50 meters below the seabed (off-shore), or ground level (on-shore). After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below seabed, using mechanical cutters.
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Reference
P-1-M-6100 P-1-M-6140
14.2.3-1 14.2.3-1
P-1-M-6100 P-1-M-6140
14.2.3-2 14.2.3-2
P-1-M-6100 P-1-M-6140
14.2.3-3 14.2.3-3
P-1-M-6100 P-1-M-6140
14.2.3-4 14.2.3-4
P-1-M-6100 P-1-M-6140 P-1-M-6100 P-1-M-6140
14.2.3-5 14.2.3-5 14.2.3-8 14.2.3-8
P-1-M-6100 P-1-M-6140
14.2.3-11 14.2.3-11
P-1-M-6100 P-1-M-6140
14.2.2 14.2.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1M-6140
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3.2. 3.2.1. 3.2.1.1. 3.2.1.2. 3.2.1.3. 3.2.2. 3.2.2.1.
3.2.2.2.
Explorative wells Open hole All permeable zones shall be plugged individually to avoid any cross flow. Cement plugs shall be set with top and bottom at least 50 meters above and below each zone. The top of the cement plugs shall be located and verified by mechanical loading. Casing shoe Last casing string above open hole shall be sealed with a cement plug, it shall extend at least 50meters above and below the shoe depth. Plug shall be tested by mechanical loading.
Liner head 3.2.3.1. At the hanging point of the liner a cement plug shall be set, it is extending at least 50meters above and below the top of liner. Casing cutting 3.2.4. 3.2.4.1. The casing shall be cut at least 100meters above the shoe of the previous casing string and a cement plug shall be placed in such manner that extends at least 50 mertres above and below the casing cut point. 3.3. Completed wells Onshore Wells with pressure in the annulus casing/casing 3.3.1. 3.3.1.1. Case I° (Casing with top of cement below the surface) Open hole Phase 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 a cement plug: it shall extend at least 50 meters above and below the shoe depth. 3.3.1.1.3. If it is impossible to retrieve the packer a cement squeeze will be performed in the formation below the packer. 3.3.1.1.4. Proceed with cutting and retrieving of the completion string above the packer. 3.3.1.1.5. If the squeeze is not allowed, in HPHT wells, a bridge plug will be set in the completion string below the packer, the completion string above 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 the completion string above the packer and to perform a cement plug on the packer.
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.3 14.3
3.2.3.
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3.3.1.2. 3.3.1.2.1. 3.3.1.2.2. 3.3.1.2.3. 3.3.1.2.4.
3.3.1.2.5.
3.3.1.3.
Case I° (Casing with top of cement below the surface) perforated casing zones Phase one: Perforated zones shall be isolated with mechanical plug and shall be squeeze cemented. Before to setting either cement or mechanical plugs, clear the internal of the casing using taper mill A cement retainer will be set maximum 10-15meters above the perforations. 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 with any upper perforated intervals 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. Case I° (Casing with top of cement below the surface) Phase two:
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
P-1-M-6100 P-1-M-6140
14.1.2 14.1.2
3.3.1.3.1. In both cases Open hole and Cased hole, 20/30 day later, return on
3.3.1.3.2. 3.3.1.3.3.
3.3.1.3.4. 3.3.1.3.5.
the well with a workover rig and verify the hydraulic seal of the plugging previously performed. The workover rig will be selected with particular attention to the well site dimensions. The well site will guarantee as safety distance that the derrick downfall radius is free from houses, electrical lines, roads and any logistic structures (engine area, office bunk houses, etc.) If it is impossible to respect the safety distance, the Responsible for the Operations has faculty of derogation. 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 previous P-1-M-6100
3.3.1.4.
casing string and a cement plug shall be placed in such a way to cover the casing at least 50 m above and below the casing cut point. 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 the
pressures, 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. Onshore Wells without pressure in the annulus casing/casing 3.3.2. 3.3.2.1. When the cement top is above the shoe of the previous casing, the utilisation of drilling rig unit can be avoided and the well abandoning operations will be carried out utilizing the best technique available considering both economic and operative constraints 3.3.2.2. The cement plug test will be performed by pressurising the top of the plug with a 1500 psi differential pressure.
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3.3.2.3.
3.3.2.4.
3.3.2.5.
3.3.2.6.
3.3.2.7. 3.3.3. 3.3.3.1. 3.3.3.2.
3.3.4. 3.3.4.1. 3.3.4.2.
