eni - drilling design manual

ARPO

ENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 230STAP P 1 M 6100

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

TITLE

DRILLING DESIGN MANUAL

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 aCD-Rom version can also be distributed (requests will be addressed to STAP Dept. inEni - Agip Division Headquarter)

Date of issue:

�

�

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� Issued by P. MagariniE. Monaci

C. Lanzetta A. Galletta

28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99

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IDENTIFICATION CODE PAGE 2 OF 230

REVISIONSTAP-P-1-M-6100 0

INDEX

1. INTRODUCTION 9

1.1. PURPOSE AND OBJECTIVES 9

1.2. IMPLEMENTATION 9

1.3. UPDATING, AMENDMENT, CONTROL& DEROGATION 9

2. PRESSURE EVALUATION 10

2.1. FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS 10

2.2. OVERPRESSURE EVALUATION 112.2.1. Methods Before Drilling 122.2.2. Methods While Drilling 122.2.3. Real Time Indicators 132.2.4. Indicators Depending on Lag Time 142.2.5. Methods After Drilling 16

2.3. TEMPERATURE PREDICTION 192.3.1. Temperature Gradients 202.3.2. Temperature Logging 20

3. SELECTION OF CASING SEATS 21

3.1. CONDUCTOR CASING 24

3.2. SURFACE CASING 24

3.3. INTERMEDIATE CASING 24

3.4. DRILLING LINER 25

3.5. PRODUCTION CASING 25

4. CASING DESIGN 26

4.1. INTRODUCTION 26

4.2. PROFILES AND DRILLING SCENARIOS 274.2.1. Casing Profiles 27

4.3. CASING SPECIFICATION AND CLASSIFICATION 284.3.1. Casing Specification 284.3.2. Classification Of API Casing 29

4.4. MECHANICAL PROPERTIES OF STEEL 294.4.1. General 294.4.2. Stress-Strain Diagram 29

4.5. NON-API CASING 31

4.6. CONNECTIONS 324.6.1. API Connections 32

4.7. APPROACH TO CASING DESIGN 334.7.1. Wellbore Forces 334.7.2. Design Factor (DF) 344.7.3. Design Factors 35

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4.7.4. Application of Design Factors 35

4.8. DESIGN CRITERIA 364.8.1. Burst 364.8.2. Collapse 394.8.3. Tension 42

4.9. BIAXIAL STRESS 434.9.1. Effects On Collapse Resistance 434.9.2. Company Design Procedure 454.9.3. Example Collapse Calculation 46

4.10. BENDING 474.10.1. General 474.10.2. Determination Of Bending Effect 474.10.3. Company Design Procedure 494.10.4. Example Bending Calculation 50

4.11. CASING WEAR 524.11.1. General 524.11.2. Volumetric Wear Rate 534.11.3. Wear Factors 554.11.4. Wear Allowance In Casing Design 564.11.5. Company Design Procedure 57

4.12. SALT SECTIONS 584.12.1. Company Design Procedure 59

4.13. CORROSION 604.13.1. Exploration And Appraisal Wells 604.13.2. Development Wells 604.13.3. Contributing Factors To Corrosion 614.13.4. Casing For Sour Service 634.13.5. Ordering Specifications 634.13.6. Company Design Procedure 64

4.14. TEMPERATURE EFFECTS 684.14.1. Low Temperature Service 68

4.15. LOAD CONDITIONS 694.15.1. Safe Allowable Pull 694.15.2. Cementing Considerations 694.15.3. Pressure Testing 704.15.4. Company Guidelines 704.15.5. Hang-Off Load (LH) 71

5. MUD CONSIDERATIONS 72

5.1. GENERAL 72

5.2. DRILLING FLUID PROPERTIES 725.2.1. Cuttings Lifting 725.2.2. Subsurface Well Control 735.2.3. Lubrication 745.2.4. Bottom-Hole Cleaning 745.2.5. Formation Evaluation 745.2.6. Formation Protection 74

5.3. MUD COMPOSITION 755.3.1. Salt Muds 755.3.2. Water Based Systems 785.3.3. Gel Systems 795.3.4. Polymer Systems 79

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5.3.5. Oil Based Mud 80

5.4. SOLIDS 80

5.5. DENSITY CONTROL MATERIALS 81

5.6. FLUID CALCULATIONS 81

5.7. MUD TESTING PROCEDURES 84

5.8. MINIMUM STOCK REQUIREMENTS 85

6. FLUID HYDRAULICS 87

6.1. HYDRAULICS PROGRAMME PREPARATION 87

6.2. DESIGN OF THE HYDRAULICS PROGRAMME 88

6.3. FLOW RATE 88

6.4. PRESSURE LOSSES 906.4.1. Surface Equipment 936.4.2. Drill Pipe 936.4.3. Drill Collars 936.4.4. Bit Hydraulics 936.4.5. Mud Motors 946.4.6. Annulus 94

6.5. USEFUL TABLES AND CHARTS 95

7. CEMENTING CONSIDERATIONS 97

7.1. CEMENT 977.1.1. API Specification 977.1.2. Slurry Density and Weight 100

7.2. CEMENT ADDITIVES 1027.2.1. Accelerators 1027.2.2. Retarders 1037.2.3. Extenders 1037.2.4. Weighting Agents 104

7.3. SALT CEMENT 105

7.4. SPACERS AND WASHES 106

7.5. SLURRY SELECTION 107

7.6. CEMENT PLACEMENT 108

7.7. WELL CONTROL 108

7.8. JOB DESIGN 1107.8.1. Depth/Configuration 1107.8.2. Environment 1117.8.3. Temperature 1117.8.4. Slurry Preparation 111

8. WELLHEADS 112

8.1. DEFINITIONS 112

8.2. DESIGN CRITERIA 1128.2.1. Material Specification 112

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8.3. SURFACE WELLHEADS 1138.3.1. Standard Wellhead Components 1138.3.2. National/Breda Wellhead Systems 113

8.4. COMPACT WELLHEAD 116

8.5. MUDLINE SUSPENSION 119

9. PRESSURE RATING OF BOP EQUIPMENT 122

9.1. BOP SELECTION CRITERIA 122

10. BHA DESIGN AND STABILISATION 125

10.1. STRAIGHT HOLE DRILLING 125

10.2. DOG-LEG AND KEY SEAT PROBLEMS 12510.2.1. Drill Pipe Fatigue 12510.2.2. Stuck Pipe 12610.2.3. Logging 12610.2.4. Running casing 12610.2.5. Cementing 12610.2.6. Casing Wear While Drilling 12610.2.7. Production Problems 126

10.3. HOLE ANGLE CONTROL 12810.3.1. Packed Hole Theory 12810.3.2. Pendulum Theory 129

10.4. DESIGNING A PACKED HOLE ASSEMBLY 12910.4.1. Length Of Tool Assembly 12910.4.2. Stiffness 12910.4.3. Clearance 13110.4.4. Wall Support and Length of Contact Tool 131

10.5. PACKED BOTTOM HOLE ASSEMBLIES 131

10.6. PENDULUM BOTTOM HOLE ASSEMBLIES 133

10.7. REDUCED BIT WEIGHT 134

10.8. DRILL STRING DESIGN 135

10.9. BOTTOM HOLE ASSEMBLY BUCKLING 138

10.10.SUMMARY RECOMMENDATIONS FOR STABILISATION 140

10.11.OPERATING LIMITS OF DRILL PIPE 142

10.12.GENERAL GUIDELINES 142

11. BIT SELECTION 143

11.1. PLANNING 143

11.2. IADC ROLLER BIT CLASSIFICATION 14311.2.1. Major Group Classification 14411.2.2. Bit Cones 145

11.3. DIAMOND BIT CLASSIFICATION 14611.3.1. Natural Diamond Bits 14611.3.2. PDC Bits 14611.3.3. IADC Fixed Cutter Classification 146

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11.4. BIT SELECTION 14811.4.1. Formation Hardness/Abrasiveness 14811.4.2. Mud Types 14911.4.3. Directional Control 14911.4.4. Drilling Method 15011.4.5. Coring 15011.4.6. Bit Size 150

11.5. CRITICAL ROTARY SPEEDS 150

11.6. DRILLING OPTIMISATION 152

12. DIRECTIONAL DRILLING 153

12.1. TERMINOLOGY AND CONVENTIONS 153

12.2. CO-ORDINATE SYSTEMS 15512.2.1. Universal Transverse Of Mercator (UTM) 15512.2.2. Geographical Co-ordinates 156

12.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 15812.3.1. Horizontal Displacement 15812.3.2. Target Direction 15912.3.3. Convergence 159

12.4. HIGH SIDE OF THE HOLE AND TOOL FACE 16012.4.1. Magnetic Surveys 16112.4.2. Gyroscopic Surveys 16312.4.3. Survey Calculation Methods 16512.4.4. Drilling Directional Wells 16712.4.5. Dog Leg Severity 172

13. DRILLING PROBLEM PREVENTION MEASURES 173

13.1. STUCK PIPE 17313.1.1. Differential Sticking 17413.1.2. Sticking Due To Hole Restrictions 17513.1.3. Sticking Due To Caving Hole 17613.1.4. Sticking Due To Hole Irregularities And/Or Change In BHA 178

13.2. OIL PILLS 17913.2.1. Light Oil Pills 17913.2.2. Heavy Oil Pills 17913.2.3. Acid Pills 180

13.3. FREE POINT LOCATION 18113.3.1. Measuring The Pipe Stretch 18113.3.2. Location By Free Point Indicating Tool 18213.3.3. Back-Off Procedure 182

13.4. FISHING 18313.4.1. Inventory Of Fishing Tools 18313.4.2. Preparation 18313.4.3. Fishing Assembly 184

13.5. FISHING PROCEDURES 18413.5.1. Overshot 18413.5.2. Releasing Spear 18413.5.3. Taper Taps 18513.5.4. Junk basket 18513.5.5. Fishing Magnet 185

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13.6. MILLING PROCEDURE 186

13.7. JARRING PROCEDURE 187

14. WELL ABANDONMENT 189

14.1. TEMPORARY ABANDONMENT 18914.1.1. During Drilling Operations 18914.1.2. During Production Operations 189

14.2. PERMANENT ABANDONMENT 19014.2.1. Plugging 19014.2.2. Plugging Programme 19014.2.3. Plugging Procedure 191

14.3. CASING CUTTING/RETRIEVING 19214.3.1. Stub Termination (Inside a Casing String) 19214.3.2. Stub Termination (Below a Casing String) 192

15. WELL NAME/DESIGNATION 193

15.1. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND TARGET 19315.1.1. Vertical Well 19315.1.2. Side Track In A Vertical Well. 19315.1.3. Directional Well 19415.1.4. Side Track In Directional Well 19415.1.5. Horizontal Well 19415.1.6. Side Track In A Horizontal Well 194

15.2. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND DIFFERENT TARGETS 195

15.3. WELLS WITH DIFFERENT WELL HEAD CO-ORDINATES AND SAME ORIGINAL TARGETS197

15.4. FURTHER CODING 198

16. GEOLOGICAL DRILLING WELL PROGRAMME 200

16.1. PROGRAMME FORMAT 200

16.2. IDENTIFICATION 200

16.3. GRAPHIC REPRESENTATIONS 200

16.4. CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME 20116.4.1. General Information (Section 1) 20116.4.2. Geological Programme (Section 2) 20716.4.3. Operation Geology Programme (Section 3) 20816.4.4. Drilling Programme (Section 4) 209

17. FINAL WELL REPORT 210

17.1. GENERAL 210

17.2. FINAL WELL REPORT PREPARATION 210

17.3. FINAL WELL OPERATION REPORT STRUCTURE 21117.3.1. General Report Structure 21117.3.2. Cluster/Platform Final Well Report Structure 212

17.4. AUTHORISATION 213

17.5. ATTACHMENTS 213

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APPENDIX A - REPORT FORMS 214

A.1. INITIAL ACTIVITY REPORT (ARPO 01) 215

A.2. DAILY REPORT (ARPO 02) 216

A.3. CASING RUNNING REPORT (ARPO 03) 217

A.4. CASING RUNNING REPORT (ARPO 03B) 218

A.5. CEMENTING JOB REPORT (ARPO 04A) 219

A.6. CEMENTING JOB REPORT (ARPO 04B) 220

A.7. BIT RECORD (ARPO 05) 221

A.8. WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06) 222

A.9. WELL PROBLEM REPORT (ARPO 13) 223

APPENDIX B - ABBREVIATIONS 224

APPENDIX C - WELL DEFINITIONS 228

APPENDIX D - BIBLIOGRAPHY 230

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1. INTRODUCTION

1.1. PURPOSE AND OBJECTIVES

The purpose of the Drilling design Manual is to guide experienced technicians andengineers involved in Eni-Agip’s in the production of well design/studies and in the planningof well operations world-wide, using the Manuals & Procedures and the TechnicalSpecifications which are part of the Corporate Standards. This encompasses theforecasting of pressure and temperature gradients through casing design to the compilationof the Geological Drilling Programme and Final Well Report.

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

The final aim is to improve performance and efficiency in terms of safety, quality and costs,while providing all personnel involved in Drilling & Completion activities with commonguidelines in all areas worldwide where Eni-Agip operates.

The objectives are to provide the drilling engineers with a tool to guide them through thedecision making process and also arm them with sufficient information to be able to planand prepare well drilling operations and activities in compliance with the CorporateCompany principles. Planning and preparation will include the drafting of well specificprogrammes for approval and authorisation.

1.2. IMPLEMENTATION

The guidelines and policies specified herein will be applicable to all of Eni-Agip Division andAffiliates drilling engineering activities.

All engineers engaged in Eni-Agip Division and Affiliates drilling design activities areexpected to make themselves familiar with the contents of this manual and be responsiblefor compliance to its policies and procedures.

1.3. UPDATING, AMENDMENT, CONTROL& DEROGATION

This manual is a ‘live’ controlled document and, as such, it will only be amended andimproved by the Corporate Company, in accordance with the development of Eni-AgipDivision and Affiliates operational experience. Accordingly, it will be the responsibility ofeveryone concerned in the use and application of this manual to review the policies andrelated procedures on an ongoing basis.

Locally dictated derogations from the manual shall be approved solely in writing by theManager of the local Drilling and Completion Department (D&C Dept.) after theDistrict/Affiliate Manager and the Corporate Drilling & Completion Standards Department inEni-Agip Division Head Office have been advised in writing.

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

Feedback for manual amendment is also gained from the return of completed ‘Feedbackand Reporting Forms’ from drilling, well testing and workover operations, refer to AppendixA.

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2. PRESSURE EVALUATION

2.1. FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS

A well programme must contain a technical analysis including graphs of pressure gradients(overburden, pore, fracture) and temperature gradient.

The following information must be included in the analysis:

a) Method for calculating the Overburden Gradient, if obtained from electric logsof reference wells or from seismic analysis.

b) Method for defining the Pore Pressure Gradient, if obtained from data (RFT,DST, BHP gauges, production tests, electric logs, Sigma logs, D exponent) ofreference wells or from seismic analysis.

c) Formula used to derive the Fracture Gradient.

d) Source used to obtain the Temperature Gradient.

The formulas normally used to calculate the Overburden Gradient are:

H28.3

1000PiPt

∆××

=∆

200t

47t228.1D

+∆−∆

=

10hD

Hi10

Gov∆×

∑=

where:

PiP = Numbers of ηsecond (calculated from sonic log for regularly depthinterval, i.e. every 50/100/200m)

∆t = Transit time (second 10-3)

D = Density of the formation

Gov = Overburden gradient

∆H = Formation interval with the same density D

Hi = Total depth (Σ ∆H)

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Equations used by ENI Agip division for fracture gradient calculation, (when overburdengradients and pore pressure gradients have been defined), are listed below:

Terzaghi equation (commonly used):

)GG(12

GG povpf −ν−

ν+=

When the formation is deeply invaded with water:

)GG(2GG povpf −ν+=

When the formation is plastic:

ovf GG =

where:

Gf = Fracture pressure

Gov = Overburden gradient

Gp = Formation pressure

v = Poissions modulus

when Poisson’s modulus may have the following values:

ν = 0.25 for clean sands, sandstone and carbonate rocks down to mediumdepth

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

2.2. OVERPRESSURE EVALUATION

There are three methods of qualitative and quantitative assessment of overpressure:

a) Methods before drilling

b) Methods while drilling

c) Methods after drilling.

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2.2.1. Methods Before Drilling

Gradients prediction is based, on the most part, analysis and processing of seismic dataand data obtained from potential reference wells. This includes:

Drilling Records These can be used in determining hole problems, abnormalpressures, lost circulation zones, required mud weights andproperties, etc.

Wireline Logs These can provide useful geological information such aslithology, formations tops, bed thicknesses, dips, faults, washout, lost circulation zones, formation fluid content andformation fluid pressure (pore pressure).

Seismic Surveys Provides two of the most important applications of seismicdata in; the detection of formations characterised by abnormalpressures and; in the forecasting of probable pressuregradient. The data from seismic surveys are analysed andinterpreted to evaluate transit times and propagation velocityfor each interval in the formation. Since overpressurisedzones have a porosity higher than normal, it is reflected in atravel time increase.

It is obvious that if the drilling is explorative and is the first wellin a specific area, the seismic data analysis may be the solesource of information available.

The prediction of the gradients is essential for planning thewell and must be included in the drilling programme.

This initial drilling phase may be able to detect zones ofpotential risk but cannot guarantee against the potentialpresence and magnitude of abnormal pressures and, hencecaution must be exercised.

2.2.2. Methods While Drilling

Given all the predictive methods available, successful drilling still depends on theeffectiveness of the methods adopted and on the way they are used in combination.Although most of these methods do not provide the actual overpressure picture, they dosignal the presence of an abnormal conditions due to the existence of an abnormallybehaving zone. Such methods, therefore, provide a warning that a more careful and diligentobservation must be maintained on the well.

The most critical situation occurs when a well with normal gradient penetrates a highpressure zone without any indications caused by faulting or outcropping at a higherelevation. However, when abnormal pressure occurs as a result of compaction only, manyof the following real time indicators appears before a serious problem develops.

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2.2.3. Real Time Indicators

Penetration Rate While drilling in normal pressured shales of a well, there willbe a uniform decrease in the drilling rate due to the increasein shale density. When abnormal pressure is encountered, thedensity of the shale is decreased with a resultant increase inporosity. Therefore, the drilling rate will gradually increase asthe bit enters an abnormal pressured shale. The corrected ‘d’exponent and Eni-Agip Sigmalog eliminate the effects ofdrilling parameter variations and give a representativemeasure of formation drillability.

The TDC Engineer is responsible for continuous monitoringand shall immediately report to the Company Drilling andCompletion Supervisor, if any change occurs.

A copy of corrected the ‘d’ exponent or Agip Sigmalog shallbe sent on daily basis to the Company’s Shore Base DrillingOffice by telefax for further checking.

Drilling Break A drilling break is defined as a rapid increase in penetrationrate after a relatively long interval of slow drilling.

Any time a drilling break is noticed, drilling shall be suspendedand a flow check carried out. If there is any lingering doubt,the hole will be circulated out until bottoms up.

Torque Torque sometimes increases when an abnormally pressuredshale section is penetrated due to the swelling of plastic claycausing a decrease in hole diameter and/or accumulation oflarge cuttings around the bit and the stabilisers.

Also torque is not easy to interpret in view of manyphenomena which can affect it (hole geometry, deviation,bottom hole assembly, etc.), it must be thought as thesecond-order parameter for diagnosing abnormal pressure.

Tight Hole DuringConnections

Tight hole when making connections can indicate that anabnormal pressured shale is being penetrated with low mudweight. When this occurs it is confirmed when the hole mustbe reamed several times before a connection can be made.

Hole Fill When making up connections, cavings may settle preventingthe bit returning to bottom.