If the top of cement is under the shoe of the previous casing, it will be mandatory to carry out a cement plug 100 m long in the annulus casing/casing by circulating through the casing perforations Several levels with the same hydraulic regime (homogeneous formations, pressure and production fluid) can be plugged by means of two cement plugs, provided the lower extends at least 50 m below the bottom of the deeper level and the upper extends at least 50 m above the top of the higher level Between such two plugs it will be placed a fluid with the same characteristics of that one used during the running of the production casing. If SBHP is lower than hydrostatic pressure of the production fluid, all annuli will be cemented to surface and the completion string will be totaly abandoned in the well. 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. Offshore Wells with pressure in the annulus casing/casing The use of workover rig is mandatory Both for explorative and completed offshore wells the well abandonment will be carried out following the procedure (above specified) for onshore well, making distintion between the two cases (pressure or not in the annulus), but performing the operation in one unique phase. Offshore Wells without pressure in the annulus casing/casing The use of workover rig is mandatory Both for explorative and completed offshore wells the well abandonment will be carried out following the procedure (above specified) for onshore well, making distintion between the two cases (pressure or not in the annulus), but performing the operation in one unique 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
Reference 1. CONCEPTUAL DESIGN 1.1 The approach to completion design must be interdiscipline, involving P-1-M-7100 1.1. Reservoir Engineering, Petroleum Engineering, Production Engineering and Drilling Engineering. This is vital in order to obtain the optimum completion design
1.2.
Many of the decisions made by the various disciplines are interrelated P-1-M-7100 and impact on the decisions made by other disciplines. For instance, the decision on the well architecture may subsequently be changed due to the availability of well servicing or workover techniques. This does not mean that the process is sequential and many decisions can be made from studies and analysis run in parallel.
1.1
1.3.
The design process consists of three phases:
P-1-M-7100
1.1
As more information is gleamed from further development wells and P-1-M-7100 as 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 suit changing conditions, increased knowledge of the field and incorporate new technologies.
1.1
• Conceptual • Detailed design • Procurement. The process of well preparation and installation of completions is fully described in the ‘Completions Procedures manual’. 1.4.
Reference 2. COMPLETION OBJECTIVES P-1-M-7100 1.2 The fundamental objectives for a completion are: 2.1. • 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 whole development plan reservoir plan. • Achieve the optimum production rates reliably at the lowest capital and operating costs.
2.2.
These may be summarised as to safely provide maximum long term P-1-M-7100 profitability. This, however, in reality is not simple and many critical decisions are needed to balance long term and short term cash flow and sometimes compromises are made.
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Reference 3. FUNCTIONS OF A COMPLETION 1.3 The main function of a completion is to produce hydrocarbons to P-1-M-7100 3.1. surface or deliver injection fluids to formations. This is its primary function, 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 conceptual design 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.
4. RESEVOIR CONSIDERATIONS 4.1. Hydrocarbon data
Reference P-1-M-7100
2.3
4.1.1.
The practical approach to the study of reservoir fluid behaviour is to P-1-M-7100 anticipate pressure and temperature changes in the reservoir and at surface during production, and to measure, by laboratory tests, the changes occurring in the reservoir samples. The results of these tests then provide the basic fluid data for estimates of fluid recovery by various methods of reservoir operations and also to estimate reservoir parameters through transient pressure testing.
2.3
4.1.2.
Two general methods are used to obtain samples of reservoir oil for P-1-M-7100 laboratory examination purposes, by means of subsurface samplers and by obtaining surface samples of separator liquid and gas. The surface samples are then recombined in the laboratory in proportions equal the gas-oil ratio measured at the separator during well testing.
2.3
4.2.
Oil Property Correlation
4.2.1.
Several generalisations of oil sample data are available to permit P-1-M-7100 correlation’s of oil properties to be made (refer to the Company Well Test Manual for sampling techniques).
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Reference 5. RESERVOIR/PRODUCTION FORECAST 2.4 To obtain the optimum performance from a well, it is first necessary to P-1-M-7100 5.1. determine its full potential and which way this can be fully exploited within any technical or economic constraints. The determination of the well’s performance entails analysing the following:
• • • • 5.2.
In-flow performance Near wellbore performance and design Multiphase flow of tubing performance Artificial lift.
The process of this analysis is shown in
P-1-M-7100
2.4
Figure PL 3.1 which requires continuous repetition during field life to account for changing conditions. 5.3.
Inflow Performance
P-1-M-7100
2.4
5.3.1.
The inflow performance relationship (IPR) provides the flow potential P-1-M-7100 of the reservoir into the wellbore against the resistance to flow of the formation and near wellbore region. The theoretical IPR is an idealistic assumption of flow performance without pressure drop due to skin effect in the near wellbore region and governed only by the size, shape and permeability of the producing zone and the properties of the produced fluids. The basic theory of this is described in this section along with some simplified IPR relationships from observed field data.