Wall instability, in an area of abnormal pressure, may causesloughing. It should be noted that fill may be due to othercauses, such as wall instability through geomechanicalreasons (fracture zones), inefficient well cleaning by thedrilling mud, rheological properties of mud insufficient to keepcuttings in suspension, etc.

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MWD In addition to directional drilling data, MWD can provide a widerange of bottom hole drilling parameters and formationevaluation, e.g.: bottomhole weight on bit, torque at bit,gamma ray, mud and formation resistivity, mud pressure andmud temperature.

If the true weight and torque at the bit are known, the drillingrate can be normalised with more accuracy by producing amore accurate ‘d’ exponent and Agip Sigmalog.

Formation resistivity is plotted and interpreted for pressuredevelopment. It should also be noted that differential resistivitybetween the mud in the drill pipe and in the annular spacemay be considered as a kick indicator.

Bottomhole mud temperature can also be an indicator of overpressure as discussed below.

2.2.4. Indicators Depending on Lag Time

Mud Gas The monitoring and interpretation of gas data are fundamentalto detecting abnormally pressured zones.

• Background gas is the gas released by the formation whiledrilling. It usually is a low but steady level of gas in the mudwhich may be interrupted by higher levels resulting fromthe drilling of a hydrocarbon bearing zone or from trips andconnections.

• An increase in the level of background gas, from thatpreviously found in overlying normally compacted shales,often occurs when drilling undercompacted formations.

• Gas shows can occur when porous, permeable formationscontaining gas are penetrated. Monitoring the form and thevolume of gas shows will make it easier to detect a state ofnegative differential pressure.

• Trip gas may be an indication of well underbalance. Theequivalent density applied to the formation with pumps off(static) is lower than the equivalent circulating density(dynamic) and when the well is close to balance point, thedrop in pressure while static may allow gas to flow from theformation into the well. The quantity of gas observed at thesurface when circulation is resumed, however will dependon several factors, e.g., differential pressure, formationpermeability, drill pipe pulling speed, swabbing. Failure tofill the hole on trips may also cause an increase in trip gas.

• Connection gas may be an indication of well imbalance(see above).

• The progressive changes, or trend, in connection gases isan important aid to evaluate differential pressure. When anundercompacted zone of uniform shale is drilled withoutincreasing the mud weight, the amount of connection gaswill almost always increase.

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Mud Temperature Measurement of mud temperature can also be used to detectundercompacted zones and, under ideal conditions, or toanticipate their approach. This is because temperaturegradients observed in undercompacted series are, in general,abnormally high compared with overlying normally pressuredsequences.

Accurate interpretation of these data is very difficult, due to anumber of variables which frequently mask changes ingeothermal gradient:

• Inflow temperature, which is dependent on the amount ofcooling at surface.

• Flow rate, which affects the speed at which the mud, andthe calories it contains, returns up the annulus.

• Thermophysical properties of the mud.• Heating effects at the bit face.• Heat exchange in the marine riser between the mud and

the sea.• Halts in drilling and/or circulation.• Surface operations such as transfer of mud between pits,

etc. Cutting Analysis • Lithology: the lithological sequence may provide an overall

indication of the possible existence of abnormal pressure.The presence of seals, drains or thick clay sequences is adetermining factor in this analysis.

• Shale density: is based on the principle that bulk density inan undercompacted zone does not follow the trend of thenormally compacted overlying clays and shales. Thevalidity of the density obtained depends on the claycomposition (the presence of accessory heavy mineralscan greatly change the density), the depth lagging (whichcan make cutting selection difficult), the mud type (reactivemuds have an adverse effect on measurement quality) andclay consolidation (difficult to measure on wellsite thedensity of clays not sufficiently consolidated).

• Shale factor: undercompacted clays which have beenunable to dehydrate often have an unusually highproportion of smectite and an abnormally high shale factor.However, the initial proportions of the clay minerals in thedeposit can mask changes in shale factor and give a falsealarm.

• Shape, size and volume of cuttings: the amount of shalecuttings will usually increase, along with a change in shape,when an abnormal pressure zone is penetrated.

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• Cuttings from normal pressured shales are small withrounded edges and are generally flat, while cuttings froman abnormal pressure are often long and splintered withangular edges. As the differential between the porepressure and the drilling fluid hydrostatic head is reduced,the pressured shales will burst into the wellbore rather thanhaving being drilled. This change in shape, along with anincrease in the amount of cuttings at the surface, could bean indication that abnormal pressure has beenencountered.

2.2.5. Methods After Drilling

These are methods founded on the elaboration of the data from electrical logs such as:induction log (IES), sonic log (SL), formation density log (FDC), neutron log (NL).

The most used methods for abnormal pressure detection are:

Induction Log (IES)Method:

Is used in sand and shale formations and consists in theplotting of the shale resistivity values at relative depths on asemilog graphic (depth in decimal scale and resistivity inlogarithmical scale).

In formations, if they are normal compacted, the resistivity ofthe shales increases with depth but, in overpressure zones, itlowers with depth increase (Refer to figure .2.a).

Also it is possible to plot the values of the shale conductibility;in this case the plot will be symmetric to that described above.The method is acceptable only in shale salt water bearingformations which have sufficient and a constant level ofsalinity.

For the calculation of gradient, refer to the ‘OverpressureEvaluation Manual’.

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Figure .2.A - Induction Log

Shale Formation Factor(Fsh) Method:

This is more sophisticated than the IES method describedabove. It eliminates the inconveniences due to water salinityvariation. It consists in the plotting of the shale factors on asemilog graph (depth in decimal scale and resistivity inlogarithmical scale)at relative depths. The ‘Fsh’ is calculatedby the following formula:

w

shsh

RR

F =

Where:

Rsht =The shale resistivity read on the log in the pointswhere they are most cleaned

Rw = The formation water resistivity reported in‘Schlumberger’s tables on the ‘log interpretationchart’.

The value of Fsh, increases with depth in normal compactionzones and lowers in overpressure zones (Refer to figure 2.b).

For the gradients calculation, the ‘Overpressure EvaluationManual’.

Fig.1,2-1INDUCTION LOG

1500

2000

2500

3000

3500

4000

4500

5000

1 10 100Resistivity (OHMM)

Top Overpresure

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Figure 2.B - ‘F’ Shale

Sonic Log (SL) Method: Also termed ‘∆t shale’, is the most widely used as, fromexperience, it gives the most reliability. It consists in theplotting, on a semilog graph (depth in decimal scale andtransit time in logarithmical scale) of the ∆t values (transit time)at relative depths.

The ∆t value (transit time) is read on sonic log in the shalepoints where they are cleanest; ∆t value lowers with the depthincrease in normal compaction zones and increases with thedepth in overpressure zones (Refer to figure 2.c)

For the calculation of gradient, refer to the ‘OverpressureEvaluation Manual’.

1500

2000

2500

3000

3500

4000

4500

5000

1 10 100F shale

Dep

th (

m)

Top Overpresure

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Figure 2.C Sonic log

2.3. TEMPERATURE PREDICTION

The temperature at various depths to which a well is drilled must be evaluated as it has agreat influence on the properties of both the reservoir fluids and materials used in drillingoperations.

The higher temperatures encountered at increasing depth usually have adverse effectsupon materials used in drilling wells but may be beneficial in production as it lowers theviscosity of reservoir fluids allowing freer movement of the fluids through the reservoir rock.

In drilling operations the treating chemicals materials and clays used in drilling mud becomeineffective or unstable at higher temperatures and cement slurry thickening and settingtimes accelerate (also due to increasing pressure).

Another effect of temperature is the lowering of the strength and toughness of materialsused in drilling and casing operations such as drillpipe and casing.

As technology improves and wells can be drilled even deeper, these problems becomemore prevalent.

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

10 100 1000

Dep

th (m

) Top Overpresure

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2.3.1. Temperature Gradients

The temperature of the rocks at a given point, formation temperature, and relationshipbetween temperature and depth is termed the thermal gradient. Temperature gradientsaround the world can vary from between 1oC in 110ft (35m) to 180ft (56m).

The heat source is radiated through the rock therefore it is obvious that temperaturegradients will differ throughout the various regions where there are different rocks. Seasonalvariations in surface temperatures have little effect on gradients deeper than 100ft (30m)except in permafrost regions.

It is important therefore that the local temperature gradient is determined from previousdrilling reports, offset well data or any other source. In most regions, the temperaturegradient is well known and is only affected when in the vicinity of salt domes. If thetemperature gradient is not known in a new area, it is recommended that a gradient of3oC/100m be assumed.

The calculation of temperature at depth if the thermal gradient is known, is simply:

T = Surface Ambient Temp + Depth/Gradient (Depth per Degree Temp)

2.3.2. Temperature Logging

During the actual drilling of a well, temperature surveys will be taken at intervals which mayhelp to confirm the accuracy of the temperature prediction.

Temperature measurement during drilling may be by simple thermometer or possibly byrunning thermal logs, however, the circulation of mud or other liquids tends to smooth outthe temperature profile around the well bore and mask the distinction of the individualstrata. Consequently the use of temperature logs during drilling is uncommon.

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3. SELECTION OF CASING SEATS

The selection of casing setting depths is one of the most critical factors affecting welldesign. These are covered in detail in the ‘Casing Design Manual’. The following sectionsare to provide engineers with an outline of the criteria necessary to enable casing seatselection.

The following parameters must be carefully considered in this selection:

• 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 program compatibility with existing wellhead systems• Casing program compatibility with planned completion programme on production

wells• Casing availability - size, grade and weight• Economics - time consumed to drill the hole, run casing and the cost of

equipment.

When planning, all available information should be carefully documented and considered toobtain knowledge of the various uncertainties.

Information is sourced from:

• Evaluation of the seismic and geological background documentation used asthe decision for drilling the well.

• Drilling data from offset wells in the area. (Company wells or scoutinginformation).

The key factor to satisfactory picking of casing seats is the assessment of pore pressure(formation fluid pressures) and fracture pressures throughout the length of the well.

As the pore pressures in a formation being drilled approach the fracture pressure at the lastcasing seat then installation of a further string of casing is necessary.

figure 3.b show typical examples of casing seat selections.

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• Casing is set at depth 1, where pore pressure is P1 and the fracture pressure isF1.

• Drilling continues to depth 2, where the pore pressure P2 has risen to almostequal the fracture pressure (F1) at the first casing seat.

• Another casing string is therefore set at this depth, with fracture pressure (F2).• Drilling can thus continue to depth 3, where pore pressure P3 is almost equal to

the fracture pressure F2 at the previous casing seat.

This example does not include any safety or trip margins, which would, in practice, be takeninto account.

Figure 3.A - Example of idealised Casing Seat Selection

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Figure 3.B - Example Casing Seat Selection (for a typical geopressurised well using a pressure profile).

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3.1. CONDUCTOR CASING

The setting depth for conductor casing is usually shallow and selected so that drilling fluidmay be circulated to the mud pits while drilling the surface hole. The casing seat must be inan impermeable formation with sufficient fracturing resistance to allow fluid circulation to thesurface. In wells with subsea wellheads, no attempt is made to circulate through theconductor string to the surface but must be set deep enough to assist in stabilising thesubsea guide base to which guide lines are attached.

The driving depth of the conductor pipe is established with the following formula:

Hi = [df x (E+H) - 103 x H]/[1.03 - df + 0.67 x (GOVhi - 1.03)]

where:

Hi = Minimum driving depth (m) from seabed

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

H = Water depth (m)

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

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

3.2. SURFACE CASING

The setting depth of surface casing should be in an impermeable section below fresh waterformations. In some instances, where there is near surface gravel or shallow gas, it mayneed to be cased off shallower.

The depth should be enough to provide a fracture gradient sufficient to allow drilling to thenext casing setting point and to provide reasonable assurance that broaching to the surfacewill not occur in the event of BOP closure to contain a kick.

3.3. INTERMEDIATE CASING

The most predominant use of intermediate casing is to protect normally pressuredformations from the effects of increased mud weight needed in deeper drilling operations.An intermediate string may be necessary to case off lost circulation, salt beds, or sloughingshales.

In cases of pressure reversals with depth, intermediate casing may be set to allow reductionof mud weight.

When a transition zone is penetrated and mud weight increased, the normal pressureinterval below surface pipe is subjected to two detrimental effects:

• The fracture gradient may be exceeded by the mud gradient, particularly if itbecomes necessary to close-in on a kick The result is loss of circulation and thepossibility of an underground blow-out occurring.

• The differential between mud column pressure and formation pressure isincreased, increasing the risk of stuck pipe.

However, in general practice, drilling is allowed until the mud weight is within 50gr/l of thefracture gradient measured by conducting a leak-off test at the previous casing shoe.

Attempts to drill with mud weight higher than this limit are sometimes successful, but manyholes have been lost by attempts to extend the intermediate string setting depth beyondthat indicated by the above rule.

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This can cause either, kicks causing loss of circulation and possibly an underground blow-out or the pipe becomes differentially stuck. Sloughing of high pressure zones can alsocause stuck pipe .

Significantly in soft rock areas, the fracture gradient increases relatively slowly compared tothe depth of the surface casing string, but the pressure gradients in the transition zonesusually change rapidly.

Emphasis is often placed on setting the surface casing to where there is an acceptablefracture gradient. Greater control over potential conditions at the surfaces casing seat isaffected by the intermediate casing setting depth decision.

It is often tempting to ‘drill a little deeper’ without setting pipe in exploratory wells. Whenpressure gradients are not increasing this can be a reasonably acceptable decision, but,with increasing gradient, the risk is greater and should be carefully evaluated.

To ensure the integrity of the surface casing seat, leak-off tests should be specified in theDrilling Programme.

3.4. DRILLING LINER

The setting of a drilling liner is often an economically attractive decision in deep wells asopposed to setting a full string. Such a decision must be carefully considered as theintermediate string must be designed for burst as if it were set to the depth of the liner.

If drilling is to be continued below the drilling liner then burst requirements for theintermediate string are further increased. This increases the cost of the intermediate string.Also, there is the possibility of continuing wear of the intermediate string that must beevaluated.

If a production liner is planned then either the production liner or the drilling liner should betied back to the surface as a production casing.

If the drilling liner is to be tied-back, it is usually better to do so before drilling the hole forthe production liner. By doing so, the intermediate casing can be designed for a lower burstrequirement, resulting in considerable cost savings. Also, any wear to the intermediatestring is spanned prior to drilling the producing interval.

If increased mud weight will be required while drilling hole for the drilling liner, then leak-offtests should be specified in the Drilling Procedures in the programme for the intermediatecasing shoe.

Insufficient fracture gradient at the shoe may limit the depth of the drilling liner.

3.5. PRODUCTION CASING

Whether production casing or a liner is installed, the depth is determined by the geologicalobjective. Depths, hence the casing programme, may have to be altered accordingly ifdepths run high or low.

The objective and method of identifying the correct depth should also be stated in theprogramme.

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4. CASING DESIGN

4.1. INTRODUCTION

For detailed casing design criteria and guidelines, refer to the ‘Casing Design Manual’.

The selection of casing grades and weights is an engineering task affected by manyfactors, including local geology, formation pressures, hole depth, formation temperature,logistics and various mechanical factors.

The engineer must keep in mind during the design process the major logistics problems incontrolling the handling of the various mixtures of grades and weights by rig personnelwithout risk of installing the wrong grade and weight of casing in a particular hole section.Experience has shown that the use of two to three different grades or two to three differentweights is the maximum that can be handled by most rigs and rig crews.

After selecting a casing for a particular hole section, the designer should considerupgrading the casing in cases where:

• Extreme wear is expected from drilling equipment used to drill the next holesection or from wear caused by wireline equipment.

• Buckling in deep and hot wells.

Once the factors are considered, casing cost should be considered.

If the number of different grades and weights are necessary, it follows that cost is notalways a major criterion.

Most major operating companies have differing policies and guidelines for the design ofcasing for exploration and development wells, e.g.:

• For exploration, the current practice is to upgrade the selected casing,irrespective of any cost factor.

• For development wells, the practice is also to upgrade the selected casing,irrespective of any cost factor.

• For development wells, the practice is to use the highest measured bottomholeflowing pressures and well head shut-in pressures as the limiting factors forinternal pressures expected in the wellbore. These pressures will obviouslyplace controls only on the design of production casing or the production liner,and intermediate casing.

The practice in design of surface casing is to base it on the maximum mud weights used todrill adjacent development wells.

Downgrading of a casing is only carried out after several wells are drilled in a given areaand sufficient pressure data are obtained.

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4.2. PROFILES AND DRILLING SCENARIOS

4.2.1. Casing Profiles

The following are the various casing configurations which can be used on onshore andoffshore wells.

Onshore

• Drive/structural/conductor casing• Surface casing• Intermediate casings• Production casing• Intermediate casing and drilling liners• Intermediate casing and production liner• Drilling liner and tie-back string.

Offshore - Surface Wellhead

As in onshore above.

Offshore - Surface Wellhead & Mudline Suspension

• Drive/structural/conductor casing• Surface casing and landing string• Intermediate casings and landing strings• Production casing• Intermediate casings and drilling liners• Drilling liner and tie-back string.

Offshore - Subsea Wellhead

• Drive/structural/conductor casing• Surface casing• Intermediate casings• Production casing• Intermediate casing and drilling liners• Intermediate casing and production liner• Drilling liner and tie-back string.

Refer to the following sections for descriptions of the casings listed above.

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4.3. CASING SPECIFICATION AND CLASSIFICATION

There is a great range of casings available from suppliers from plain carbon steel foreveryday mild service through exotic duplex steels for extremely sour service conditions.The casings available can be classified under two specifications, API and non-API.

Casing specifications, including API and its history, are described and discussed in the‘Casing Design Manual’. Sections 4.3.1 and 4.3.2 below give an overview of someimportant casing issues.

Non-API casing manufacturers have produced products to satisfy a demand in the industryfor casing to meet with extreme conditions which the API specifications do not meet. Thearea of use for this casing are also discussed in section 4.3.1 below and the productsavailable described in section 4.3.2.

4.3.1. Casing Specification

It is essential that design engineers are aware of any changes made to the APIspecifications. All involved with casing design must have immediate access to the latestcopy of API Bulletin 5C2 which lists the performance properties of casing, tubing anddrillpipe. Although these are also published in many contractors' handbooks and tables,which are convenient for field use, care must be taken to ensure that they are current.

Operational departments should also have a library of the other relevant API publications,and design engineers should make themselves familiar with these documents and theircontents.

It should not be interpreted from the above that only API tubulars and connections may beused in the field as some particular engineering problems are overcome by specialistsolutions which are not yet addressed by API specifications. In fact, it would be impossibleto drill many extremely deep wells without recourse to the use of pipe manufactured outwithAPI specifications (non-API).

Similarly, many of the ‘Premium’ couplings that are used in high pressure high GORconditions are also non-API.

When using non-API pipe, the designer must check the methods by which the strengthshave been calculated. Usually it will be found that the manufacturer will have used thepublished API formulae (Bulletin 5C3), backed up by tests to prove the performance of hisproduct conforms to, or exceeds, these specifications. However. in some cases, themanufacturers have claimed their performance is considerably better than that calculated bythe using API formulae. When this occurs the manufacturers claims must be criticallyexamined by the designer or his technical advisors, and the performance corrected ifnecessary.

It is also important to understand that to increase competition. the API tolerances have beenset fairly wide. However, the API does provide for the purchaser to specify more rigorouschemical, physical and testing requirements on orders, and may also request placeindependent inspectors to quality control the product in the plant.

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4.3.2. Classification Of API Casing

Casing is usually classified by:

• Outside diameter• Nominal unit weight• Grade of the steel• Type of connection• Length by range• Manufacturing process.

Reference should always be made to current API specification 5C2 for casing lists andperformances.

4.4. MECHANICAL PROPERTIES OF STEEL

4.4.1. General

Failure of a material or of a structural part may occur by fracture (e.g. the shattering ofglass), yield, wear, corrosion, and other causes. These failures are failures of the material.Buckling may cause failure of the part without any failure of the material.

As load is applied, deformation takes place before any final fracture occurs. With all solidmaterials, some deformation may be sustained without permanent deformation, i.e. thematerial behaves elastically.

Beyond the elastic limit, the elastic deformation is accompanied by varying amounts ofplastic, or permanent, deformation, If a material sustains large amounts of plasticdeformation before final fracture. It is classed as ductile material, and if fracture occurs withlittle or no plastic deformation. The material is classed as brittle.

4.4.2. Stress-Strain Diagram

Tests of material performance may be conducted in many different ways, such as bytorsion, compression and shear, but the tension test is the most common and is qualitativelycharacteristics of all the other types of tests.

The action of a material under the gradually increasing extension of the tension test isusually represented by plotting apparent stress (the total load divided by the original cross-sectional area of the test piece) as ordinates against the apparent strain (elongationbetween two gauge points marked on the test piece divided by the original gauge length) asabscissae.

A typical curve for steel is shown in figure 4.a.

From this, it is seen that the elastic deformation is approximately a straight line as called forby Hooke's law, and the slope of this line, or the ratio of stress to strain within the elasticrange, is the modulus of elasticity E, sometimes called Young's modulus.

Beyond the elastic limit, permanent, or plastic strain occurs.

If the stress is released in the region between the elastic limit and the yield strength (seeabove) the material will contract along a line generally nearly straight and parallel to theoriginal elastic line, leaving a permanent set.

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Figure 4.A- Stress - Strain Diagram

In steels, a curious phenomenon occurs after the end of the elastic limit, known as yielding.This gives rise to a dip in the general curve followed by a period of deformation atapproximately constant load. The maximum stress reached in this region is called the upperyield point and the lower part of the yielding region the lower yield point. In the harder andstronger steels, and under certain conditions of temperature, the yielding phenomenon isless prominent and is correspondingly harder to measure. In materials that do not exhibit amarked yield point, it is customary to define a yield strength. This is arbitrarily defined as thestress at which the material has a specified permanent set (the value of 0.2% is widelyaccepted in the industry).

For steels used in the manufacturing of tubular goods the API specifies the yield strength asthe tensile strength required to produce a total elongation of 0.5% and 0.6% of the gaugelength.

Similar arbitrary rules are followed with regard to the elastic limit in commercial practice.Instead of determining the stress up to which there is no permanent set, as required bydefinition, it is customary to designate the end of the straight portion of the curve (bydefinition the proportional limit) as the elastic limit. Careful practice qualifies this bydesignating it the ‘proportional elastic limit’.

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As extension continues beyond yielding, the material becomes stronger causing a rise ofthe curve, but at the same time the cross-sectional area of the specimen becomes less as itis drawn out. This loss of area weakens the specimen so that the curve reaches a maximumand then falls off until final fracture occurs.

The stress at the maximum point is called the tensile strength (TS) or the ultimate strengthof the material and is its most often quoted property.

The mechanical and chemical properties of casing, tubing and drill pipe are laid down in APIspecifications 5CT and 5C2.

Depending on the type or grade, minimum requirements are laid down for the mechanicalproperties, and in the case of the yield point even maximum requirements (except for H 40).

The denominations of the different grades are based on the minimum yield strength, e.g.:

Grade Min. Yield Strength

H 40 40,000psi

J 55 55,000psi

C 75 75,000psi

N 80 80,000psi

etc.

In the design of casing and tubing strings the minimum yield strength of the steel is taken asthe basis of all strength calculations

As far as chemical properties are concerned, in API 5CT only the maximum phosphorusand sulphur contents are specified, the quality and the quantities of other alloying elementsare left to the manufacturer.

API specification 5CT ‘Restricted yield strength casing and tubing’ however specifies, thecomplete chemical requirements for grades C 75, C 95 and L 80.

4.5. NON-API CASING

Eni-Agip Division and Affiliates policy is to use API casings whenever possible. Somemanufacturers produce non-API casings for H2S and deep well service where API casingsdo not meet requirements. The most common non-API grades are shown in the CasingDesign Manual (STAP-P-1-M-6110-4.3).

Reference to API and non-API materials should be made to suit the environment in whichthey are recommended to be employed.

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4.6. CONNECTIONS

The selection of a casing connection is dependant upon whether the casing is exposed towellbore fluids and pressures. API connections are normally used on all surface andintermediate casing and drilling liners. Non-API or premium connections are generally usedon production casing and production liners in producing wells.

API connections rely on thread compound to form the seal and are not recommended forsealing over long periods of time when exposed to well high pressures and corrosive fluidsas the compound can be extruded exposing the threads to corrosive fluids which in turnreduces the strength of the connection. Sealing on premium connections are provided by atleast one metal-to-metal seal which prevents this exposure of the threads to corrosiveelements, hence, retains full strength.

The properties of both API and non-API connections are described below.

4.6.1. API Connections

The types of API connections available are:

• Round thread short which is coupled.• Round thread long which is coupled.• Buttress thread which is coupled, with both normal and special clearance.• Extreme line thread which is integral with either normal or special clearance.

Round thread couplings, short or long, have less strength than the corresponding pipebody. This in turn requires heavier pipe to meet design requirements, than if the pipe andcoupling had the same strength. Problems like ‘pullouts’ or ‘jump-outs’ can happen withround thread type coupling on 103/4" casing or when also subjected to bending stresses, i.e.doglegs, directional drilled holes. etc.

Buttress threads have, according to API calculations, higher joint strength than the pipebody yield strength with a few exceptions. Buttress threads also stab and enter easier thanround threads, therefore, should be used whenever possible, except for 20" and larger pipewhere special connections could be beneficial due to having superior make-upcharacteristics.

API round threads and buttress threads have no metal to metal seals. As stated earlier, theseal in API thread is created by the thread compound which contains metal which fill thevoid space between the threads. When subjected to high pressure gas, temperaturevariations, and/or corrosive environment this sealing method may fail. Therefore, in suchconditions, connections with metal-to-metal seals, should be utilised.

According to API standards the coupling shall be of the same grade as the pipe exceptgrade H 40 and J 55 which may be furnished with grade J 55 or K 55 couplings.

For connection dimensions refer to the current API specification.

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4.7. APPROACH TO CASING DESIGN

Casing design is basically a stress analysis procedure which is fully described in the ‘CasingDesign Manual’.

As there is little point in designing for loads that are not encountered in the field, or inhaving a casing that is disproportionally strong in relating to the underlying formations, thereare clearly four major elements to casing design:

• Definition of the loading conditions likely to be encountered throughout the life ofthe well.

• Specification of the mechanical strength of the pipe.• Estimation of the formation strength using rock and soil mechanics.• Estimation of the extent to which the pipe will deteriorate through time and

quantification of the impact that this will have on its strength.

4.7.1. Wellbore Forces

Various wellbore forces affect casing design. Besides the three basic conditions (burst,collapse and axial loads or tension), these include:

• Buckling.• Wellbore confining stress.• Thermal and dynamic stress.• Changing internal pressure caused by production or stimulation.• Changing external pressure caused by plastic formation creep.• Subsidence effects and the effect of bending in crooked hole.• Various types of wear caused by mechanical friction.• H2S or squeeze/acid operations.• Improper handling and make-up.

This list is by no means comprehensive because new research is still in progress.

The steps in the design process are:

1) Consider the loading for burst first, since burst will dictate the design for most of thestring.

2) Next, the collapse load should be evaluated and the string sections upgraded ifnecessary.

3) Once the weights, grades and section lengths have been determined to satisfy theburst and collapse loading, the tension load can then be evaluated.

4) The pipe can be upgraded as necessary as the loads are found and the coupling typedetermined.

5) The final step is a check on biaxial reductions in burst strength and collapseresistance caused by compression and tension loads, respectively. If these reductionsshow the strength of any part of the section to be less than the potential load, thesection should again be upgraded.

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4.7.2. Design Factor (DF)

The design process can only be completed if knowledge of all anticipated forces isavailable. This however, is idealistic and never actually occurs. Some determinations areusually necessary and some degree of risk has to be accepted.

The risk is usually due to the assumed values and therefore the accuracy of the designfactors used.

Design factors are necessary to cater for:

• Uncertainties in the determination of actual loads that the casing needs towithstand and the existence of any stress concentrations, due to dynamic loadsor particular well conditions.

• Reliability of listed properties of the various steels used and the uncertainty inthe determination of the spread between ultimate strength and yield strength.

• Probability of the casing needing to bear the maximum load provided in thecalculations.

• Uncertainties regarding collapse pressure formulas.• Possible damage to casing during transport and storage.• Damage to the steel from slips, wrenches or inner defects due to cracks, pitting,

etc.• Rotational wear by the drill string while drilling.

The DF will vary with the capability of the steel to resist damage from the handling andrunning equipment.

The value selected as the DF is a compromise between margin and cost.

The use of excessively high design factors guarantees against failure, but provideexcessive strength and, hence, cost.

The use of low design factors requires accurate knowledge about the loads to be imposedon the casing.

Casing is generally designed to withstand stress which, in practice, it seldom encountersdue to the assumptions used in calculations, whereas, production tubing has to bearpressures and tensions which are known with considerable accuracy.

Also casing is installed and cemented in place whereas tubing is often pulled and re-used.As a consequence a of this and due to the fact that tubing has to combat corrosion effectsfrom formation fluid, a higher DF is used for tubing than casing.

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4.7.3. Design Factors

The following DF’s must be used in casing design calculations:

Casing Grade Design Factor H 40 1.05 J 55 1.05 K 55 1.05 C 75 1.10

Burst L 80 1.10 N 80 1.10 C 90 1.10 C 95 1.10 P 110 1.10 Q 125 1.20

Collapse All Grades 1.10 < C-95 1.70

Tension > C-95 1.80 Note The tensile DF must be considerably higher than the previous factors to avoid

exceeding the elastic limit and, therefore invalidating the criteria on which burstand collapse resistance are calculated.

4.7.4. Application of Design Factors

The minimum performance properties of tubing and casing from the ‘API’ bulletin are onlyused to determine the chosen casing is within the DF.

Burst For the chosen casing (diameter, grade, weight and thread)take the lowest value from API casing tables columns 13-19.This value divided by DF gives the internal pressureresistance of casing to be used for design calculation

Collapse Use only column 11 of API casing tables and divide by the DFto obtain the collapse resistance for design calculation.

Tension Use the lowest value from columns 20-27 of the API casingtables and divide by the DF to obtain the joint strength fordesign calculation.

Note: It should be recognised that the Design Factor used in the context ofcasing string design is essentially different from the ‘Safety Factor’ usedin many other engineering applications.

The term ‘Safety Factor’ as used in tubing design, implies that the actual physical propertiesand loading conditions are exactly known and that a specific margin is being allowed forsafety. The loading conditions are not always precisely known in casing design, andtherefore in the context of casing design the term ‘Safety Factor’ should be avoided.

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4.8. DESIGN CRITERIA

4.8.1. Burst

Burst loading on the casing is induced when internal pressure exceeds external pressure.

To evaluate the burst loading, surface and bottomhole casing burst resistance must first beestablished according to the company procedure outlined below.

Surface Casing Internal Pressure The wellhead burst pressure limit is arbitrary, and is generally set equal to

that of the working pressure rating of the wellhead and BOP equipmentbut with a minimum of 140kg/cm2. See ‘BOP selection criteria’ in section9.1.

With a subsea wellhead, the wellhead burst pressure limit is taken as 60%of the value obtained as the difference between the fracture pressure atthe casing shoe and the pressure of a gas column to surface but in anycase not less than 2,000psi (140atm).

Consideration should be given to the pressure rating of the wellhead andBOP equipment which must always be equal to, or higher than, thepressure rating of the pipe.

When an oversize BOP having a capacity greater than that necessary isselected, the wellhead burst pressure limit will be 60% of the calculatedsurface pressure obtained as difference between the fracture pressure atthe casing shoe with a gas column to surface. Methane gas (CH4) withdensity of 0.3kg/dm3 is normally used for this calculation. In any case itshall never be considered less than 2,000psi (140atm).

The use of methane for this calculation is the ‘worst case’ when thespecific gravity of gas is unknown, as the specific gravities of any gaseswhich may be encountered will usually be greater than that of methane.

The bottomhole burst pressure limit is set equal to the predicted fracturegradient of the formation below the casing shoe.

Connect the wellhead and bottomhole burst pressure limits with a straightline to obtain the maximum internal burst load verses depth.

When taking a gas kick, the pressure from bottom-hole to surface willassume different profiles according to the position of influx into thewellbore. The plotted pressure versus depth will produce a curve.

External Pressure In wells with surface wellheads, the external pressure is assumed to beequal to the hydrostatic pressure of a column of drilling mud.

In wells with subsea wellheads:

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)

Net Pressure The resultant load, or net pressure, will be obtained by subtracting, ateach depth, the external from internal pressure.

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Intermediate Casing

Internal Pressure The wellhead burst pressure limit is taken as 60% of the calculated valueobtained as difference between the fracture pressure at the casing shoeand the pressure of a gas column to wellhead.

In subsea wellheads, the wellhead burst pressure limit is taken as 60% ofthe value obtained as the difference between the fracture pressure at thecasing shoe and the pressure of a gas column to the wellhead minus theseawater pressure

The bottom-hole burst pressure limit is equal to that of the predictedfracture gradient of the formation below the casing shoe.

Connect the wellhead and bottom-hole burst pressure limits with astraight line to obtain the maximum internal burst pressure

External Pressure The external collapse pressure is taken to be equal to that of theformation pressure.

With a subsea wellhead, at the wellhead, hydrostatic seawater pressureshould be considered.

Net Burst Pressure The resultant burst pressure is obtained by subtracting the external frominternal pressure versus depth.

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Production Casing The ‘worst case’ burst load condition on production casing occurs when a well is shut-in and thereis a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied to the top ofthe packer fluid (i.e. completion fluid) in the tubing-casing annulus.

Internal Pressure The wellhead burst limit is obtained as the difference between thepore pressure of the reservoir fluid and the hydrostatic pressureproduced by a colum of fluid which is usually gas (density =0.3kg/dm3).

Actual gas/oil gradients can be used if information on these areknown and available.

The bottom-hole pressure burst limit is obtained by adding thewellhead pressure burst limit to the annulus hydrostatic pressureexerted by the completion fluid.

Generally the completion fluid density is, equal to or close to, themud weight in which casing is installed.

Note: It is usually assumed that the completion fluid and

mud on the outside of the casing remainshomogeneous and retain their original densityvalues. However this is not actually the caseparticularly with heavy fluids but it is also assumedthat the two fluids will degrade similarly under thesame conditions of pressure and temperature.

Connect the wellhead and bottom-hole burst pressure limits with astraight line to obtain the maximum internal burst pressure.

Note: If it is foreseen of that stimulation or hydraulic

fracturing operations may be necessary in future,therefore the fracture pressure at perforation depthand at the well head pressure minus the hydrostatichead in the casing plus a safety margin of 70kg/cm2

(1,000psi) will be assumed.

External Pressure The external pressure is taken to be equal to that of the formationpressure.

With a subsea wellhead, at the wellhead, hydrostatic seawaterpressure should be considered.

Net Burst Pressure The resultant burst pressure is obtained by subtracting the externalfrom internal pressure at each depth.

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Intermediate Casing and Liner If a drilling liner is to be used in the drilling of a well, the casing above where the liner issuspended must withstand the burst pressure that may occur while drilling below the liner. Thedesign of the intermediate casing string is, therefore, altered slightly.

Since the fracture pressure and mud weight may be greater or lowerbelow the liner shoe than casing shoe, these values must be usedto design the intermediate casing string as well as the liner.

When well testing or producing through a liner, the casing above theliner is part of the production string and must be designed accordingto this criteria

Tie-Back String In a high pressure well, the intermediate casing string above a liner may be unable to withstand atubing leak at surface pressures according to the production burst criteria. The solution to thisproblem is to run and tie-back a string of casing from the liner top to surface, isolating theintermediate casing.

4.8.2. Collapse

Pipe collapse will occur if the external force on a pipe exceeds the combination of theinternal force plus the collapse resistance.

The reduced collapse resistance under biaxial stress (tension/collapse) should beconsidered.

No allowance is given to increased collapse resistance due to cementing.

Surface Casing Internal Pressure For wells with a surface wellhead, the casing is assumed to be

completely empty.

In offshore wells with subsea wellheads, the internal pressureassumes that the mud level drops due to a thief zone

External Pressure In wells with a surface wellhead, the external pressure is assumedto be equal to that of the hydrostatic pressure of a column of drillingmud.

In offshore wells with a subsea wellhead, it is calculated:

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 (ifatm).

Net Collapse Pressure The resultant collapse pressure is obtained by subtracting theinternal pressure from external pressure at each depth.

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Intermediate Casing Internal Pressure The ‘worst case’ collapse loading occurs when a loss of circulation

is encountered while drilling the next hole section with the maximumallowable mud weight. This would result in the mud level inside thecasing dropping to an equilibrium level where the mud hydrostaticequals the pore pressure of the thief zone (Refer to Errore.L'origine riferimento non è stata trovata.). Consequently it will beassumed the casing is empty to the height (H) calculated as follows:

(Hloss-H) x dm = Hloss x Gp

H = Hloss (dm - Gp)/dm

If Gp = 1.03 (kg/cm2/10m)

Then H = Hloss (dm-1.03)/dm

Hloss = Depth at which circulation loss is expected (m)

dm = Mud density expected at Hloss (kg/dm2)

Gp = Pore pressure of thief zone (kg/cm2/10m) - usually Normally pressured with 1.03 as gradient.

When thief zones cannot be confirmed, or otherwise, during thecollapse design, as is the case in exploration wells, Eni-Agipdivision and associates suggests that on wells with surfacewellheads, the casing is assumed to be half empty and theremaining part of the casing full of the heaviest mud planned to drillthe next section below the shoe.

In wells with subsea wellheads, the mud level inside the casing isassumed to drop to an equilibrium level where the mud hydrostaticpressure equals the pore pressure of the thief zone.

External Pressure The pressure acting on the outside of casing is the pressure of mudin which casing is installed.

The uniform external pressure exerted by salt on the casing orcement sheath through overburden pressure, should be given avalue equal to the true vertical depth of the relative point.

Net Collapse Pressure The effective collapse line is obtained by subtracting the internalpressure from external at each depth.

Production Casing Internal Pressure During the productive life of well, tubing leaks often occur. Also

wells may be on artificial lift, or have plugged perforations or verylow internal pressure values and, under these circumstances, theproduction casing string could be partially or completely empty. Theideal solution is to design for zero pressure inside the casing whichprovides full safety, nevertheless in particular well situations, theDrilling and Completions Manager may consider that the lowestcasing internal pressure is the level of a column of the lightestdensity producible formation fluid.

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External Pressure Assume the hydrostatic pressure exerted by the mud in whichcasing is installed.

The uniform external pressure exerted by salt on the casing orcement sheath through overburden pressure, should be given avalue equal to the true vertical depth of the relative point.

Net Collapse Pressure In this case of the casing being empty, the net pressure is equal tothe external pressure at each depth.

In other cases it will be the difference between external and internalpressures at each depth.

Intermediate Casing and Liner If a drilling liner is to be used in the drilling of a well, the casing

above where the liner is suspended must withstand the collapsepressure that may occur while drilling below the liner.

When well testing or producing through a liner, the casing abovethe liner is part of the production casing/liner and must be designedaccording to this criteria.

Tie-Back String

If the intermediate string above the liner is unable to withstand thecollapse pressure calculated according to production collapsecriteria, it will be necessary run and tie-back a string of casing fromthe liner top to surface.

Figure 4.B - Fluid Height Calculation

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4.8.3. Tension

Note: The amount of parameters which can affect tensile loading means theestimates for the tensile forces are more uncertain than the estimates foreither burst and collapse. The DF imposed is therefore much larger.