2.4
5.4.
Near wellbore performance and design
P-1-M-7100
2.4
5.4.1.
Flow behaviour in the near wellbore region may cause a dramatic P-1-M-7100 effect on the IPR curve which results in greatly reduced flow capability. This is characterised by a damaged IPR curve and the amount of damage or skin effect, is mainly caused by the drilling and completion practices. Good drilling and completion practices can or may minimise this damage allowing use of the idealised IPR curve to be used for completion design.
2.4
5.5.
Multiphase flow of tubing performance
P-1-M-7100
2.4
5.5.1.
Some completion designs to deal with reservoir conditions, such as P-1-M-7100 gravel packs for unconsolidated sands, will also cause reduced IPR curves which must be anticipated during the design phase. Two phase flow, velocity effects in gas wells, high rate or high GOR oil wells, in undamaged near wellbore regions also reduce the IPR curve. Alternatively, stimulation procedures which can provide a negative skin are desirable as this increases production.
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 not P-1-M-7100 intersect and in this case artificial lift could be used to provide the pressure differential between the curves (Refer to
2.4.5
Figure PL 3.2). An artificial lift system places an injection of energy into the flow system which displaces the TPC curve downwards. In a pumping well, the displacement is dependent on the pump performance curve (i.e. pump differential versus rate) which is plotted below the well performance curves as shown in Figure PL 3.2. This results in a combined outflow performance curve termed the pump intake curve.
Reference List: ‘Completion Design Manual’
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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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RESERVOIR FLUIDS CHARACTERISTICS
Reference 1. GENERAL 2.3 The practical approach to the study of reservoir fluid behaviour is to P-1-M-7100 1.1. anticipate pressure and temperature changes in the reservoir and at surface during production, and to measure, by laboratory tests, the changes occurring in the reservoir samples. The results of these tests then provide the basic fluid data for estimates of fluid recovery by various methods of reservoir operations and also to estimate reservoir parameters through transient pressure testing. Reference
2. OIL CHARACTERISTICS Oil density. 2.1. 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. Reference
3. GAS CHARACTERISTICS Gas gravity. 3.1. 3.2.
Volume factor.
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3.3.
Viscosity.
3.4.
Chemical composition.
3.5.
Corrosive agents content.
3.6.
Hydrate forming capability.
3.7.
Water density.
3.8.
Water salinity.
3.9.
Water pH.
4. GAS CONDENSATE CHARACTERISTICS Gas gravity. 4.1. 4.2.
Condensate density.
4.3.
Dew point.
4.4.
Volume factor.
4.5.
Viscosity.
4.6.
Chemical composition.
4.7.
Corrosive agents content.
4.8.
Condensate-gas ratio.
4.9.
Chemical composition.
4.10.
Asphaltenes deposition curve.
4.11.
Hydrate forming capability.
4.12.
Water density.
4.13.
Water salinity.
4.14.
Water pH.
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5. SAMPLING Bottom hole and/or surface reservoir fluid sampling should be always 5.1. planned during the well testing executed on exploratory and appraisal wells in order to get a PVT study before final completion design carry on. 5.2.
The PVT study should contain FLASH vaporisation data for tubing PVT 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 be performed to obtain the real GOR and a surface sampling shall be performed.
5.6.
Surface sampling shall be executed at stabilised flow parameters at relevant pressure & temperature separator conditions and well head parameters shall be recorded at same time.
5.7.
Field measurement of H2S concentration shall be always referred to the sampling point conditions. (first stage separator; second stage separator; tank gas).
Reference
Reference List: ‘Completion Design Manual’
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RESERVOIR ROCK CHARACTERISTICS
1. GENERAL Within Completion engineering rock characteristics are primarily 1.1. concerned with the way in which the rock system will react to the completion 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 Choice of completion fluids. 2.1. 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.
Reference
Reference
Reference
3. MAIN CHARACTERISTICS Porosity. 3.1.
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 The Completion engineer should check the availability of formation 4.1. cores, and address the request to core in case of lack of the information essential to the particular design in progress. 4.2.
Reference
The core study should be addressed to the Well Area Laboratories and a synthesis of results should take part of the Completion design study.
Reference List: ‘Completion Design Manual’
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STAP-P-1-M-6090 PL. 3.4.
EFFECTS OF RESERVOIR CHARACTERISTICS
1. GENERAL The driving mechanisms and thermodynamics of the hydrocarbons in 1.1. the reservoir is a matter of reservoir engineering that should decide the reservoir depletion strategy and address to the completion engineering the information of concern to the completion design. 1.2.