To evaluate the tensile loading, the company procedure outlined below applies.

Surface Casing Tension Calculate the casing string weight in air.

Calculate the casing string weight in mud multiplying the previousweight by the buoyancy factor (BF) in accordance with the mudweight in use.

Add the additional load due to bumping the cement plug to thecasing string weight in mud.

Note: This pull load is calculated by multiplying the

expected bump-plug pressure by the inside area ofthe casing.

A calculation of this kind is an approximation because theassumption has been made that:

• No buoyancy changes occur during cementing.

• The pressure is applied only at the bottom and not where thereare changes in section. As seen with the previous case, thedifferences in the calculated values are quite small, whichjustifies the preference for the simpler approximation method.

Once the magnitude and location of the forces are determined, thetotal tensile load line may be constructed graphically. Note: morethan one section of the casing string may be loaded in compression.

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4.9. BIAXIAL STRESS

When the entire casing string has been designed for burst, collapse and tension, and theweights, grades, section lengths and coupling types are known, reduction in burstresistance needs to be applied due to biaxial loading.

The total tensile load, which is tensile loading versus depth, is used to evaluate the effect ofbiaxial loading and can be shown graphically.

By noting the magnitude of tension (plus) or compression (minus) loads at the top andbottom of each section length of casing, the strength reductions can be calculated using the‘Holmquist & Nadai’ ellipse, see figure 4.c.

Note: The effects of axial stress on burst resistance are negligible for themajority of wells.

4.9.1. Effects On Collapse Resistance

The collapse strength of casing is seriously affected by axial load, but the correctionadopted by the API (API Bulletin 5C3) is only valid for D/t ratios of about 15 or less. Inprinciple collapse resistance is reduced or increased when subjected to axial tension orcompression loading.

As can be seen from figure 4.c, increasing tension reduces collapse resistance where iteventually reaches zero under full tensile yield stress.

The adverse effects of tension on collapse resistance usually affects the upper portion of acasing string which is under tension reducing the collapse resistance of the pipe.

After these calculations, the upper section of casing string may need to be upgraded.

Note: Fortunately most times, the biaxial effects of axial stress on collapseresistance are insignificant.

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Figure 4.C - Ellipse of Biaxial Yield Stress

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4.9.2. Company Design Procedure

The value for the percentage reduction of rated collapse strength is determined as follows:

1) Determine the total tensile load.

2) Calculate the ratio (X) of the actual applied stress to yield strength of the casing.

3) Refer to figure 4.d and curve ‘effect of tension on collapse resistance’ and find thecorresponding percentage collapse rating (Y).

4) Multiply the collapse resistance by the percentage (Y), without tensile loads to obtainthe reduced collapse resistance value.

This is the collapse pressure which the casing can withstand at the top of the string.

The collapse resistance increases towards the bottom as the tension decreases.

Figure 4.D - Effect Of Tension On Collapse Resistance

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1

X= Tensile load Pipe body yield strength

Y=

Co

llap

sres

iste

nce

wit

h t

ensi

le lo

ad

Co

llap

se r

esis

ten

ce w

ith

ou

t te

nsi

le lo

ad

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4.9.3. Example Collapse Calculation

Determine the collapse resistance of 7", N 80, 32lbs/ft (4kg/m), BTR casing with the shoe ata depth of 5,750m and a mud weight of 1.1kg/dm3.

Collapse resistance without tensile load = 8,610psi (605 kg/cm2)

Pipe body yield strength = 745,000lbs (338 t)

Buoyancy factor = 0.859

Weight in air of casing = t274000,1

62.47x750,5=

Weight in mud of casing = 274 x 0.859 = 235 t

695.0338235

Strength Body Yield Pipe

casingofmudinWeightx ===

From the curve or stress curve factors in figure 4.d if X = 0.695 then Y = 0.445 and thecollapse resistance with tensile load can be determined

Collapse resistance under load = Nominal Collapse Rating x 0.445

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4.10. BENDING

4.10.1. General

When calculating tension loading, the effect of bending should be considered if applicable.

The bending of the pipe causes additional stress in the walls of the pipe. This bendingcauses tension on the outside of the pipe and in compression on the inside of the bend,assuming the pipe is not already under tension (Refer to figure 4.e)

Figure 4.E - Bending Stress

Bending is caused by any deviations in the wellbore resulting from side-tracks, build-upsand drop-offs.

Since bending load increases the total tensile load, it must be deducted from the usablerated tensile strength of the pipe.

4.10.2. Determination Of Bending Effect

For determination of the effect of bending, the following formula should be used:

AfD52.15B ××α×=

where:

α = Rate (degrees 30m)

D = Outside diameter of casing (ins)

Af = Cross-section area of casing (cm2)

TB = Additional tension (kg)

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The formula is obtained from the two following equations:

J2

DMB

××

=σ

where:

MB = Bending moment (MB = E x J/R) (Kg x cm)

D = Outside diameter of casing (cm)

J = Inertia moment (cm4)

σ = Bending stress (kg/cm2)

E x J = Bending stiffness (kg x cm2)

R = Radius of curvature (cm)

JE

LMB

××

=σ

where:

MB = Bending moment (kg x cm)

L = Arch length (cm)

E = Modulus of elasticity (kg/cm2)

J = Inertia moment (cm4)

θ = Change in angle of deviation (radians)

Obtaining L

JEMB

××θ= thus the equation becomes:

L2

DE

×××θ

=σ

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Then, by using the more current units giving the build-up or drop-off angles in degrees/30m, we obtain the final form of the equation for ‘TB’ as follows:

AfTB

=θ

L2

AfDETB

××××θ

=

α×π×

=30180

R

R1

L =

302180

AfDETB

×××××α×π

=

E = 21,000kg/mm2 = 2.1 x 106kg/cm2

( ) ( )10030

AfD4251802

101.2TB

6

××××

××

××α×π=

TB = 15.52 x α x D x Af

when:

Af = Square inches

α = Degrees/100ft

TB = 218 x α x D x Af (lbs) or 63 x α x D x W(lbs)

W = Casing weight (lbs/ft)

Note: Since most casing has a relatively narrow range of wall thickness (from0.25” to 0.60”), the weight of casing is approximately proportional to itsdiameter. This means the value of the bending load increases with thesquare of the pipe diameter for any given value of build-up/drop-off rate.At the same time, joint tension strength rises a little less than the directratio. The result is that bending is a much more severe problem with largediameter casing than with smaller sizes.


Since bending load, in effect, increases tensile load at the point applied, it must bededucted from the usable strength rating of each section of pipe that passes the point ofbending.

The section which is ultimately set through a bend must have the bending load deductedfrom its usable strength up to the top of the bend. From that point up to the top of thesection the full usable strength can be used.

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4.10.4. Example Bending Calculation

Data:

Casing: OD. 13 3/8", 72lbs/ft (107.14kg/m), C 75, BTR

Directional well with casing shoe at 2,000m. (MD)

Kick-off point at 300m

Build-up rate: 3°/30m

Maximum angle: 30°

Mud weight : 1.1kg/dm3

Pipe body yield strength: 1,558,000lbs (707t)

Design factor : 1.7

Calculation:

Casing weight in air (Wa) Wa = 107.14 x 2,00 = 214t

Casing weight in mud (Wm) Wm = 214 x 0.859 = 184t

Additional tension due to the bending effect (TB)

TB = 15.52 x 3 x 13.375 x 133.99 = 83,441kg = 83t

This stress will be added to the tensile stress already existing on thecurved section of hole.

Tension in the casing at 300m(TVD)=156t. 5)

Total tension in the casing at 300m = 156 + 83 = 239t

Tension in the casing at 600m (MD) =129t.

Total tension in the casing at 600m (MD) = 129 + 83 = 212t.

See figure 4.f for the graphical representation of the example.

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Figure 4.F - Bending Load Example

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4.11. CASING WEAR

4.11.1. General

Casing wear decreases the performance properties of casing. The burst and collapseresistance of worn casing is in direct proportion to its remaining wall thickness.

Figure 4.G - Casing Wear

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A major contributing factor to reducing the life of a casing string is poor handling throughoutthe supply chain. All personnel in this chain must adopt the proper handling procedures.

The major factors affecting casing wear are:

• Rotary speed• Tool joint lateral load and diameter• Drilling rate• Inclination of the hole• Severity of dog legs• Wear factor.

The location and magnitude of volumetric wear in the casing string can be estimated bycalculating the energy imparted from the rotating tool joints to the casing at different casingpoints and dividing this by the amount of energy required to wear away a unit volume of thecasing. The percentage casing wear at each point along the casing is then calculated fromthe volumetric wear.

Eni-Agip acceptable casing wear limit is </= 7%.

Volumetric wear is proportional to an empirical ‘wear factor’ which is defined as thecoefficient of friction divided by the volume of casing material removed per unit of energyinput.

The wear factor depends upon several variables including :

• Mud properties• Lubricants• Drill solids• Tool-joint roughness.

Note: The chemical action of gases such as H2, CO2 and O2 tends to reduce thesurface hardness of steel and, thus, contributes significantly to the rate ofwear.

4.11.2. Volumetric Wear Rate

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

Wear Volume Per Foot(V) = EnergySpecific

ftPerInputEnergy

where:

Specific Energy = The amount of energy required to wear away a unit volumeof casing material.

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The frictional energy imparted to the casing by the rotating tool joint equals:

Energy Input Per Foot = Friction Force Per Foot x Sliding Distance

where:

Friction Force Per Foot = Friction Factor x Tool Joint Lateral Load Per Foot

Sliding Distance = n x TJ Diameter x Rotary Speed x Contact Time

and:

Tool Joint Contact Time DPJL

TJLS ×=

where:

S = Drilling Distance

TJL = Tool Joint Length

P = Rate of Penetration

DPJL. = Drill Pipe Joint Length

The lateral load on the drill pipe equals:

Drill Pipe Lateral load per Foot (L) =DPJL

TJLxTJLLPF

where:

TJLLPF = Tool Joint Lateral Load Per Foot

TJL = Tool Joint Length

DPJL. = Drill Pipe Joint Length

The Wear Factor controlling the wear efficiency is defined as:

Wear Factor = Friction Factor/Specific Energy

Combining the above equations. shows that the Wear Volume, V, equals:

PS x N x D x L x F x x 60

vπ

=

where:

V = Wear Volume Per Foot (ins3/ft)

F = Wear factor (ins2/lbs)

L = Lateral Load on Drill Pipe Per Foot (lbs/ft)

D = Tool Joint Diameter (ins)

N = Rotary Speed (RPM)

S = Drilling Distance (ft)

P = Penetration Rate (ft/hr)

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The tool joint and drill pipe lengths do not appear in Equation 6 because they do not effectthe amount of casing wear in the linear model.

Note: Wear volume increases non-linearly with wear depth, because groovesbecome wider as the wear depth increases.

4.11.3. Wear Factors

Wear Factor (F)

Drilling Fluid Tool Joint (10-1 psi-l)

Water+Betonite+Barite Smooth 0.5 -

Water+Betonite+Lubricant (2%) Smooth 0.5 - 5

Water+Betonite+Drill Solids Smooth 5 - 10

Water Smooth 10 - 30

Water+Betonite Smooth 10 - 30

Water+Betonite+Barite Slightly Rough 20 - 50

Water+Betonite+Barite Rough 50 - 150

Water+Betonite+Barite Very Rough 200 - 400

Table 4.A - Typical Casing Wear Factors

Wear Factor

Drilling Fluid Tool Joint (10-1 psi-l)

Water+Betonite+Barite Rubber Protector 1 - 2

Water Rubber Protector 4 - 10

Table 4.B - Typical Casing Wear Factors (Shell-Bradley, 1975)

Mud Weight Tool Weighting Wear Factor

Drilling Fluid (lbs/al) Joint Material (10-l0psi-1)

Oil+Bentonite 10 Smooth Barite 0.9 - 1.2

Water+Bentonite 10 Smooth Barite 0.8 - 1.6

Water+Bentonite 10 Smooth Iron Oxide 3 - 4

Water+Betontite 10 Smooth Drill Solids 5 - 11

Water+Betontite 10 Smooth Sand 11 - 13

Water+Betontite 8.8 Smooth None 22 - 27

Table 4.C - Effect of Weighting Material on Casing Wear Factor (Bol, 1985)

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4.11.4. Wear Allowance In Casing Design

With the design loads recommended it is highly unlikely that a reduction in collapseresistance due to wear will be critical at shallow depths or similarly that the reduction inburst resistance will be critical at the lower end of the casing string.

The most likely wear points in a deviated wells are at the kick-off point and near surface inthe vertical portion where buckling may occur (particularly at the top of cement).

In the vertical wells, wear points may also develop at the top of cement if buckling occursbut unless there are known sudden changes in formation dip, which could cause a large‘drilled dogleg’, wear is likely to be small and uniformly spread over the entire length of thestring.

For most purposes, consideration of wear allowances can be restricted to deviated wells,with the most likely wear point at the kick-off point where burst reduction will be the primeconsideration.

Since wear estimates are order-of-magnitude calculations, it is recommended that wearallowances be considered only in cases where the burst (or collapse) resistance of thecasing at the wear point will be approached during the anticipated operating time in thestring.

In marginal cases, it may well prove cost effective to run a base caliper survey to re-surveythe casing prior to entering a hydrocarbon bearing zone (or pressure test the casing to theequivalent of the burst pressures anticipated from the zone) than to run heavy walled casingthrough all the anticipated wear sections.

The recommended procedure is therefore:

1) Conduct the casing design.

2) At the wear points, calculate the allowable reduction in wall-thickness so that the burst(or collapse) resistance of the casing just equals the burst (or collapse) load, includingthe appropriate Design Factor applied.

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

4) Calculate, from the allowable loss in wall thickness and the rate of wear, the allowableoperating time in the string.

If the allowable operating time is less than the anticipated operating time, use heaviercasing (or increases the grade) 100m above and to 60m below the wear point until theallowable operating time exceeds the anticipated operating time.

If the allowable operating time is greater than the anticipated operating time (say estimated50 days allowable versus estimated 20 days operating) do not include a wear allowance. Ifthe allowable operating time and the anticipated operating time are about the same, either:

a) include a wear allowance

or

b) monitor casing wear during drilling, and commission an intermediate string if theworn casing strength approaches the design loads.

In any given situation whether option a) or b) is exercised will be dependent upon a numberof factors, many of which are beyond the scope of routine casing design.

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Option a)

Is the conservative approach, but it may be too high, given the gross uncertainties inherentin wear estimations. However, in rank wildcats, particularly in remote locations, it may bejustified.

Option b)

Requires a base caliper survey to be run immediately after installing the casing string,followed by runs at discrete intervals during the drilling phase.

If wear is proven to have occurred, and an intermediate string has to be commissionedearly, the deeper objectives of the well may not be reached. However, conditions as drillingproceeds may indicate that the design loads assumed are not going to be encountered andthe reduction in casing strength is acceptable.

In any event, valuable data on casing wear in the area will be obtained and field practicesmay be improved as result of the attention paid to wear, eventually leading to a reduction inoverall wear rates.

In most cases, option b) is preferred.


There is no reliable method of predicting casing wear and defining the correspondingreduction in casing performance. Because the reduction in burst and collapse rating isdirectly proportional to wall thickness the revised theoretical value may be calculated.

The normal procedure to cater for possible wear when designing casing is to select the nextcasing grade or wall thickness, therefore, in a vertical well, casing wear is usually in the firstfew joints below the wellhead or intervals with a high dogleg severity.

Consideration should be given to increasing the grade or wall thickness of the first few jointsbelow the wellhead.

In deviated wells, wear will be over the build-up and drop-off sections. Again the casing overthese depths can be of a higher grade or heavier wall thickness.

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4.12. SALT SECTIONS

Salt formations often exhibit plastic flow properties which can cause exceedingly high loadson casing. The rate of salt flow is a function of its composition, temperature, depth oroverburden pressure and also probably influenced by how it is bedded or interbedded withother formations.

The problem of salt formations has to be assessed on an individual well to well and/or areato area basis.

The objectives for drilling through salt zones should be:

• To achieve trouble free drilling.• Prevent casing collapse during the drilling and the production life of the well.

With regards to trouble free drilling, sticking due to salt flow, mud problems from saltcontamination, hole enlargement and the well's overall casing programme, are the primefactors to be considered.

There are other factors that have to not be under evaluated such as:

• Control of gas flows from porous zones interbedded in the salt, differentialsticking in porous zones.

• Abnormal pressure due to entrapment of pressure by salt• Shale sloughing from interbedded or boundary shales.

To prevent casing collapse, the designer should plan for non-uniform salt loading, obtainingthe best possible cement job, using casing with higher than normal collapse ratings andpossibly two strings of casing through the salt section.

In some cases, two strings may be more advantageous as experience has demonstratedthat it is not practical to design a casing string to resist collapse. This technique is probablythe most reliable and safest approach for preventing casing collapse but is probably notnecessary in the majority of salt sections.

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In designing casing for any application, the accepted design load is the one for which thecasing is subjected to the greatest conceivable loads.

In the particular case of casing design opposite salt formations, certain guidelines can beconsidered:

• For production casing exposed to salt formations, assume the casing will bealways evacuated at some point during the well life.

• The uniform external pressure exerted by salt on the casing (or cement sheath)due to overburden pressure should be given a value equal to the true verticaldepth to the point in question.

• Proper cement placement opposite a salt section is often difficult due towashout.

• Any beneficial effects of the cement sheath should be ignored during design ofthe casing.

• If the wellbore is deviated, additional axial forces due to hole curvature shouldbe considered when determining the collapse resistance of the casing.

Conclusions:

• Running casing in salt sections is rather a cementing problem than a casingproblem.

• If the pipe is well cemented, it is sufficient to design for collapse load in thetraditional mode (overburden pressure/design factor).

• If the casing is poorly cemented the collapse effect may be very high. In thiscase, it may help to run heavier wall casing.

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4.13. CORROSION

A production well design should attempt to contain produced corrosive fluids within tubing.They should not be produced through the casing/tubing annulus.

However, it is accepted that tubing leaks and pressured annuli are a fact of life and as such,production casing strings are considered to be subject to corrosive environments whendesigning casing for a well where hydrogen sulphide (H2S) or carbon dioxide (CO2) ladenreservoir fluids can be expected.

During the drilling phase, if there is any likelihood of a sour corrosive influx occurring,consideration should be given to setting a sour service casing string before drilling into thereservoir.

The BOP stack and wellhead components must also be suitable for sour service.

4.13.1. Exploration And Appraisal Wells

Routine measures to be taken during drilling include:

• Use of casing and wellhead equipment with a metallurgy suitable for sourservice.

• Use of high alkaline mud to neutralise the H2S gas.• Use of inhibitors and/or scavengers.

These measures will provide a degree of short term protection necessary to controlcorrosion of the casing in the hole during the drilling phase.

4.13.2. Development Wells

Casing corrosion considerations for development wells can be confined to the productioncasing only.

Internal corrosion

The well should be designed to contain any corrosive fluids (produced or injected) within thetubing string by using premium connections.

Any part of the production casing that is likely to be exposed to the corrosive environment,during routine completion/workover operations or in the event of a tubing or wellhead leak,should be designed to withstand such an environment.

External corrosion

Where the likelihood of external corrosion due to electrochemical activity is high and theconsequences of such corrosion are serious, the production casing should be cathodicallyprotected( either cathodically or by selecting a casing grade suitable for the expectedcorrosion environment).

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4.13.3. Contributing Factors To Corrosion

Most corrosion problems which occur in oilfield production operations are due to thepresence of water. Whether it may be present in large amounts or in extremely smallquantities, it is necessary to the corrosion process. In the presence of water, corrosion is anelectrolytic process where electrical current flows during the corrosion process. To have aflow of current, there must be a generating or voltage source in a completed electricalcircuit.

The existence, if any, of the following conditions alone, or in any combination may be acontributing factor to the initiation and perpetuation of corrosion:

Oxygen (O2)

Oxygen dissolved in water drastically increases its corrosivity potential. It can cause severecorrosion at very low concentrations of less than 1.0 PPM.

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.

Carbon dioxide (CO2)

When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of thewater and increase its corrosivity. It is not as corrosive as oxygen, but also usually results inpitting.

The important factors governing the solubility of carbon dioxide are pressure, temperatureand composition of the water. Pressure increases the solubility to lower the pH, temperaturedecreases the solubility to raise the pH.

Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’corrosion.

The partial pressure of carbon dioxide can be determined by the formula:

Partial Pressure = Total pressure x Mol Fraction of C02 in the gas

Example:

In a well with a bottom hole pressure of 3,500psi and a gas containing 2% carbon dioxide:

Partial pressure = 3,500 x 0.02

= 70psi

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Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the followingrelationships have been found:

• Partial pressure > 30 psi usually indicates high corrosion risk.• Partial pressure 3-30 psi may indicates high corrosion risk.• Partial pressure < 3 psi generally is considered non corrosive.

Hydrogen Sulphide (H2S)

Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acid andusually causes pitting. Attack due to the presence of dissolved hydrogen sulphide isreferred to as ‘sour’ corrosion.

The combination of H2S and CO2 is more aggressive than H2S alone and is frequently foundin oilfield environments.

Other serious problems which may result from H2S corrosion are hydrogen blistering andsulphide stress cracking.

It should be pointed out that H2S also can be generated by introduced micro-organisms.

Temperature

Like most chemical reactions, corrosion rates generally increase with increasingtemperature.

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. Moregas goes into solution as the pressure is increased this may in turn increase the corrosivityof the solution.

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 washed off thecasing 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.

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4.13.4. Casing For Sour Service

All temperatures (1) 150° F (65°C) (3) or greater 175° F (80°C) or greater

API Specification 5CT GradeH40, (2) K55 and J 55

API Specification 5CT GradeN80 (Q and T)

API Specification 5CT GradeH40, N80

Grade C75 (2)

and L80

Grade C 95 Grade P110

Proprietary Grades:

see NACE standard

MR-01-75

Proprietary Grades:

Q and T, with a maximum yieldstrength of 100,000psi

(689,475kPa)

Proprietary Grades:

with 110,000psi

(758,420kPa) minimum to140,000psi (965,265kPa)max. yield strength

Q and T = quenched and tempered.

1) Impact resistance may be required by other standards and codes for low operatingtemperatures.

2) 80,000 psi (551,580kPa) maximum yield strength permissible. The latest revision ofAPI Specification 5CT includes this requirement.

3) Continuous minimum temperature; for lower temperatures, select from column 1.

Table 4.D - Operation Temperature

4.13.5. Ordering Specifications

When ordering tubulars for sour service, the following specifications should be included, inaddition to those given in the above table.

a) Downgraded grade N 80, P 105 or P 110 tubulars are not acceptable for ordersfor J 55 or K 55 casing.

b) The couplings must have the same heat treatment as the pipe body.

c) The pipe must be tested to the alternative test pressure (see API Bulletins 5Aand 5 AC).

d) Cold die stamping is prohibited, all markings must be paint-stencilled or hot diestamped.

e) Three copies of the report providing the ladle analysis of each heat used in themanufacture of the goods shipped, together with all the check analysesperformed, must be submitted.

f) Three copies of a report showing the physical properties of the goods suppliedand the results of hardness tests (Refer to step 3 above) must be submitted.

g) Shell modified API thread compound must be used.

Note: Recommendations for casing to be used for sour service must bespecified according to the API 5CT for restricted yield strength casings.

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The casing should also meet the following criteria:

• The steel used in the manufacture of the casing should have been quenchedand tempered. (This treatment is superior to tubulars heated/treated by othermethods e.g. normalising and tempering).

• All sour service casing should be inspected using non-destructive testing orimpact tests only, as per API Specification 5CT.


CO2 Corrosion

The following guidelines should be used for the appropriate corrosive environment.

• In exploration wells, generally the presence of CO2 in the formation causes littleproblems, and will have no influence on material selection for the casing.

• In producing wells, the presence of CO2 may lead to corrosion on those partscoming in contact with CO2 which normally means the production tubing andpart of the production casing below the packer.

Corrosion may be limited by:

• The selection of high alloy chromium steels, resistant to corrosion.• Inhibitor injection, if using carbon steel casing. Generally, wells producing CO2

partial pressure higher than 20 psi requires inhibition to limit corrosion.

H2S Corrosion

In exploration wells, if there is high probability of encountering H2S, consideration should begiven to limit casing and wellhead yield strength according to ‘API’ 5CT and ‘NACE’standard MR-01-75.

In producing wells, casing and tubing material will be selected according to the amount ofH2S and other corrosive media present.

Refer to figure 4.hand figure 4.i for partial pressure limits.

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Figure 4.H - Sour Gas Systems

Figure 4.I - Sour Multiphase Systems

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Figure 4.J - Sumitomo Metals

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Application Domain Material SM’Designation

Notes

Mild Environment Domain ‘A’ API J55 N80 P110 (Q125)

SM 95G SM 125G

Sulphide Stress CorrosionCracking (medium pressureand temperature)

Domain ‘B’ Cr or Cr-Mo Steel API L80 C90 T95

SM 80S SM 90S SM 95S

Sulphide Stress CorrosionCracking (high pressure andtemperature)

Domain ‘C’ 1Cr 0.5Mo Steel Modified AISI 4130

SM 85SS SM 90SS SM C100 SM C110

Higher yield strengthfor sour service

Wet CO2 Corrosion Domain ‘D’ 9Cr-1Mo Steel SM 9CR 75 SM 9CR 80 SM 9CR 95

Quenched andtempered

13Cr Steel Modified AISI 420

SM 13CR 75 SM 13CR 80 SM 13CR 95

Quenched andtempered

Wet CO2 with a little H2SCorrosion

Domain ‘E’ 22Cr 5Ni 3Mo Steel 25Cr 6Ni 3Mo Steel

SM 22CR 65* SM 22CR 110** SM 22CR 125** SM 25CR 75* SM 25CR 110** SM 25CR 125**SM 25CR 140**

Duplex phaseStainless steels * Solution Treated ** Cold drawn

Wet CO2 with H2S Corrosion Domain ‘F’ 25Cr 35Ni 3Mo Steel 22C 42Ni 3Mo Steel 20Cr 35Ni 5Mo Steel

SM 2535 110 SM 2535 125 SM 2242 110 SM 2242 125 SM 2035 110 SM 2035125

As cold drawn

Most Corrosive Environment Domain ‘G’ 25Cr 50Ni 6Mo Steel 20Cr 58Ni 13Mo Steel 16Cr 54Ni 16Mo Steel

SM 2550-110 SM 2550-125 SM 2550-140 SM 2060-110*** SM 2060-125*** SM 2060-140*** SM 2060-155*** SM C276-110*** SM C276-125*** SM C276-140***

As cold drawn *** Environment

with freeSulphur

(Refer to figure 4.j)

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4.14. TEMPERATURE EFFECTS

For deep wells, reduction in yield strength must be considered due to the effect on steel byhigher temperatures.

It no information is available on temperature gradients in an area, a gradient of 3°C/100mshould to be assumed (Refer to section 2.3).

Use figure 4.k below for reductions in yield strength against temperature.

Figure 4.K - Temperature Effects

4.14.1. Low Temperature Service

Operations at low temperatures require tubulars made from steel with high ductility at lowtemperatures to prevent brittle failures during transport and handling.

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4.15. LOAD CONDITIONS

When running casing, shock loads are exerted on the pipe due to:

• Sudden deceleration forces (e.g.: if the spider accidentally closes or the slipsare kicked-in when the pipe is moving or the pipe hits a bridge).

• Sudden acceleration forces (e.g.: picking the pipe out of the slips or if the casingmomentarily hangs up on a ledge then freed).

Either of the above will cause a stress wave to be created which will travel through thecasing at the speed of sound.

This effect is quantified as follows:

SL = 150 x V x Af

Where:

SL = Shock load (lbs x ins2)

V = Peak velocity when running (ins/sec)

Af = Cross-sectional area (ins2)

150 = Speed of sound in steel (lbs x sec/ins)

4.15.1. Safe Allowable Pull

The safe allowable pull must be calculated and stipulated during the casing string designprocess and communicated to the well site prior to running casing, particularly, whenreciprocating pipe during the cementing procedure.

The application of the pulling load should only be considered as an emergency measure toretrieve the casing string from the wellbore. It is normal to incorporate in the casing stringdesign an overpull contingency of 100,000lbs (45t), over the weight of the string in mud.

4.15.2. Cementing Considerations

The cement sheath can protect the casing against several types of potential downholedamage including:

• Deformation through perforating gun detonations.• Formation movement, salt flows, etc. (Refer to previous section 4.13).• Loss of bottom joint on surface/intermediate strings during drilling.

However, the following aspects need to be considered:

• Adding resistance to casing collapse for design purposes is questionable.• In fault slippage zones, doglegs and certain sand control failures, the cement

sheath may contribute to problems.

As a cement slurry is pumped into the casing, the weight indicator increases to a maximumwhen mud has been displaced from the casing by the full amount of cement.

The maximum weight of the string occurs when the cement reaches the casing shoe orwhen the top cement plug is released.

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This weight increase can approach the remaining allowable pull in the string. If reciprocationis contemplated, this problem may be severe enough to prevent reciprocation and, hencestretching the pipe. After considering the above loading, the design engineer may decidethat a higher allowable pull is required.

For design calculation, a worst case situation is assumed as follows:

• The mud weight in the annulus is the lowest planned for the section.• The inside of the casing is full of cement slurry, with mud above.• The shoe instantaneously plugs-off just as the cement reaches it and the

pressure rises to a value of circa ‘1,000psi’ before the pumps are able to beshut-down.

The load is calculated as follows:

CCL = [(Cw - Mw) x D + 1000] x Ai

where:

CCL = Cementing contribution load (lbs)

Cw = Cement weight (psi/ft)

Mw = 0utside mud weight (psi/ft)

D = Length over which Cw & Mw act(ft)

Ai = Internal area of casing (ins2)

1,000 = Pressure increment (psi)

4.15.3. Pressure Testing

Casing pressure tests will be carried out according to the pressure stated in the drillingprogramme.

When establishing an internal casing pressure test, the differential pressure due to adifference in fluid level and/or fluid density, inside and outside the casing, shall be takeninto account.

Each casing shall be pressure tested at the following times:

• When cement plug bumps on bottom with a pressure stated in the drillingprogramme.

• When testing blind/shear rams of the BOP stack against the casing.• After having drilled out a DV collar.

4.15.4. Company Guidelines

The leading criteria for pressure testing will be the maximum anticipated wellhead pressure.

In all cases the test pressure will be no higher than 70% of API minimum internal yieldpressure of the weakest casing in the string or to 70% of the BOP WP.

The test pressure shall remain stable for at least 5 - 10 minutes.

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4.15.5. Hang-Off Load (LH)

The Hang-off load required for a casing is obtained as per algebraic amount of the followingloads:

LH= Pa + L1 + L2 + L3 + Fc

Where:Pa = weight in air of the not cemented casingL1 = stress due to variation of internal pressureL2 = stress due to variation of external pressureL3 = stress due to variation of average temperatureFc = critical force (take into account only if it is positive)

l1a = -0.6 ID2 π/4 (γ2 - γ1)/2 H/10 (for inside casing mud weight variation)L1 = l1b = 0.03 ID2 π/4 (2N – N2/10) γ0 (for inside casing mud level drop)

l1c = -0.6 ID2 π/4 Pi (for inside casing pressure applied)

l2a = 0.6 OD2 π/4 (γ2 - γ1)/2 H/10 (for outside casing mud density variation)L2 = l2b = 0.03 OD2 π/4 (2M – M2/H) γ0 (for inside casing mud level drop “m”)

l2c = 0.6 OD2 π/4 OD2 Pe (for outside casing pressure applied)

∆tm = ∆tm2 - ∆tm1

L3 = 26 (OD2 – ID2) π/4 ∆tm ; with ∆tm1 = tf1 + (ts1-tf1)/2 H/S

∆tm2 = tf2 + (ts2-tf2)/2 H/S2

Fc = Pi ID2 π/4 – Pe OD2 π/4

H = uncemented casing lengthID = inside diameterM = outside casing mud level dropN = inside casing mud level dropOD = outside diameterPi = inside pressure applied at casing headPe = outside pressure applied at casing headS = casing setting depthS2= end of the next phasetf1= flow line mud temperature when the well is at “S”ts1= static bottom hole (S) temperaturetf2= flow line mud temperature when the well is at “S2”ts2= static bottom hole (S2) temperature

γγ0 = mud density at the time of the inside casing mud level drop

γγ1 = mud density during cementing job

γγ2 = max mud density during the next drilling phase

∆∆tm = temperature total variation

∆∆tm1 = variation of temperature at shoe depth

∆∆tm2 = variation of temperature at the end of the next phase

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5. MUD CONSIDERATIONS

5.1. GENERAL

For full information on drilling fluids preparation, refer to Eni-Agip’s Drilling Fluids Manual.

a) A detailed mud programme shall be included as an integral part of the drillingprogramme.

b) A Mud Service Contractor may be contracted for the preparation of the mudprogramme, which shall be submitted to the Company Drilling Office for approvalbefore to integrate into the Drilling Programme.

c) The same Contractor may be contracted for Mud Engineering on rig site under thecontrol of the Company Drilling and Completion Supervisor.

d) No variation from the mud program is permitted without previous discussion with andapproval of the Company Shore Base Drilling office.

e) The mud characteristics to be used for specific operations, such as tripping, casingrunning, etc., shall be based on specifications described the relevant sections of theDrilling Programme.

5.2. DRILLING FLUID PROPERTIES

Drilling fluids serve many purposes but their primary functions are to

• Lift formation cuttings to surface• Control subsurface pressures• Lubricate the drill string• Clean the hole• Aid in formation evaluation• Protect formation productivity

5.2.1. Cuttings Lifting

Clearing the hole of cuttings is an essential primary function of a drilling fluid system and isoften the most misinterpreted and abused. Drill solids are heavier than the mud and willtend to slip downward against the flow. This slip velocity when the fluid is in viscous oflaminar flow is directly affected by the thickness or shear characteristics of the mud. Therelationship between mud velocity and thickness to enable cutting removal is important andif velocity is low due to pump rate or enlarged hole sections, then the mud must bethickened and vice versa.

Water based muds are thickened by adding bentonite, large volumes of solids, flocculationor by the use of special additives. This provides the operator with a choice of options,however the use of bentonite is the most popular as it is relatively cheap. When usingbentonite, sometimes a thinner needs to be added to prevent flocculation and water losscontrol problems.

The use of large quantities of solids is an undesirable solution if it is not required to increasemud weight for subsurface pressure control. Usually a mud selection is a compromise of allthe various problem solutions and often the lifting capability is not effective. What may havebegun as a simple mud thickening problem is complicated by the resulting effects on theother mud objectives.

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5.2.2. Subsurface Well Control

It is always desirable to utilise the lowest possible mud weight to achieve maximum drillingrate and lost circulation problems are minimised. However, the hydrostatic pressure appliedby the mud must be greater than the highest formation pressures to effect pressure control.

To determine the mud weight required, it is necessary to obtain predicted formation porepressures and the fracture gradient. The mud weight selected must exceed the formationpore pressures in each section but to minimise drilling problems and still not exceed thefracture pressure. This is sometimes a fine balancing act between satisfying well controland not exceeding the rock strength in weak zones.

Formation pressure and temperature prediction is usually found be using offset well databut can also be predicted (refer to section 2). Normal formation pressure gradients are0.465psi/ft but vary from region to region. It is important that overpressure are predicted andmonitored for during drilling.

Once the formation pressures for a section are known, a safety margin must be added andthen mud weight calculated:

052.0TVD

inargMSafetyPMW F

×+

=

where:

MW = Mud weight, ppg

PF = Formation pressure, psi

TVD = True vertical depth, ft

Example: A formation pressure has a pressure of 4,020psi at 8,500ft, a safety margin of600psi is desired, what is the required mud weight ?.

ppg42100520ft5008

psi600psi0204MW .

.,,

=×+

=

Safety margins are usually around 0.2ppg but may vary according to conditions.

Example, a mud with a 700psi safety margin at 10,000ft will only provide a 350psi margin at5,000ft. It may be decided to use an increased mud weight at the shallower depths if themargin is too small.

To calculate pressure at a given depth and mud weight the calculation is:

TVDxMWx052.0PH =

Mud weight is increased by the addition of heavy solids.

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5.2.3. Lubrication

Lubrication and cooling are also important functions of the mud. Working life of expensiveequipment can be prolonged by adequate cooling and lubrication. Problems such asexcessive torque, drag and differential sticking are also reduced.

Lubricants include bentonite, oil, detergents, graphite, asphalts, special surfactants andwalnut shells. Bentonite acts as a lubricant by reducing friction between the wall cake andthe drill string. Oil is less used today due to the environmental impact and disposal problemsand similar to graphite as it also requires oil as a carrier. Asphalt is usually added for itsother properties but also acts as a lubricant. Surfactants have been claimed to lubricate butthis should be analysed as they are more expensive.

5.2.4. Bottom-Hole Cleaning

Thin fluids with high shear rates through the bit are the most effective at hole cleaning andmeans that viscous fluids can be used if they have shear-thinning characteristics. In generalfluids with low solids contents are more effective in hole cleaning.

5.2.5. Formation Evaluation

Drilling fluids have been effect greatly by the requirement for quality formation evaluation.Viscosity may be increase to ensure improved cutting lift, filtration may be reduced toreduce fluid invasion or special fluids used instead of the mud system for logging and welltesting. The procedures for mud conditioning before logging have become standard today.

The type of mud will also have an effect, e.g. oil based mud make evaluation of potentialproducing formations difficult and salt water fluids can mask permeable zones.

Thick filter cake can interfere with side wall coring information and water or oil invasionaffects resistivity logs.

The formation evaluation programme must take all of these considerations into account toobtain the best results.

5.2.6. Formation Protection

In the past it has been proven that the drilling process and fluids will cause damage toproducing formations and the utmost precautions should be taken to minimise this damage.The ideal protection policy is to keep all foreign fluids away from the formation, however inmost cases this is impractical, unless air drilling, and hence the drilling fluid should beselected according to conditions. For instance, oil based mud can be used when it isdesirable to keep water off a zone, however oil based mud may be more damaging to gaszones than salt water fluid, etc. Salt water fluid with high calcium content have also beeneffective.

To help minimise invasion, reduction in the filtration rate may be employed but reliance onstatic surface testing as assurance may be misleading on actual downhole filtration rates.

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5.3. MUD COMPOSITION

The composition of drilling mud is a mixture of the base fluid (see the list of liquids below),solids and chemical additives.

• Fresh Water• Salt water• Oil• Mixture of above

The base fluid for most muds is fresh water as it is usually readily available and is cheap.Seawater has become more widely used due to the increase in offshore drilling for obviousreasons. Oil based mud is very popular when it is desired to reduce the amount of water inthe system. Two types of oil based mud are available, an oil mud that has less than 5%water by volume and invert emulsion which is between 5 and 50%.

5.3.1. Salt Muds

Salt added to water will provide a range of weights according to the type and amount of saltadded. The maximum weight ranges for various types of brines are:

Kcl up to 9.6ppg (1,150kg/m3)

NaCl2 up to 10.0ppg (1,200kg/m3)

CaCl2 10.0 to 11.6ppg (1,200-1,390kg/m3)

The following figures show amount of salt and water required to achieve the range of brinedensities.