Reference
In an oil reservoir, primary production results from existing pressure in P-1-M-7100 the reservoir. There are three basic drive mechanisms:
2.2.7
• Dissolved gas • Gas cap • Water drive. Most reservoirs in actuality produce by a combination of all three mechanisms. Reference 2. DESIGN PARAMETERS 2.2.7 The effect of the drive mechanism on the producing characteristics P-1-M-7100 2.1. must 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 typical reservoir pressures versus production trends and gas-oil ratio production trends for the three basic drive mechanisms.
3. COMPLETION DESIGN THROUGH FIELD LIFE Natural flow to artificial lift design should be considered. 3.1. 3.2.
Production to injection status should be considered.
3.3.
Sand consolidation or control should be considered.
4. NEAR WELLBORE RESTRICTIONS The well performance at bottom hole is given by the summation of the 4.1. reservoir performance and the near wellbore performance. The near wellbore performance may be reduced by different causes that shall be considered. 4.2.
Formation damage skin
4.2.1.
Formation skin occur when the permeability in the near wellbore region is reduced as a result of various fluid-fluid and fluid-rock interactions. This is often due to the invasion of solids or incompatible fluids 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 a spherical/cylindrical flow through the crashed zone around the perforation tunnel. This is more significant where the shot penetration does not cross the damaged zone and where the effective shot density is reduced because 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 total net pay thickness is open. In that case the flow converge to the perforated interval to enter the wellbore and cause additional pressure losses.
4.4.2.
Partial completion skin, called also geometrical skin, can be very large especially in high anisotropy formations and should be generally avoided. However a zone may be intentionally partly perforated to avoid 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 is reduced. That can happen in oil wells producing below bubble point and in gas wells producing below dew point. The effect of the multiphase pressure drop depends on how the relative 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 sand are positioned in front of the pay zone to inhibit formation sand from invading the gravel pack. Additional pressure drop should be given by poor perforation filling allowing the tunnel to collapse and/or when sand 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 the high velocity of the fluids in the near wellbore area causes turbulence and associated pressure drop. The magnitude of the non-Darcy effect should be very large and shall be taken into account in gas wells producing more than 10,000Nm³/day and oil wells producing more 3 than 50m /day per perforated meter.
4.8.
Reduction of permeability during production
4.8.1.
Obstructions may occur also during production phase and caused by the following.
4.8.2.
Produced fines.
4.8.3.
Scales.
4.8.4.
Asphaltenes.
Reference 5. STRATEGY TO MINIMISE THE SKIN EFFECTS 2.2.6 In a radial flow situation, where fluids move towards the well from all P-1-M-7100 5.1. directions, most of the pressure drop in the reservoir occurs fairly close to the wellbore. In a uniform sand, the pressure drop across the last 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 the reservoir. Obviously flow velocities increase tremendously as fluid approaches the wellbore. This area around the wellbore is the ‘critical area’ and as much as possible should be done to prevent damage or flow restrictions in this critical area.
5.2.
If a well is to be perforated overbalanced, then strict control over the P-1-M-7100 fluid used to ensure it is compatible with the reservoir formation, formation fluids and must also be clean to prevent formation damage.
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 any P-1-M-7100 restriction to flow.
2.2.6
5.10.
Gravel Pack Completions
P-1-M-7100
9.3.1
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 essential for to prevent high skin factors. 5.11.
Specific chemical treating of the near wellbore area to remove formation damage.
5.12.
Limit brine volume losses in depleted reservoir and use surface tension reducer.
Reference 6. WELL INFLOW PERFORMANCE 2.4 The inflow performance relationship (IPR) provides the flow potential P-1-M-7100 6.1. of the reservoir into the wellbore against the resistance to flow of the formation and near wellbore region. The theoretical IPR is an idealistic assumption of flow performance without pressure drop due to skin effect in the near wellbore region and governed only by the size, shape and permeability of the producing zone and the properties of the produced fluids.
6.2.
The equation used shall take into account all the Darcy and nonDarcy effects.
6.3.
Where inflow relationship passes through the bubble point, a straight P-1-M-7100 line IPR is drawn above the bubble point and the curved IPR signifies the two phase flow below this point. For this, Vogel’s equation is combined with the PI to develop a general IPR equation. This has been published by Brown. When the BHFP is above the bubble point use the normal straight line equation: qo =J(pR −p wf )
and when it drops below the bubble point use the modified Vogel equation: p Jp qo =J(p R −p wf )+ b 1−0.2 wf 1.8 pb
p −0.8 wf pb
2
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6.4.