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Figure 5.A - Material Required For Preparation Of Potassium Chloride Solutions (20o)

Figure 5.B - Material Required For Preparation Of Sodium Chloride Solutions (20o)

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Brine weight is affected by temperature and it is necessary to obtain the average welltemperature in order to determine the density reduction from that when it was prepared atsurface. figure 5.c below shows brine densities at various temperatures.

Average well temperature 2

tempholeToptempholeBottom +=

Figure 5.C - Density Vs Temperature For Brine

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If drilling through salt beds or sections, the drill fluid should be saturated which will preservehole geometry avoiding enlargement. When working with salt at saturation point, it is notuncommon to find salt deposited in the lines and surface tanks with temperature drop.

For brine densities below 1,050kg/m3, it is recommended to include 1-3% by weight of KClin the brine formulation to inhibit interaction between the fluid and water sensitive clays inthe formation.

Potassium is rarely used in concentrations above 0.4ppg as sodium chloride may be usedwhich is considerably cheaper. Sodium chloride is a cheap brine and has good solubilitywhich varies little with temperature. Calcium chloride is used in the higher weight range butshould be prepared with seawater as precipitates may form and the sodium chloride contentmay crystallise if the weight range is above 1,320kg/m3.

5.3.2. Water Based Systems

High weight mud systems usually contain more solids than low weight systems. Extra solidsin high weight mud originate from the gels, chemicals, weight material and drill solids fromthe rock. Good solids control systems and the proper addition of water and chemicals willeliminate solids build up and problems. figure 5.d shows a field developed guidelines forsolids level in water muds.

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Figure 5.D- Guidelines for Clay Based Mud Systems

5.3.3. Gel Systems

The commercial clays added to the mud system are bentonite and attapulgite. Bentonite isadded to increase viscosity, gel strengths and suspension. filtration and filter cakeproperties are also improved with bentonite. Drilled solids also enter the system duringdrilling. If flocculation of bentonite occurs then a dispersant should be added. Attapulgite isused where bentonite does not react properly.

5.3.4. Polymer Systems

Polymers have been used mainly in completion and workover operations requiring minimumsolids content, hence reducing formation damage.

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5.3.5. Oil Based Mud

As pointed out earlier oil based muds are used to reduce torque and/or drag beneficial indrilling directional wells and where water based muds may cause hole damage such as inshales. Oil mud is only less damaging if the water phase is dosed with salt to a higherconcentration of that in the formations to prevent the water being pulled out and, hencecausing sloughing. The salt used for this is usually calcium chloride due to its good solubilityproperties.

Lime must be added to oil mud to convert sodium salts into calcium soaps and combatproblems associated with carbon dioxide and hydrogen sulphide intrusion.

Changing from water based to oil based mud may cause contamination in long sections ofopen hole will have absorbed a considerable amount of water, therefore should berestricted to cased hole only.

Oil based mud was treated as special purpose mud due mainly to its high cost incomparison to water based mud, however with today’s restocking arrangements availablewith the suppliers it has become much more economic. In general terms, the costs of drillingwith oil based mud is considered to be 30% less than for comparable water based weightmud thought to be due getting more efficient weight on the bit. The hindrance to the use ofoil based mud is the environmental disposal of coated cuttings.

5.4. SOLIDS

Solids are divided into two groups, low and high gravity. The low gravity solids are furthersubdivided into reactive and non-reactive groups. Reactive and non- reactive refers towhether they react to changing downhole conditions. Low gravity solids include sand chert,limestone, dolomite, some shales and mixtures of other minerals.

Non-reactive solids are undesirable and if larger than 15 microns in size, they are erosive tocirculating equipment.

The size of solids in microns and inches with the appropriate screen sizes are given in table5.a below:

Microns Inches Shaker Screen Size

1540 0.0606 12 x 12

1230 0.0483 14 x 14

1020 0.0403 16 x 16

920 0.0362 18 x 18

765 0.0303 20 x 20

Table 5.A - Solids Size Versus Screen Size

Reactive solids are clays which are reactive to water. The most common clays used arebentonite or gel and attapulgite (salt gel). Bentonite is used to both add thickness andviscosity to the mud and control fluid loss.

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5.5. DENSITY CONTROL MATERIALS

To drill a well successfully, the formation pressure must be controlled by the hydrostaticweight of the mud. A mud system will normally gain weight due to the addition of drilledsolids if proper mechanical solids control equipment is not used or is inefficient. Thesesolids are undesirable in high mud weight systems as they cause problems when weightingmaterials are added.

Common weighting materials are shown in table 5.b below:

Material Average SG Max Mud Weight (ppg)

Barite 4.25 20-22

Lead Sulphide 6.6 28-32

Calcium Carbonate 2.7 12

Ilmenite 4.5 21-26

Hematite (Itagrite ore) 5.1 24-26

Table 5.B- Common Weighting Materials

Water based fluids can be weighted up by salts.

5.6. FLUID CALCULATIONS

The following equations are provided for an engineer to be able to calculate materialrequirements, stock levels and mud weights. The symbols listed below are used in thefollowing equations and examples. These or variations in these may be found in any drillingfluids handbook.

WO = Weight of original mud, lbs

WA = Weight of material added, lbs

WF = Weight of final mud, lbs

VO = Volume of original mud, gal

VA = Volume of material added, gal

VF = Volume of final mud, gal

DO = Weight of original mud, ppg

DA = Weight of material added, ppg

DF = Weight of final mud, ppg

w = Weight of material added to original mud, lbs/bbl

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Calculation of solids material required to increase mud weight.

Equation:

( )

A

F

OF

D

D1

DD42w

−

−=

Example: A mud system contains 750bbl of 10.4ppg mud, how many sacks of barite arerequired to increase the density to 12.4 ?.

( )bbllb130

435412

1

41041242w /

.

...

=−

−=

Total barite required:

975sklbs100

bbslbs130xbbl750==

/

/

Calculation of density resulting from adding liquid to decrease mud weight.

Equation:

( )AOF

AOF DD

V

VDD −−=

Example: A mud system contains 800bbl of 11.3ppg mud, what is the resulting density ofadding 100bbl of 42o API oil ?.

Calculate SG of oil:

SG8160513142

5141SG .

..

=+

=

Calculate density of oil:

ppg806338x8160DA ... ==

Calculate VF:

bbl900

bbl100bbl800VF

=+=

( )ppg8.10

80.63.11900

1003.11DF

=

−−=

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Calculation of density by adding solids to a mud.

Equation:

A

O

F

Dx42w

1

42w

DD

+

+=

Example: 10 tons of barite were added to 800bbl of 9.2ppg mud, what was the final densityof the mud ?.

First calculate w:

bbl/lbs25

bbl800

lbs000,2xt10w

=

=

Calculate final density:

ppg63.9

4.35x4225

1

4225

2.9DF

=

+

+=

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5.7. MUD TESTING PROCEDURES

The following table summarises the common mud field testing procedures. Refer to API RP13B for Standards Mud Testing Procedures.

Test Water Based Mud Oil Based Mud

Mud weight Mud balance Mud balance

Viscosity Marsh funnel & graduated cup Marsh funnel & graduated cup

Sand content Sand content kit N/A*

Rheology n(PV, YP) Viscometer Viscometer

Shear strength (non-pressurised

Shearmeter Shearmeter

Low pressure filtration (100psi) API filter press Usually not applicable exceptwith a relaxed filtration mud

High pressure filtration HP/HT Press HP/HT Press

Static pressure filtration High temperature pressurisedaging cells

High temperature pressurisedaging cells

Hydrogen ion determination Modified calorimetric method(pHydrion dispenser) orelectrometric method (pHmeter)

N/A*

Oil, water, solids determination Retort kit Retort kit for determination ofO/W ratio

Bentonite content Methylene blue kit N/A*

Chloride content Potassium chromate, silvernitrate

N/A*

Water phase salinity and totalsoluble salts

N/A* Measurement of calciumchloride and sodium chloridecontent %BWOW

Alkalinity N-50 sulphuric acid,phenolphthalien or methylorange

N/A*

Calcium and magnesium Versentate hardness test N/A*

Electrical stability N/A Voltage breakdown meter

* Not applicable in most cases or is not customarily evaluated.

Table 5.C - Common Mud Testing Equipment and Chemicals

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The following mud properties in the units shown below shall be included in the Drillingprogramme. These shall be clearly checked, recorded; and also reported to CompanyDrilling Office on a daily basis:

Weight kg/lTemperature (especially in oil mud) °CFunnel viscosity secs/gal/4Plastic viscosity centipoiseYield point g/100cm2

Gel strengths g/100cm2

Water losses cm3/30mins

Filter cake millimetresSand content % by volumeSolids content % by volumeOil content % by volume

Calcium content mg/l Ca++

Salinity g/l Cl-

5.8. MINIMUM STOCK REQUIREMENTS

a) Minimum stock requirements for mud weighting materials, chemicals, pipe freeingagent, dispersant, lost circulation material, cement, kill and reserve mud on the rig,depends on the well pressure prognosis, severity of potential drilling problems and rigload capacity.

b) The minimum barite stock shall be 100t. When overpressurised formations areanticipated, barite stock shall be based on expected formation pressure gradients, onthe actual mud weight and on the volume of the active drilling fluid in the system.

c) The minimum cement stock shall be 100t. or at least enough to prepare 200m ofcement plug.

d) A minimum volume of 70m3 of kill mud at 1.4kg/l shall be stocked while drilling surfacehole without a BOP stack installed.

e) After nippling up a BOP stack, minimum requirements for kill mud cannot be specified.The volume and density of kill mud shall be adjusted to the well pressure prognosisand pit volumes available on the rig.

f) Properties of reserve and kill mud should be checked and maintained daily andrecorded the mud report.

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g) In addition, the following material is recommended to be available on board forcontingencies:

• A stock of diesel oil, enough to guarantee five day of operations.• Pipe freeing agent. The quantity shall be sufficient to prepare two pills, the

volume of each one shall be two times the capacity of the annulus openhole/BHA.

• Dispersant - 20 drums• Mica (fine, medium and coarse) -1.5t of each• Wall Nut - 3t• Viscosifier for salt water (i.e. Biopolymer): the quantity shall be enough to

prepare 200m3.

The inventory of materials on board should be reviewed daily and replenishment arrangedimmediately when stock levels approach the specified minimum requirement. With regard tobarite, cement and diesel oil, should the stocks fall below the minimum requirement, drillingoperations shall be suspended.

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6. FLUID HYDRAULICS

The Eni-Agip IWIS (ADIS) software programme is currently used for all hydraulicprogrammes and provides all the necessary information to be input into the ‘GeologicalDrilling Programme’. However it is necessary for drilling engineers to be armed withsufficient information to use the ADIS programme and plan for drilling operations.

There are some company guidelines that are helpful in fulfilling this objective outlined in thefollowing sub-sections but more detailed information can be found in the company’s ‘MudManual’.

6.1. HYDRAULICS PROGRAMME PREPARATION

Before the design of a hydraulics programme can commence, the following informationabout the well and drilling equipment should be ascertained:

a) Drilling contractor

b) Drilling unit

c) Hole sizes

d) Depth intervals

e) Mud weights at the various depths

f) Whether plastic viscosities are expected

g) Pumps:

• Manufacturer, type and model• Number of pumps• Horsepower available• Liner sizes available• Max pump speed• Min pump speed• Max pump pressure.

h) Minimum annular velocity

i) Length and ID of standpipe, swivel, kelly hose and kelly (or top drive)

j) Drill string design

k) Priority for the hydraulics programme, i.e. max bit hydraulics, max jet impactforce, constant pump speed or variable pump speed

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6.2. DESIGN OF THE HYDRAULICS PROGRAMME

The first priority of a hydraulics programme is to maximise bottomhole cleaning. Hydraulicdesign methods include:

• Hydraulic Impact• Bit Hydraulic Horsepower• Nozzle Velocity• A combination of these Methods

Regardless of the design method to be used, the first step is to determine the maximumsurface hydraulic horsepower available. This is calculated by using the following equation:

1741PQ

Hp =

where:

Hp = Surface horsepower available

P = Maximum permitted surface pressure

Q = Maximum flow rate

The following example illustrates a typical calculation:

Maximum permissible surface pressure: 3,000psi

Maximum flow rate: 600gpm

Available horsepower:

034,11741

6003000Hp =

×=

If the pump size is 1,500HP then it is capable of delivering the required 1,034HP:

6.3. FLOW RATE

The flow rate must be maintained high enough to achieve two functions, to provide enoughvelocity to remove cavings and cuttings and the jetting requirements of the bit for each holesection. Upward flow velocities of 100-200ft/min are usually sufficient in normal conditions.

Obviously this demands much higher circulation volumes when drilling larger hole sizes.The recommended flow rates for the standard bit size are given in table 6.a:

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Hole Size [ins] Flow Rate [l/min]

171/2” 3,000-4,000 15” 2,800-3,500

121/4” 2,200-2,600 97/8” 1,500-1,900 81/2” 1,200-1,600 77/8” 1,200-1,600 63/4” 800-1,000 6” 600-800

Table 6.A- Rates for the standard casing design

Optimum annular velocity can also be calculated by the following equation:

Optimum Annular Velocity DHMW

8.11+

=

where:

MW = Mud weight, lbs/gal

DH = Diameter of hole, inches

From a given flowrate, annular velocity can be calculated as follows:

Annular Velocity 22 DPDH

)Q(51.24

−=

where:

Q = Flow, gal/min

DH = Diameter of hole, ins

DP = Diameter of pipe, ins

The flow rate must also maintain good hole condition so that erosion does not occur orcause invasion of formations that may damage potential producing zones. Rates ofcirculating above that necessary simply to maintain good hole conditions can be used toobtain faster drilling rates. The additional horsepower and pumping equipment required forthis due to increased friction losses must be justified to ensure economy.

Critical annular velocity is expressed by:

Critical Annular Velocity ( )( )[ ]

MW)DPDH(

MWYPDPDH04.3PV8.64

×−

××−×+=

where:

PV = Plastic velocity

YP = Yield point

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6.4. PRESSURE LOSSES

Pressure losses are calculated using Bernoulli’s Theorem. Considering two points in acirculating system, the following equation may be used:

WFp

g2

UhWF

p

g2

Uh

2

222

1

111

22

+−ρ

+=+−ρ

+

where:

h = Height above a chosen reference elevation, ft

U = Flow velocity, ft/sec

P = Pressure of the fluid, lbs/ft2

ρ = Density of the fluid, lbs/ft3

g = Acceleration of gravity 32ft/sec2

F = Sum of flowing pressure losses

W = Sum of mechanical energy added

In a mud system, as h1 and h2 are at the same height they cancel each other and thevelocity values are negligible, therefore the equation is reduced to:

W = F

‘W’ represents the hydraulic horsepower that must be applied to the mud with ‘F’representing the fluid pressure losses in the system and the nozzles of the bit. Bernoulli’stheorem may be used for the whole circulating system or just part of the system such as thenozzles of the bit.

The total friction losses caused by the surface equipment, drill string and annuli can besummed up as:

Ps = Ps.e + Pd p. + Pd.c + Pb + Pd.c.a + Pd.pa

where:

Ps = Total pressure drop

Ps.e = Pressure drop in the surface equipment

Pd p. = Pressure drop in the drill pipe

Pd.c = Pressure drop in the drill collars

Pb = Pressure drop in the bit

Pd.c.a = Pressure drop in the hole and drill collar annulus

Pd.pa = Pressure drop in the hole and drill pipe annulus

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Each of the pressure drops for a particular section can be obtained by calculation or fromusing industry standard tables if the mud properties of rheology and weight are known. Thepressure drops also depend largely on whether the flow regime is laminar or turbulent. Thisaspect and all of the pressure drops in a system are calculated by the ADIS softwareprogramme

Any alteration in the mud properties or drill string design or bit nozzle area will in turn alterthe hydraulic programme. Suitable assumptions must be made for contingency in order thatthe available pump horsepower is sufficient to cater for most circumstances which mayarise.

Before pressure drops can be calculated, it is necessary to determine whether flow islaminar or turbulent and the plastic viscosity correction factor.

To determine if flow is laminar or not, it is necessary to find out the Reynolds number by:

Reynolds number (Rn) µ

−××=

)DPDH(AVMW47.15

where:

µ = 300Kη-1

κκ =300300σ

η =300600

log322.3σσ

ρ =DPDH

AV41.1

−×

σ600 = 2PV + YP

σ300 = PV + YP

If the Reynolds number is less than 2,000 flow is laminar and over 4,000 is turbulent.

Laminar flow annulus pressure loss is calculated by:

Laminar annular pressure loss (psi) 2)DPDH(90000

PVAVL)DPDH(225

YPL

−

××+

−×

=

Turbulent annular pressure loss (psi) DPDH

AVLMW)104327.1( 27

−×××

=−

where:

L = Length, ft

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The plastic viscosity correction factor is found from the following figure 6.a

Figure 6.A - Plastic Viscosity Correction Chart

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6.4.1. Surface Equipment

The lengths and IDs of the surface lines, manifolds, standpipe, kelly or top drive will cause afriction drop. Each of these parameters need to be known for input into the ADISprogramme.

Pressure drop in pipe bore (psi) 86.1

86.1

ID

QLMW00061.0 ×××=

6.4.2. Drill Pipe

If a parallel or tapered drilling string is used, the length of each section for varying depthsneeds to be determined for each individual size of pipe and then the pressure drops in eachcombined to obtain the total pressure drop of the string.

The calculation is the same as that given in the previous subsection.

6.4.3. Drill Collars

Similar to the drill pipe above, the various lengths of drill collar IDs need to be known, thepressure drop for each length calculated and then added.

6.4.4. Bit Hydraulics

The jetting action across the bit nozzles must be sufficient enough to clean the cuttingsaway from the bit and up into the hole/drill collar annulus. Eni-Agip recommends that theminimum nozzle velocity is 100m/sec.

Further to this, the following is the recommended hydraulic horsepower delivery for rollercone bits in the most common hole sections:

8 ½” = 8-9 HHP/ins2

12 ¼” = 5-6 HHP/ins2

17 ½”(16”) = 3-4 HHP/ins2

The pressure drop across the nozzles are calculated by:

Pressure Drop Across Nozzles TFA10858QMW 2

××

=

where:

TFA = Total flow area, sq ins

Bit HHP can be calculated by:

Bit HHP/in2 DH2.1346

QP

××∆

=

Jet impact force is calculated by:

Jet Impact Force (lbs) JetVQMW000516.0 ×××=

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JetSize

TFA Of1 Jet

TFA Of2 Jet

TFA Of3 Jet

TFA Of4 Jet

TFA Of5 Jet

TFA Of6 Jet

TFA Of7 Jet

TFA Of8 Jet

TFA Of9 Jet

7/32” .038 .076 .114 .152 .190 .228 .266 .305 .342

8/32” .049 .098 .147 .196 .245 .295 .344 .393 .442

9/32” .062 .124 .186 .249 .311 .373 .435 .497 .559

10/32” .077 .153 .230 .307 .383 .460 .537 .614 .690

11/32” .093 .186 .278 .371 .464 .557 .650 .742 .835

12/32” .110 .221 .331 442 .552 .663 .773 .884 .994

13/32” .130 .259 .389 .518 .648 .778 .907 1.037 1.167

14/32” .150 .300 .450 .600 .750 .900 1.050 1.200 1.350

15/32” .172 .344 .516 .688 .860 1.032 1.204 1.376 1.548

16/32” .196 .392 .588 .784 .980 1.176 1.372 1.568 1.764

18/32” .249 .498 .747 .996 1.245 1.494 1.743 1.992 2.241

20/32” .307 .613 .921 1.228 1.535 1.842 2.148 2.455 2.762

22/32” .371 .742 1.113 1.484 1.855 2.226 2.597 2.468 3.339

24/32” .441 .883 1.325 1.767 2.209 2.650 3.092 3.534 3.976

Table 6.B- TFA Comparison (Total Flow Area)

6.4.5. Mud Motors

If mud motors are used, the HHP required will be provided by the supplier and must beadded into the total pressure drop of the system.

6.4.6. Annulus

Pressure loss calculations for the annulus between the hole/drill collar annulus and thehole/drill pipe annulus need to be carried out by inputting the collar ODs, drill pipe ODs andcorresponding lengths as follows:

Turbulent Flow Annulus Pressure Loss (psi) ( )

DPDHVALMW104327.1 27

−××××

=−

.

The equivalent circulating density is calculated:

Equivalent Circulating density DepthVeticalTrue

25.19DropessurePrAnnularTotalMW

×+=

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6.5. USEFUL TABLES AND CHARTS

Mud lbs/gal Weight lbs cu ft g/cc or sp gr BuoyancyCorrection factor

8.34 62.3 1.00 .873 9 67.3 1.08 .862

10 74.8 1.20 .847 11 82.3 1.32 .832 12 89.8 1.44 .817 13 97.2 1.56 .801 14 104.7 1.68 .786 15 112.2 1.80 .771 16 119.7 1.92 .755 17 127.2 2.04 .740 18 134.6 2.16 .725 19 142.1 2.28 .710 20 149.6 2.40 .694 21 157.1 2.52 .679 22 164.6 2.64 .664 23 172.1 2.76 .649 24 179.5 2.88 .633

Table 6.C - Buoyancy Factors

lbs/gal lbs percu ft

SG psi per1,000 ft

lbs/gal lbs percu ft

SG psi per1,000 ft

7.5 56.0 0.90 389.6 14.0 150.0 1.68 727.3 8.0 59.8 0.96 415.6 14.5 108.5 1.75 753.2 8.3 62.4 1.00 431.2 15.0 112.3 1.80 779.2 8.5 63.4 1.02 441.6 15.5 115.9 1.86 805.2 9.0 67.5 1.08 467.5 16.0 120.0 1.92 831.2 9.5 71.1 1.14 493.5 16.5 123.4 1.98 857.1

10.0 75.0 1.20 519.5 17.0 127.5 2.04 883.1 10.5 78.5 1.26 545.5 17.5 130.9 2.10 909.1 11.0 82.5 1.32 571.4 18.0 135.0 2.16 935.1 11.5 86.0 1.38 597.4 18.5 138.3 2.22 961.0 12.0 90.0 1.44 623.4 19.0 142.1 2.28 987.0 12.5 93.6 1.50 649.3 19.5 145.8 2.34 1013.0 13.0 97.5 1.56 675.3 20.0 149.6 2.39 1039.0 13.5 101.0 1.62 701.3

Table 6.D - Conversion Units for Various Mud Weights

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Pipe Tool Joint Equivalent

OD (ins) Nominal Weight Connector ID (ins) ID(ins)

27/8 6.5 IF 21/8 2.225

27/8 10.4 XH 127/8 2.14

27/8 10.4 IF 21/8 2.15

31/2 13.3 FH & XH 27/16 2.74

31/2 13.3 IF 211/16 2.76

31/2 15.5 IF 29/16 2.60

4 14.0 FH 213/16 3.29

4 14.0 IF 31/4 3.34

4 15.7 FH 211/16 3.18

4 15.7 IF 31/2 3.24

41/2 16.6 FH 3 3.76

41/2 16.6 FH 35/32 3.79

41/2 16.6 XH 31/2 3.78

41/2 16.6 IF 33/4 3.82

41/2 20.0 FH & XH 3 3.56

41/2 20.0 IF 35/8 3.64

5 19.5 XH 33/4 4.23

5 25.6 XH 31/2 3.97

51/2 21.9 REG 23/4 4.40

51/2 21.9 FH 313/16 4.6-

51/2 21.9 FH 4 4.75

51/2 21.9 IF 413/16 4.80

51/2 24.7 FH 4 4.60

65/8 25.2 REG 31/2 5.52

65/8 25.2 FH 5 5.88

65/8 25.2 IF 529/32 5.96

For Drill Collar Bores Same as ID

Table 6.E - Drill Pipe Sizes Metric and Imperial

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7. CEMENTING CONSIDERATIONS

The objective of the primary cementing process, to place cement in the annulus betweenthe casing and the formations exposed to the wellbore, is to provide zonal isolation. Toachieve this, a hydraulic seal must be obtained between the cement and the casing andbetween the cement and the formations at the same time preventing fluid channels in thecement sheath.

This requirement makes the primary cementing operation the most important performed onthe well. To this end, it is vital, that engineers are provided with sufficient information andguidelines so that they can plan and conduct successful cementing operations preventingthe need to conduct remedial operations which may be damaging to the well and costly interms of lost rig time.

This section provides information, guidelines and the basic calculations necessary toachieve this.

7.1. CEMENT

7.1.1. API Specification

Portland cement is the most widely used in cementing operations in the oil industry and anAPI specification (10) was established. API 10 consists of eight classes of cement, Athrough H, to provide standard to suit a range of well conditions. The API classificationsystem is shown in table 7.a below:

APIClass

Mixing Water Slurry Weight Well Depth Static BHPTemperature

gal/sk ltrs/sk lbs/gal kg/ltrs ft m oF oC

A 5.2 19.7 15.6 1.87 0-6,000 0-1,830 80-130 27-77

B 5.2 19.7 15.6 1.87 0-6,000 0-1,830 80-130 27-77

C 6.3 23.8 14.8 1.77 0-6,000 0-1,830 80-170 27-77

D 4.3 16.3 16.4 1.97 6,000-12,000 1,8303,660 170-260 77-127

E 4.3 16.3 16.4 1.97 6,000-14,000 1,8304,270 170-290 77-143

F 4.3 16.3 16.4 1.97 10,000-16,000 3,050-4,880 230-320 110-160

G 5.0 18.9 15.8 1.89 0-8,000 0-2,440 80-200 27-93

H 4.3 16.3 16.4 1.97 0-8,000 0-2,440 80-200 27-93

Table 7.A - API Cement Specification

Class A Is intended for use when no special properties are requires.

Class B Has the same properties as class A except has a moderate to high sulphateresistance (MSR and HSR).

Class C Is intended for use when conditions require high early strength.

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Classes D, E and F are referred to as retarded cements developed for higher temperatureand pressures conditions.

Class D Intended for use in moderately high temperatures and pressures and isavailable in both MSR and HSR.

Class E Intended for use in high temperature and pressure conditions and is availablein both MSR and HSR.

Class F Intended for use in extreme high temperature and pressure conditions and isavailable in both MSR and HSR.

Classes G and H were developed in response to the improved technology in slurryacceleration and retardation by chemical means. These are the most widely used cementstoday.

Class G, H Intended for use as a basic well cement to cover a wide range of well depthsand temperatures and is available in both MSR and HSR. Types G and H areessentially identical except that H is significantly coarser than G, evident fromtheir different water requirements.

The following table 7.b shows the various properties of neat slurries and API cement.

API Class Water Slurry Weight Slurry Volume

gal/sk ltrs/sk lbs/gal kg/ ltrs Ft3/sk m3/sk ltrs 3/sk

A & B 5.2 19.7 15.6 1.87 1.18 0.033 0.33

C 6.3 23.9 14.8 1.77 1.32 0.037 0.37

G 5.0 18.8 15.8 1.89 1.15 0.033 0.33

h 4.3 16.3 16.4 1.97 1.06 0.030 0.30

D, E & F 4.3 16.3 16.4 1.97 1.06 0.030 0.30

Table 7.B - Properties of Neat Slurries and API cement.

table 7.d below shows the typical compressive strengths and thickening times of APIcements.

table 7.d Definitions

* Determined by Wagner turbidmeter apparatus ** Based on 250ml volume percentage equivalent 3.5ml is 1.4% + Bearden unit of slurry consistency (Bc) Bc Bearden units of consistency on a preserved consistometer ABc Beaden units of consistency on an atmosphere pressure consistometer

The relationship between Bc and ABc is approximately Bc x 0.69 = ABc Thisrelationship is valid for units of consistency less than 30Bc

*** Thickening time required are based on 75% values of total cement times observedin the casing survey, plus 25% safety factor

++ Maximum thickening time required for Schedule 5 is 120 mins

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Well Cement Class A B C D E F G H Water % by weight of well cement 46 46 56 38 38 38 44 38 Soundness (autoclave expansion),Maximum %

0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80

Fineness *(Specific surface) Minimum m2/kg 150 160 220 - - - - - Free-Water content, Maximum ml - - - - - - 3.5** 3.5**

Compressive Strength Test 8-hours Curing time

Schedule Number

CuringTemp of (oC)

CuringPressurepsi(kPa)

Minimum Compressive Strength, psi (MPa)

- 100 Atmos 250 200 300 - - - 300 300 (38) Atmos (1.7) (1.4) (2.1) - - - (2.1) (2.1) - 140 Atmos - - - - - - 1,500 1,500 (60) Atmos - - - - - - (10.3) (10.3) 6S 230 3,000 - - - 500 - - - - (110) (20,700) - - - (3.5) - - - - 8S 290 3,000 - - - - 500 - - - (143) (20,700) - - - - (3.5) - - - 9S 320 3,000 - - - - - 500 - - (160) (20,700) - - - - - (3.5) - -


Schedule Number

CuringTemp of (oC)



8S 290 3,000 - - - - - - - - (143) (20,700) - - - - - - - -


Schedule Number

CuringTemp of (oC)



- 100 Atmos 1,800 1,500 2,000 - - - - - (38) Atmos (12.4) (10.3) (13.8) - - - - - 4S 170 3,000 - - - 1,000 1,000 - - - (77) (20,700) - - - (6.9) (6.9) - - - 6S 230 3,000 - - - 2,000 - 1,000 - - (110) (20,700) - - - (13.8) - (6.9) - - 8S 290 3,000 - - - - 2,000 - - - (143) (20,700) - - - - (13.8) - - - 9S 320 3,000 - - - - - 1,000 - - (160) (20,700) - - - - - (6.9) - - 10S 350 3,000 - - - - - - - - (177) (20,700) - - - - - - - -

Pressure Temperature Thickening Time Test Specification TestSchedule Number

Maximum Consistency 15 to30 min Straining Period B +

Minimum Thickening Time (min***)

1 30 90 90 90 - - - - - 4 30 90 90 90 90 - - - - 5 30 - - - - - - 90 90 5 30 - - - - - - 120 max ++ 120 max ++

6 30 - - - 100 100 100 - - 8 30 - - - - 154 - - - 9 30 - - - - - 190 - -

Table 7.C - Physical Requirements for API Portland Cements

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Concentration of Additives

The concentrations of most solid cement additives are expressed as percentage by weightof cement (BWOC). This method is also used for water. For example, if 30% silica sand isused in a blend, the amount for each sack of cement is 94lbs x 0.30 = 28.2lbs of silicasand. This results in 94 + 28.2 = 122.2lbs total mix. The true percentage silica sand in themix is 28.2/122.2 = 23.07%.

Salt is an exception and is added by weight of mix water (BWOW). Weighting materials areoften added on a lbs/sk basis for convenience as it eliminates the need to convert frompercentage BWOC to lbs in the bulk plant.

Liquid additive concentrations are most commonly expressed in gal/sk of cement. Forexample, according to table 7.d, liquid sodium silicate has an absolute volume of0.0859gal/lbs. If a concentration of 0.4lbs/sk is prescribed, the weight of the material is0.4/0.0859 = 4.66lbs/sk.

Material Absolute Volume SG

(gal/lbs) (m3/t)

Barite 0.0278 0.231 4.33

Bentonite 0.0454 0.377 2.65

Coal (ground) 0.0925 0.769 1.30

Gilsonite 0.1123 0.935 1.06

Hematite 0.0244 0.202 4.95

Limenite 0.0270 0.225 4.44

Silica Sand 0.0454 0.377 2.65

NaCl saturated 0.0556 0.463 2.15

Fresh Water 0.1202 1.000 1.00

Table 7.D - Absolute Values of Common Cementing Materials

7.1.2. Slurry Density and Weight

The slurry density is calculated by adding the masses of the components and dividing it bythe total of the absolute volumes occupied, i.e. divide the total weight in lbs/volume in gals.

additiveswatercement

additiveswatercementslurry

galgalgal

lblblb)gal/lbs(P

++++

=

The yield of a cement is the volume occupied by a unit plus all the additives and mix water.Cement is measured is sacks therefore the yield is expressed in cubic feet per sack (ft3/sk).This is now used to calculate the number of 94lbs sacks required to achieve the requiredannulus volume.

As there are 31.51 cubic feet per cubic metre, divide the cubic feet by 31.51 to obtain theamount of cement in cubic metres.

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Example calculation:

A slurry is composed of G class cement and 50% water, 94 x 0.50 = 47.0lbs water.

Component Weight (lbs) Absolute Volume(gal/lbs)

Volume (gal)

Cement 94 0.0382 3.59

Water 47.0 0.1202 5.65

Total 141.0 9.24

gal/lbs26.1524.9

0.141)gal/lbs(Pslurry

=

=

The yield is:

sk/ft235.1

sk/gal48.7

sk/gal24.9YieldSlurry

3=

=

The total volume of mix water required is the gals calculated above, 5.65 multiplied by thenumber of sacks of cement to be mixed.

Additives are treated in the same manner as above, however if any have a volume lessthan 1% then they are generally ignored.

An example calculation with additives is as follows:

A slurry is composed of class G cement + 35% silica flour + 1% solid cellulosic loss additive+ 0.2gal/sk liquid PNS dispersant + 44% water.

Component Weight (lbs) Absolute Volume(gal/lbs)

Volume (gal)

Cement 94 0.0382 3.59

Silica flour 32.9 0.0454 1.49

Cellulosic Fluid LossAdditive

0.94 0.0932 0.088

Liquid PNS Dispersant 1.97 0.1014 0.20

Water 41.36 0.1202 4.97

Total 171.17 10.34

gal/lbs55.1634.10


=

=

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The yield is:

sk/ft38.1

sk/gal48.7


3=

=

7.2. CEMENT ADDITIVES

In well cementing, Portland cement systems are designed for temperatures ranges frombelow freezing to 700oF (350oC) in thermal recovery and geothermal wells. They alsoencounter pressures ranging from ambient to 30,000psi (200Mpa) in deep wells.

Accommodation of such variations in conditions was only possible through the developmentof cement additives. They modify the properties of the cement system allowing successfulplacement of the slurry between the casing and the formation, rapid compressive strengthdevelopment and adequate zonal isolation for the life of the well.

It is not possible to detail all of the 100 or more additives in use today but the categorisationof these additives and some of those used by Eni-Agip are described below.

There are eight recognised categories:

• Accelerators• Retarders• Extenders• Weighting Agents• Dispersants• Fluid Loss Control Agents• Loss Circulation Control Agents• Speciality Additives

Details of all of these additives are given in the ‘Drilling Fluids Manual’.

7.2.1. Accelerators

Added to cements to shorten the setting time and/or accelerate the hardening process.They are also required to counter the effect of other additives added to the slurry such asdispersants and fluid loss control agents.

Calcium Chloride is undoubtedly the most efficient and economical accelerator. It isgenerally added in concentrations of 2-4% BWOC (Refer to table 7.e) but over 6% itsperformance becomes unpredictable and premature setting may occur.

CaCl2 %BWOC 91oF 103oF 113oF

0 4:00 3:30 2:32

2 1:17 1:11 1:01

4 1:15 1:02 0:59

Table 7.E – Calcium Chloride Thickening Time on Portland Cement

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CaCl2% 60oF 80oF 100oF

6hr 12hr 24hr 6hr 12hr 24hr 6hr 12hr 24hr

0 Not Set 60 415 45 370 1,260 370 840 1,780

2 125 480 1,510 410 1,020 2,510 1,110 2,370 3,950

4 125 650 1,570 545 1,245 2,890 1,320 2,560 4,450

Table 7.F– Calcium Chloride Compressive Strength Vs Temperature and Time of PortlandCement

NaCl can also be used as an accelerator. Seawater is extensively used offshore as it has a25g/l NaCl but the concentration of magnesium of about 1.5g/l must be taken into account.

7.2.2. Retarders

The retardation process is not completely understood but there are a number of additivesavailable. The chemical nature of the retarder to be used is dependent on the cementphase (silicate or aluminate).

Common retarders are lignosulphonates, hydroxycarboxylic acids, saccharide compounds,cellulose derivatives, organophosphonates and inorganic compounds.

7.2.3. Extenders

Extenders are used for the following uses:

• Reduce slurry density• Increase slurry yield• Water extenders• Low-density aggregates• Gaseous extenders

A list with general information on the most common extenders is given in table 7.g

Extender Range of Slurry DensitiesObtainable (lbs/gal)

Performance Feature and OtherBenefits

Bentonite 11.5-15.0 Assists fluid loss control.

Fly Ash 13.0-14.1 Resists corrosive fluids.

Sodium Silicates 11.1-14.5 Only low percentages required. Idealfor seawater mixing.

Microspheres 8.5- 15.0 Good compressive strength, thermalstability and insulating properties.

Foamed Cement 6.0-15.0 Excellent strength and lowpermeability.

Table 7.G- Summary of Extenders

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The most frequently used clay-based extender is bentonite which contains 85% of the claymineral smectite (or montmorillonite). It is added in concentrations of up to 20% BWOC.Concentrations above 6% requires the addition of a dispersant to reduce the slurry viscosityand gel strength. API recommends that 5.3% water BWOW be added for each 1% bentonitebut testing with a particular cement is necessary to determine the optimum water content.table 7.h shows the slurry density decreases and the yield increases quickly with bentoniteconcentration, however compressive strength correspondingly decreases.

BentoniteConcentration %

Class G - 44% Water

Water (gal/sk) Slurry Density(lbs/gal)

Yield (ft3/sk)

0 4.97 15.8 1.14 2 6.17 15.0 1.31 4 7.36 14.4 1.48 6 8.56 13.9 1.65 8 9.76 13.5 1.82

10 10.95 13.1 1.99 12 12.15 12.7 2.16 16 14.55 12.3 2.51 20 16.94 11.9 2.85

Table 7.H- Bentonite Effects on Slurry Properties

High concentrations of bentonite tend to improve fluid loss and is also effective at elevatedtemperatures.

7.2.4. Weighting Agents

When high pore pressures, unstable well bores, and deformable/plastic formations areencountered, high weight muds of over 18ppg may be used are correspondingly cementslurries of equal weight must be used.

One method of achieving high weight slurries is to simply reduce the amount of mix water,however dispersants would be required to maintain pumpability. When weights higher thanthis are required, materials with high SGs are added. The most common weighting agentsand there properties are shown in table 7.i.

Material Specific Gravity AbsoluteVolume (gal/lbs)

Colour Additional Water(gal/lbs)

Limenite 4.45 0.027 Black 0.00 Hematite 4.95 0.024 Red 0.0023

Barite 4.33 0.028 White 0.024

Table 7.I- Common Weighting Material Properties

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7.3. SALT CEMENT

Salt cements have applications where freshwater cement will not bond properly. This isusually in wells which have salt formations where water will dissolve the formation or leachaway the salt at the interface producing no bond at all. A good bond can be achieved if saltslurries are used.

Salt slurries found another use to protect shale formations which are sensitive to freshwater and tend to slough when in contact. This problem causes:

• Excessive washouts and channelling behind the pipe.• Lost circulation into the weakened shale structure.• Annular bridging which may prevent slurry circulation.

The cement used in salt slurries is usually NaCl but there is no reason that KCl cannot beused. Previously, the benefits of using salt cements was known but was unpopular due tothe inconvenience of premixing salt with water prior to adding cement. Today the techniqueof blending dry granulated salt with cement at the bulk plant greatly simplifies its use.