Fetkovich recognised that many oil wells could be handled in the P-1-M-7100 same way as gas wells using the curved IPR:
(
qo =C pR −p wf 2
2.4.1
)
2 n
where:
6.5.
C =
Linear deliverability coefficient
n
Deliverability exponent (0.5 to 1.0)
=
Blount and Jones presented an alternative generalised IPR equation P-1-M-7100 which was an extension to the Forcheimer equation to include the non-Darcy flow effects:
2.4.1
p R −p wf =aq+bq2 6.6.
Forcheimer equation for gas wells should be used for pressure below P-1-M-7100 2,000psi and where the drawdown is small as in high permeability wells: p R −p wf =Aqg + Aqg
6.7.
2.4.1
2
When the µz value is not constant the pseudo pressure m(p) shall be used 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 is expected.
Reference List: ‘Completion Design Manual’
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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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STAP-P-1-M-6090 PL. 3.5.
TUBING PERFORMANCE
Reference 1. GENERAL 2.4.4 The relationship between pressure and temperature drop in wells and P-1-M-7100 1.1. PVT behaviour is complex. Pressure drop is determined using empirical and semi-empirical correlation’s and carried out on computer software programmes.
1.2.
Calculating pressure drop in tubing involve numerical integration of P-1-M-7100 the steady-state pressure gradient equation over the entire tubing length. It consists of the following three components: • • •
2.4.4
Hydrostatic head Wall friction Fluid acceleration.
1.3.
The acceleration term is usually negligible except in system involving P-1-M-7100 significant fluid expansion (gas wells when near atmospheric pressure).
2.4.4
1.4.
The friction losses are controlled by fluid viscosity and geometric P-1-M-7100 factor (pipe diameter and roughness) and normally accounts for around 10 % of overall head losses.
2.4.4
1.5.
The gravitational component accounts for around 90 % of the overall P-1-M-7100 head losses and is proportional to the density of the fluid mixture at each point in the tubing and is a complex function of the relative velocity of the phases present.
2.4.4
1.6.
The geometrical distribution of the gas and liquid in the pipe P-1-M-7100 constitute the “flow pattern” or “flow regime”. The flow patterns are governed by the flow rates of each phase, the tubing diameter and to a lesser extent PVT fluid properties.
2.4.4
1.7.
Flow patterns are identified using empirical flow pattern maps. Each flow regime has different pressure gradients that should be calculated by the use of different empirical correlation for liquid hold-up and friction factor.
1.8.
Typical pressure gradients in wells for different flow patterns are: • • • •
Single phase oil Bubble flow Slug flow Mist flow
= = = =
0.36psi/ft 0.25psi/ft 0.20psi/ft 0.1 - 0.2psi/ft
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2. TEMPERATURE GRADIENT The temperature profile shall be considered in the outflow 2.1. performance calculation.
Reference
2.2.
Computer calculation should be performed to predict both steady state or transient temperature changes overtime.
2.3.
A temperature prediction method shall be always validated with measured data.
2.4.
Some wells have produced fluids with special properties that are very P-1-M-7100 sensitive to temperatures and more complex heat transfer calculations are required. These are: • • •
2.4.4
Gas condensate wells with retrograde condensate. High pour point crude oil wells. Wells in which hydrate formation can occur.
3. PVT DATA CALCULATION Due to the complexity of the relationship between pressure and 3.1. temperature drop in wells and PVT behaviour all calculation shall be performed 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 accurately predict 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.
3.4.2.2.
Water salinity.
3.4.2.3.
Separator condition (P&T).
3.4.2.4.
Condensate/Gas ratio.
3.4.2.5.
Water/Gas ratio.
3.4.3.
Retrograde condensate
3.4.3.1.
Separator condition (P&T).
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.
3.4.3.8.
Water salinity.
4. PVT PARAMETERS TO BE MATCHED For a best fluid properties prediction FLASH PVT data shall be 4.1. matched. 4.2.
If only Differential liberation PVT data is available it shall be corrected to 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 After that a solid PVT table is obtained the TBG performance shall be 5.1. calculated. 5.2.
Several correlations for predicting pressure gradients in oil wells are available. Validation with actual field data is the only reliable method for choosing the best correlation for a particular case and within a particular range of fluids rate.
5.3.
Try to get more than a flowing gradient at different flow rate from well testing.
5.4.
Do not tune calculated value with measured data by changing the TBG 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 not consider operating point (intersection IPR/TCP) on the left of the minimum of the curve to avoid instability.
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Reference 6. LIMITS 2.4.4 In gas wells, liquid loading can also be predicted using simplified P-1-M-7100 6.1. methods presented with Turner et al which are independent of pressure drop calculations. These methods have been reviewed by Lea and Tighe. For wells producing high gas-water or gascondensate ratios, it is recommended that tubing size be assessed using these methods in addition to lift curve methods and that the most conservative approach be adopted.
6.2.
Erosion in completions occurs when there are high velocities and if P-1-M-7100 there are solids particles in the flow stream. The most common points for erosion is where there are restrictions that cause increased velocities. The API have published a method in API RP 14E, to determine the threshold velocities for erosion to occur in piping systems but the validity of this for all conditions is questionable.
6.3.
The choice of the optimum tubing size should be taken into account the 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 the clearance CSG / TBG in order to be able to washover and fish a broken tubing by standard overshot.
7. OPTIMUM TBG SIZE THROUGH FIELD LIFE Optimum TBG size should change with changing reservoir condition 7.1. and 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.
2.4.4
Reference
Reference list: ‘Completion Design Manual’
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STRESS ANALYSIS
Reference 1. GENERAL 7.1 All completion tubing strings will have tubing movement calculations P-1-M-7100 1.1. conducted to ascertain the maximum load applied to the string and/or completion tubing movement to be catered for in the completion design.
All tubing strings should be designed for stress, preferably using an appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WSTube programme to the latest version. 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 actual axial force and the force that causes the same outer fiber stress that is induced by the curvature due to buckling and hole doglegs.
1.4.
Hoop and radial stresses shall be computed using Lame’s formulas at the 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 the worst stress conditions have been identified.
Reference 2. PARAMETERS 7.2 During completion tubing design process, it is necessary to calculate P-1-M-7100 2.1. the variations in length for the stresses applied under load conditions. When these have been determined it will confirm the suitability of the selected 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) to P-1-M-7100 produce an accurate tubing movement/stress analysis and, hence, selection of a tubing are: • • • • • • • •
2.3.
7.3
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.
Movement can only occur if the tubing is free to move. If the tubing is P-1-M-7100 not free to move and is anchored to a packer then stress will be subjected to the tubing string and packer.
7.2
Tubing movement upward (contraction) is assumed to be negative and downward (lengthening) is positive. 2.4.
The optimum tubing size, determined by nodal analysis conducted by P-1-M-7100 the reservoir engineers, is required and is the basis of all the calculations.
7.3.2
The tubing movement/stress calculations will then determine the tubing weight or any change in grade required to meet with the applied SF for stress. 2.5.
Bottom-hole Pressure:
P-1-M-7100
7.3.3
P-1-M-7100
7.3.4
Accurate initial and prognosed future formation pressures both static and dynamic are fundamental to tubing movement/stress calculations. These pressures can be obtained from previous well exploration test data or appraisal well test reports. 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 causes the greatest tubing movement.
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2.7.
Temperature changes cause expansion and contraction in metals, P-1-M-7100 which is a significant factor in tubing strings. All metals have a particular expansion rate that is termed the ‘Co-efficient of thermal expansion’.
7.2.2
The co-efficient of liner expansion for tubular steels is usually 6.9 x -6 10 in/in/F°. 2.8.
When a well is completed, either with a tubing seal unit in a packer P-1-M-7100 bore or a tubing movement device, it will have completion fluid in both the tubing and the annulus, this is referred to as the initial condition. All subsequent conditions are calculated from this initial condition.
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 the operational parameters.
2.10.
Production operations normally yield tubing elongation’s and injection operations normally yields tubing contractions.
2.11.
Usually injection or cold operations are the most critical for the stress behaviour.
7.4
Reference 3. CALCULATION METHOD 7.10 For each operation the tubing movement and the relevant stresses P-1-M-7100 3.1. shall be calculated as per the method described in the AGIP procedure.
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 any changes in material, tubing OD, tubing ID, casing ID, internal fluid level, 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 an P-1-M-7100 appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WSTube programme to the latest version.
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Reference 4. SAFETY FACTOR 7.10.2 A completion string’s safety factor is defined as the ratio between the P-1-M-7100 4.1. yield stress and the maximum value of the stress obtained.
4.2.
Carbon and CRA Steels up to 13%Cr
P-1-M-7100
7.10.2
4.3.
• The acceptable SF for these types of materials is: 1.25 Cold Worked (CW) CRA Steels
P-1-M-7100
7.10.2
4.4.
The acceptable SF for these types of materials which include duplex, super-austenitic and Incoloy is: 1.35 P-1-M-7100 Uniaxial and biaxial safety factor
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 5.1. Minimum operational cases to be evaluate
Reference
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 P-1-M-7100
7.7.4 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 yields material’s stress greater than the minimum accepted one, changes in the operating procedure shall be investigated prior to change the best tubing 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 that make the tubing buckle into a helix.
5.3.2.
The pitch of the helix shall be calculated to make prevision of free passage of tools.
5.3.3.
Applied casing pressure can reduce this buckling effect and straight the tubing reducing wire line or coiled TBG overpulling.
5.3.4.
Applied casing pressure must balance the effect of reducing buckling and the increasing of compression and packer loads.
Reference 6. TBG - PACKER INTERACTIONS P-1-M-7100 7.5 With free moving packer/tubing seals systems, the calculations are 6.1. made for the selection of an appropriate length of seal assembly, PBR or ELTSR with anchored packer/tubing systems.
6.2.
In some completions the tubing is firmly fixed to the packer, P-1-M-7100 preventing any movement of the string when well conditions vary. In this situation the tubing-packer forces generated by the presence of the anchoring must be determined so as to be able to confirm if the tubing-packer anchoring system and the packer have sufficient strength to safely withstand all the forces exerted.
6.3.
The packer shall withstand the force imposed by the tubing movement and the differential pressure.
6.4.
When available the use of Packer Envelopes is suggested to insure the packer works within the design limits.
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7. TUBING MECHANICAL PROPERTIES 7.1. Mechanical properties that must be considered
Reference
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 be considered when anisotropic material is used.
7.3.
When reduction in tubing thickness is expected due to corrosion the expected final tubing thickness shall be also considered.
7.4.
The connections to be used shall be qualified according to the M-1-M-5006 requirements as set in the Eni-Agip Division and Affiliates procedure P-1-M-7100 ‘Connection Procedure Evaluation’. • •
7.9.1
The use of premium connections for tubing is mandatory. The use of premium connections for production casing is advised but not mandatory.
Reference List: ‘Completion Design Manual’
STAP-P-1-M-7100
‘Test Procedure for Connection Evaluation’
STAP M-1-M-5006
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MATERIAL SELECTION
Reference 1. CORROSION GENERAL 7.8.1 In general, the ideal material is determined by the results of corrosion P-1-M-7100 1.1. studies carried out prior to the tubing design stage, especially when the severity of the conditions suggest the use of expensive CRA materials.
1.2.
The existence, if any, of the following conditions alone, or in any P-1-M-7100 combination may be a contributing factor to the initiation and perpetuation of corrosion:
6.2
1.2.1.
Oxygen (O2):
P-1-M-7100
6.2
P-1-M-7100
6.2
P-1-M-7100
6.2
Oxygen dissolved in water drastically increases its corrosivity potential. 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. 1.2.2.
Hydrogen Sulphide (H2S): Hydrogen sulphide is very soluble in water and when dissolved behaves 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 alone and is frequently found in oilfield environments. Other serious problems which may result from H2S corrosion are hydrogen blistering and sulphide stress cracking. It should be pointed out that H2S also can be generated by introduced micro-organisms.
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 as corrosive as oxygen, but usually also results in pitting. The important factors governing the solubility of carbon dioxide are pressure, temperature and composition of the water. Pressure increases the solubility to lower the pH, temperature decreases the solubility to raise the pH. Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’ corrosion.
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1.2.4.
Temperature:
P-1-M-7100
6.2
P-1-M-7100
6.2
P-1-M-7100
6.2
Like most chemical reactions, corrosion rates generally increase with increasing temperature. 1.2.5.
Pressure Pressure affects the rates of chemical reactions and corrosion reactions are no exception. In oilfield systems, the primary importance of pressure is its effect on dissolved gases. More gas goes into solution as the pressure is increased this may in turn increase the corrosivity of the solution.
1.2.6.
Velocity of fluids within the environment: Stagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as the corrosion scale is removed from the casing exposing fresh metal for further corrosion. High velocities and/or the presence of suspended solids or gas bubbles can lead to erosion, corrosion, impingement or cavitation.
1.3.
Corrosion cell minimum environment
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 electrochemical process occurs between an anode area which loose material and a cathode 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, when in contact with pure iron, will form a cell and become the cathode thus causing the anode to corrode.
1.6.
The formation of scale in isolated areas can lead to a corrosion cell being formed. Bacteria, especially slime forming bacteria, can cause corrosion cells to form if only isolated areas are covered.
1.7.
The use of different metals in contact is an obvious way to cause a corrosion cell.
1.8.
Water effect
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1.9.
Sulphide Stress Cracking (SSC)
P-1-M-7100
6.3.1
1.9.1.
The SSC phenomenon occurs usually at temperatures of below 80°C P-1-M-7100 and with the presence of stress in the material. The H2S comes into contact 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 temperature gradients is very useful in the choice of the tubular materials since differing materials can be chosen for various depths.
6.3.1
Evaluation of the SSC problem depends on the type of well being investigated. In gas wells, gas saturation with water will produce condensate water and therefore create the conditions for SSC. In oil wells, two separate cases need to be considered, vertical and deviated wells: 1.9.2.
In vertical oil wells, generally corrosion occurs only when the water P-1-M-7100 cut becomes higher than 15% which is the ‘threshold’ or commonly defined as the ‘critical level’ and it is necessary to analyse the water cut profile throughout the producing life of the well.
6.3.1
1.9.3.
o In highly deviated wells (i.e. deviations >80 ), the risk of corrosion by P-1-M-7100 H2S is higher since the water, even if in very small quantities, deposits on the surface of the tubulars and so the problem can be likened to the gas well case where the critical threshold for the water cut drops to 1% (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 predict P-1-M-7100 corrosion, 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
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1.9.7.
The problem of carbon dioxide attack is much worse in gas production than in oil production. In the oil tubular the surface of the steel may be protected by the oil flowing through it. In gas production droplets of saline water will accumulate on the surface of the steel, resulting in small anodes and large cathode causing rapid localised corrosion.
1.10.
Hydrogen sulphide
1.10.1.
Hydrogen sulphide is soluble in water and acts as a weak acid producing iron sulphide which is cathodic to steel that corrode and tends to form a scale on steel thus further promoting the corrosion reaction.
1.10.2.
Free hydrogen is generated by the reaction that may enter the steel structure causing embrittlement. Low hardness material (22 HRC max) shall be used where this phenomena can occur.
1.11.
Stress corrosion cracking
1.11.1.
Hydrogen sulphide and a tensile stress can act in concert to provide cracks in a susceptible material in particular environment. This form of attack is named stress corrosion cracking (SCC). The tensile stress can be residual, applied or a combination of the two. The important factor in stress corrosion cracking which makes this form of attack so damaging, is that cracks propagate at much lower values of stress than would cause failure if the corrodent was not present. Stress corrosion cracking can occur in a system which previously has not shown no sign of any corrosion problem, if the operating condition are changed.
1.11.2.
The susceptibility to SSC decrease with increasing pH. This decrease starts at a pH of approximately 6 and above a pH of 9.5 SSC generally 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 and depth.
1.11.4.
Stress corrosion cracking can occur also in presence of chloride or bromide ions, particularly in hot conditions. These ions can be present in formation water, injection water and brines used as completion, workover and packer fluids.
1.11.5.
Certain corrosion resistant alloys (CRA), especially austenitic stainless steel, are susceptible to stress corrosion cracking.
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STAP-P-1-M-6090 Reference 2. CORROSION CONTROL MEASURES P-1-M-7100 6.2 2.1. Corrosion control measures may involve the use of one or more of the following
2.1.1.
Control of the environment: • • • • • • • • •
2.1.2.
2.1.3.
P-1-M-7100
6.2
P-1-M-7100
6.2
Plastic coating Plating
Improvement of the corrosion resistivity of the steel: •
6.2
pH Temperature Pressure Chloride concentration CO2 concentration 2 H S concentration 2 H O concentration Flow rate Inhibitors
Surface treatment: • •
P-1-M-7100
Addition of the alloying elements micro structure
2.2.
Corrosion Inhibitors
P-1-M-7100
6.5
2.2.1.
An inhibitor is a substance which retards or slows down a chemical P-1-M-7100 reaction. Thus, a corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environmental on a metal.
6.5
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 oil and gas wells: • • • • • •
Batch treatment (tubing displacement, standard batch, extended batch) Continuous treatment Squeeze treatment Atomised inhibitor squeeze - weighted liquids Capsules Sticks.
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2.3.
Coating
2.3.1.
Coating prevents contact of the metal by corrosive fluids. Internally coating tubing, however, is relatively expensive and has several disadvantages.
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 is not coated
2.3.5.
Coated tubing does not eliminate the need to protect trees and flowlines.
2.4.
Gas removal
2.4.1.
Removal of corrosive gases has most application in water injection systems. Even 1 ppm dissolved oxygen corrodes steel several times faster 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 accordance with 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 cheapest method to manage corrosion because of their resistance that may reduce the needs of workover and the risk associated with a failed completion
Reference 3. MATERIAL SELECTION 6.8 The material selection of tubing shall be made upon the following P-1-M-7100 3.1. diagram:
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100 pCO2 (atm)
10
1
FBHT
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