The mix water requires a minimum 3.1lbs of dry salt for every gallon of water (0.3714kg/l) or37.2 BWOW. If the concentration is less then the slurry will not be saturated and may causethe problems previously outlined. If more salt is added then there is no detrimental effectsexcept changes in density and pumping ability.

table 7.j shows the BWOW for various concentrations of salt in water including saturated:

Concentration %BWOW Absolute Volume(gal/lbs) (m3/t)

2 0.0771 0.3104 0.0378 0.3166 0.0384 0.3218 0.0390 0.326

10 0.0394 0.32912 0.0399 0.33314 0.0403 0.33616 0.0407 0.34018 0.0412 0.34420 0.0416 0.34722 0.0420 0.35124 0.0424 0.35426 0.0428 0.35728 0.0430 0.35930 0.0433 0.36132 0.0436 0.36334 0.0439 0.366

37.2 saturated 0.0442 0.369

Table 7.J - BWOW for Various Concentrations of Salt in Water

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An example calculation of a salt slurry using the previous fresh water slurry is as follows:

94lbs cement x 50% = 47lbs

47lbs of water x .372 = 17.48lbs NaCl

Component Weight(lbs)

Absolute Volume(gal/lbs)

Volume(gal)

Cement 94 0.0382 3.59

NaCl 17.48 0.0442 0.77

Water 47.00 0.1202 5.65

Total 158.48 10.01

gal/lbs26.1501.10


=

=

The yield is:

sk/ft338.1

sk/gal48.7


3=

=

7.4. SPACERS AND WASHES

When the fluids are incompatible, to ensure all the mud is displaced, it is common practiceto pump one or more intermediate fluid or preflushes which are compatible with both themud and the slurry. This will buffer the two fluids and prepares the casing and formationwalls leaving them receptive to bonding. To accomplish all of the above, the rheological andchemical properties must be carefully designed.

The rheology and density of washes are close to that of water or oil. They act be thinningand dispersing the mud and, because of their very low viscosity, they are ideal for use inturbulent flow. The simplest form of wash is fresh water although surfactants anddispersents are often added.

Spacers are also used which are preflushes with a much higher solids content. the particlesare thought to scrub the walls and provide a better preparation. the most common spacer isa scavenger slurry which is a cement slurry with a low density and low fluid loss rate goodfor turbulent flow. The best spacer is a spacer that has a density higher than the mud butless than the cement slurry. This is achieved by adding weighting agents (usually insolubleminerals with high density) with a viscofier for efficient suspension.

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There are two classes of viscofiers:

a) Water soluble polymers

• Polycrylamides• Guar and guar derivatives• Cellulose derivatives, CMC, HEC, HMC, HPC• Xantham gum and other biopolymers

b) Inorganic clays

• Bentonite, attapulgite, kaolinite, sepiolite

Eni-Agip recommends that, unless an effective mud density is required to control theformation pressure, a water spacer be used on all cement jobs which shall have sufficientvolume to provide a contact time of three mins.

7.5. SLURRY SELECTION

The selection of a slurry design depends on many factors other than simply pore andfracture pressures.

• Cements are sometimes mixed at high density to achieve specific strengthswithin a short time interval or it may be designed on an economic basis wherehigh yield per sack is achieved at the expense of strength.

• Temperature as previously explained has a large impact on the class of cementthat can be used.

• Fluid loss additives are necessary where the cement is in contact withproduction zones or in small annular gaps to prevent the loss of the aqueousphase. As fluid loss additives are viscofiers they require dispersants to be addedto preserve mixability.

• Dispersants are used for the previous reason but also to reduce viscosity andreduce pump pressures and improve placement efficiency. caution should betaken when using dispersants as they can change thickening time.

• Additives such as accelerators and retarders are required to hasten or slowdown the setting times.

In the main, the compressive strength of the cement is secondary to the properties of theliquid slurry as cement systems generally provide strengths which exceed those actuallyrequired in most cases.

The ADIS programme should help the engineer to obtain the ideal slurry for a specific wellapplication.

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7.6. CEMENT PLACEMENT

Good mud removal is the essence of obtaining a successful primary cement job andtherefore the use of an effective preflush and/or spacer is pumped between the mud andthe slurry.

Freshwater spacers are normally used when water based mud is in the hole and salttolerant spacers for salt saturated muds. Oil based mud is generally removed with spacersdosed with surfactants and/or organic solvents.

In every case laboratory testing should be carried out beforehand to ensure that nounforeseen interactions can occur, hence affecting the performance of the spacer.

7.7. WELL CONTROL

Every well has a band of pressures in which the engineer must remain to execute asuccessful cementing operation. The limiting pressure boundaries are determined byformation pore and fracture pressures and casing strength limits. Unless a softwarepackage is used, the engineer would find it impractical to calculate the pressures at point inthe well throughout the entire job, therefore, if it is necessary to conduct manualcalculations, the usual approach is to select the worst case scenario analysis techniquewhere the key points will be identified and examined.

These are normally at the weakest formations which will experience their highest pressureat the end of the displacement just before the plug bumps and conversely the at highpressure zones at the time the low density preflush or spacer passes.

A good rule of thumb under such circumstances, is to select the shallowest active zonewhich poses a risk to security and concentrate on the worst cases at this point usinghydrostatic pressure without the friction component.

An important impact on well control is the amount of excess cement calculated which cancause higher than expected hydrostatic pressure is the hole is close to gauge causinglosses therefore compromising the success of the job and well security.

Similarly, if using low density flushes or spacers, better than expected hole gauge will raisethe column of the fluid to higher than expected height therefore exerting reducedhydrostatic pressure.

If pressure band over long sections to be cemented is narrow, it may be necessary to varythe density of the cement slurry and pump two slurries, a lead and tail with differentdensities. See example figure 7.a

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Figure 7.A- Downhole Pressure Density Plot

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7.8. JOB DESIGN

The selection of a slurry for a job design is dependent upon conducting a problem analysisinto:

• Depth/configuration data• Wellbore environment• Temperature data

These data will directly affect the basic cement properties and displacement regime. Theannular configuration will determine which flow regime is practical and required rheologicalproperties. Wellbore conditions will indicate whether special materials are required due tothe presence of gas, salt, etc., need to be incorporated. The mud density indicates theminimum acceptable cement slurry density. These factors, together with the temperaturedata, guide the selection of the additives for the control of the slurry flow properties andthickening time.

7.8.1. Depth/Configuration

The hole depth and configuration will make a considerable impact on the temperature andfluid volume, hydrostatic pressure and friction pressure. this could even lead to the designof a special system.

In open hole sections the volume of slurry depends upon the shape of the hole which israrely ‘gauge’ and some formations are liable to become eroded or washed out. For openhole sections the volume should have an increment added to cater for such problems. Ifthere is a reason to have doubts over the size of the hole, a caliper survey should be run toestimate the hole size. It should be noted that the amount of pads on the caliper will affectthe accuracy of the calculation if the hole is not round.

The increments to be applied in absence of a caliper survey are:

• Surface Casing - 100%• Intermediate Casing - 50%• Production Casing - 30%

If a log is available the increment will be the hole volume calculation plus 10%.

The trapped volume between the cement collar and cement shoe must be added to totalvolume.

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7.8.2. Environment

Pore pressure in the formations are important from a security standpoint and, in conjunctionwith leak-off test results, to prevent formation damage through fracturing or leak-off ofcement into producing zones. The engineer must not look solely at target zones but also therisk from other non-producing zones. The presence of gas, salt and other formations willalso affect the job design.

Mud physical and chemical properties must also be considered, with regard to compatibilitywith chemical washes, spacers or other fluids. The displacement of oil based mud fromformations may invariable require the use of surfactants to improve compatibility, remove oilfilm from the formations and leave the surfaces water wet.

If 100% mud removal is not possible, the slurry properties can be altered to ensure it is notadversely affected by the mud. Data on compatibility can be obtained by laboratory testing.

7.8.3. Temperature

Circulating bottom hole and static temperatures need to be considered as well as thetemperature differential between the bottom and top of the cement column. The circulatingtemperature is the temperature it will be exposed to as it is placed in the well and for whichthe thickening time tests for high-temperature and high-pressure is carried out.

Circulating temperatures by calculation in accordance with temperature schedulespublished in API 10 Specification. However, actual temperature is often preferred and thesecan be obtained by running a temperature measurement device.

One rule of thumb which should apply to the slurry design, is to ensure that the statictemperature at the top of the cement exceeds the circulating bottom hole temperature. Ifthis is not the case then stage cementing should be employed. This rule of thumb alsoprovides a means of determining the depth for the location of the cementing stage collar.

7.8.4. Slurry Preparation

Mixing is one of the most important practical cementing problems. The goal of the mixingprocess is to obtain the correct proportioning of solids and carrier fluid with the propertiessimilar to those of the expected from pre-job lab testing. If this is not achieved, the carefulpre-planning calculations to determine the displacement rate, friction pressure, etc., will beerroneous and thickening time and fluid loss parameters may change dramatically.

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8. WELLHEADS

This section provides design criteria for wellheads which have been standardised by Eni-Agip Division and Affiliates.

With regard to modular type surface wellheads, the most commonly used wellhead in Eni-Agip’s activities is the National/Breda wellhead system which is covered later in this section.However, there is no commonality in the selection of compact surface wellheads or subseawellheads.

Each project must be assessed to ascertain the most economic type of wellhead to be usedfor the location or type of completion..

8.1. DEFINITIONS

The following are a list of definitions and their abbreviations specific to wellhead equipment.

MSCL Modular Single Completion Land

DCSFSL Dual Completion Seal Flange solid-block Land

SCSO Single Completion Seal Flange Offshore

DCSO Dual Completion Solid-block Offshore

8.2. DESIGN CRITERIA

Eni-Agip divide wellhead equipment into two classifications:

Class A Equipment designed to operate up to 5,000psi WP

Class B Equipment designed to operate up to 10,000psi WP

The selection of the wellhead system pressure rating will be based upon the maxanticipated surface pressure.

8.2.1. Material Specification

The material selection will meet with either ‘General Service’ or ‘Sour Service’ conditions.

General service conditions are defined as:

Operating Temperature Range: -29oC to 82oC as per API 6A

The steels which meet with this criteria are material standard (no sour service), class Dd asper API 6A as defined by NACE MR-01-75

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Sour service conditions are when the CO2 or H2S concentrations exceed 7psi and 0.05psirespectively. In this case the material will be selected in accordance whether an inhibitionprogramme is implemented which may decide if chrome or carbon steel is applicable.However if the event of any H2S being present above the limit, a steel with a hardness lessthan 22Rc will be selected to comply with NACE MR-0175 specification. Refer to section4.13 on corrosion.

In offshore environments, the wellhead and Xmas tree equipment should be protectedagainst the corrosive effects of salt spray by application of an appropriate coating.

Modern compact wellheads, described below, may offer enhanced safety due to theincreased fire resistance by the use of all metal-to-metal seals.

8.3. SURFACE WELLHEADS

Compact wellheads have many advantages over composite types in that they are shorter,have less connections, less outlets and are therefore have fewer potential leak paths. Thecompact wellhead was developed from subsea systems which require the stacking of anumber of casing mandrel hangers in a single body.

The advantages of the traditional composite type wellhead with its modular construction are:its ability to be altered during drilling operations (due to enforced changes in the casingprogramme), and low cost.

The compact wellhead, also sometimes referred to as speed, fast or unitised head, comesin various configurations but usually consists of a body that is mounted onto the surfacecasing and into which each subsequent casing hanger is run and landed. The sealing ofthese hangers is via a seal assembly run above each hanger with metal-to-metal seals. Themain advantages of the compact head is the reduced height, saving of rig time due to beingable to run the hangers without removing the BOPs and enhanced safety for the samereason.

8.3.1. Standard Wellhead Components

Refer to ‘Specification for Surface Wellhead and Xmas Tree Standard Equipment Manual’.

table 8.a shows the standard equipment for the various classifications and well options.From this table, the sizes and pressure rating of equipment available for the variousapplications can be determined.

8.3.2. National/Breda Wellhead Systems

National/Breda wellhead systems are, up to now, the most commonly used systems by Eni-Agip Division and Affiliate companies. It is of traditional modular construction and coverspressure ranges between 3,000 and 15,000 psi for both standard and non-standard casingprofiles.

table 8.a shows the standard range of National/Breda wellhead configurations and anexample wellhead. Other wellhead and equipment details can be obtained from themanufacturer’s catalogue.

AR

PO

ENI S

.p.A.

Ag

ip D

ivisio

n

IDE

NT

IFIC

AT

ION

CO

DE

PA

GE 114 O

F 230

RE

VIS

ION

ST

AP

-P-1-M

-61000

Tab

le 8.A- E

ni-A

gip

Stan

dard

Wellh

ead E

qu

ipm

ent C

hart

AGIPCODE

Ref.nr Topflange

(in)

Max. W.P.(psi)

Btm (CSG)(in)

Ref. nr BtmFlange

(in)

Max. W.P.(psi)

Topflange

(in)

Max. W.P.(psi)

Ref. nr

Btmflange

(in)

Max. W.P.(psi)

Topflange

(in)

Max. W.P.(psi)

Ref. nr

BtmFlange

(in)

Max. W.P.(psi)

Topflange

(in)

Max. W.P.(psi)

Ref. nr

Diam(in)

Max.W.P. (psi)

Diamtbg(in)

MSCL 1 1.3 13 5/8 5000 13 3/8 & 9 5/8 2.1 13 5/8 5000 13 5/8 5000 5.1 13 5/8 5000 9 5000 6.1 9 5000 2 7/8

MSCL 2 1.3 13 5/8 5000 13 3/8 & 9 5/8 2.1 13 5/8 5000 13 5/8 5000 5.1 13 5/8 5000 9 5000 6.2 9 5000 3 1/2

MSCL 3 1.3 13 5/8 5000 13 3/8 & 9 5/8 2.1 13 5/8 5000 13 5/8 5000 5.1 13 5/8 5000 9 5000 6.3 9 5000 5

DCSFSL 1 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.1 13 5/8 5000 13 5/8 5000 5.1 13 5/8 5000 9 5000 6.6 9 5000 2 x 2 3/8

DCSFSL 2 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.2 13 5/8 5000 13 5/8 10000 5.2 13 5/8 10000 9 10000 6.8 9 10000 2 x 2 3/8

DCSFSL 3 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.1 13 5/8 5000 13 5/8 5000 5.3 13 5/8 5000 11 5000 6.5 11 5000 2 x 3 1/2

SCSO 1 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.1 13 5/8 5000 13 5/8 5000 5.4 13 5/8 5000 7 1/16 5000 6.4 7 1/16 5000 3 1/2

DCSO 1 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.1 13 5/8 5000 13 5/8 5000 5.4 13 5/8 5000 7 1/16 5000 6.9 7 1/16 5000 2 x 2 3/8

DCSO 2 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.2 13 5/8 5000 13 5/8 10000 5.5 13 5/8 10000 7 1/16 10000 6.7 7 1/16 10000 2 x 2 3/8

DCSO3 1.2 21 1/4 5000 20 & 18 5/8 2.4 21 1/4 5000 13 5/8 5000 2.2 13 5/8 5000 13 5/8 10000 5.2 13 5/8 10000 9 10000 6.8 9 10000 2 x 2 3/8

(*) 1.2 21 1/4 5000 20 & 18 5/8 2.5 21 1/4 5000 13 5/8 10000 2.3 13 5/8 10000 13 5/8 10000

1.1 26 3/4 3000 24 1/2 2.6 26 3/4 3000 21 1/4 5000 2.5 21 1/4 5000 13 5/8 10000 2.3 13 5/8 10000 13 5/8 10000

3° CASING HEAD SPOOL

(*) Typical wellhead configuration for deep wells (po Valley)

Typical outlines for on-shore, off-shore single and dual completion class -A and class -B(STAP -M-1-SS-5701E)

CASING HEAD CASING HEAD SPOOL CASING HEAD SPOOL TUBING SPOOL TUBING HANGER

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WP (psi) 3K (A) 3K (B) 5K (C) 5K (D) 10K (E) 10K (F) 15K (G) 15K (H) Section 1 470 470 470 470 470 510 510 - Section 2 620 620 625 690 690 850 850 510 Section 3 472 472 472 670 660 700 700 850 Section 4 - - - 581 700 700 750 700 Section 5 - - - - - -- 750

Figure 8.A - Wellhead Dimensions (mm)

20"

13 3/8"

9 5/8"

7"

4

3

2

1

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8.4. COMPACT WELLHEAD

Modern offshore drilling has uncovered a need for specially designed wellheads requiringless space with shorter installation times, thus offering a greater degree of safety. Thesolution to this need was met by the introduction of the unitised or compact wellhead whichincorporates a casing flange, casing spools and possibly a tubing spool in a single offshorecomposite wellhead body.

Eni-Agip Division and Affiliates generally use the compact wellhead system in developmentdrilling operations.

The concept is quite different from that already described in section 8.3 and similar tosubsea wellhead systems from which the compact head was developed.

Each manufacturer has its own particular product which differs from other manufacturers.Considering the number of different varieties available, it is not possible to provide a uniqueassembling procedure for all the existing unitised or compact wellhead types in this manual.

figure 8.b and figure 8.c show two typical examples of compact wellhead systems. Forspecific running procedures reference should always be made to the well specific DrillingProgramme and manufacturer's instructions.

Technical advantages of the compact wellhead are:

• Elimination of the rig time lost in nippling-up or down the BOPs, which isnormally associated with conventional wellhead spools.

• Once the pack-off is set, the BOP can be tested.• No crossover adapters are required.• The stack-up height is greatly reduced by the elimination of the casing and

tubing spools.• The Well is under BOP control from the time the 13 3/8” BOP stack is installed on

the Compact Wellhead to the time the Xmas tree is installed.

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Figure 8.B - Wellhead ‘Unitised 3,000psi WP

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Figure 8.C - Wellhead SMS 135/8 10,000psi WP Assembly

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8.5. MUDLINE SUSPENSION

The Mudline Suspension system is a method for supporting the weight of casing at theseabed (mudline) while drilling from a jack-up (Refer to figure 8.d and figure 8.e)

It offers a method of disconnection for all casing strings, allowing the temporaryabandonment of the well in the minimum of time and without having to cut the casings.

The casing strings extend from the mudline back to the drilling unit. Conventional land typewellhead and BOPs are installed for well control during drilling operations.

The system utilises simple fluted landing rings or expanding collets in which the hangers arelanded. Each casing string is supported at the mudline by a mudline casing hanger. Therunning tools or the tieback tools connect the mudline casing hangers with the casing stringabove (landing string).

Running tools used in the mudline system, include a square bottom thread, to install it intothe hangers and seal, to maintain the pressure integrity of the running tool mudline hangers.The connection of the running tools is the casing thread as per the user’s requirement.

Washout ports, located in the mudline hanger or in the running tool, ensure thoroughflushing of the annulus. The washout ports are exposed by a partial rotation of the runningtool. When the washout ports are closed the pressure integrity of the casing is provided bythe seals of the running tool.

When temporarily abandoning a well, the casing landing string is retrieved by disconnectingthe running tools. Corrosion caps used in temporary well abandonment may be installed atthis time.

Any, or all, of the casing strings can be re-installed back to a conventional land typeproduction tree, installed on a production platform wellhead deck, by means of tie-backtools.

Metal to metal seals between the tieback tool a 133/8” or smaller mudline casing hangersprovide a permanent pressure seal for the producing life of the well.

Eni-Agip have used a ‘mudline completion system’ enabling a well to be drilled using aJack-up drilling equipment and afterwards completing it with a subsea production system.

Each mudline suspension manufacturer produces its own product different from those ofcompetitors. Considering the great number of different features, it is not possible todescribe all the existing mudline suspension system in this manual. For the installationprocedure, refer to the well specific ‘Drilling Programme’ and the manufacturer’s ‘operatingprocedures’.

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Figure 8.D - MLL Mudline Casing Suspension System

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Figure 8.E - The MLC Mudline Suspension System

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9. PRESSURE RATING OF BOP EQUIPMENT

The prime considerations, when selecting and procuring pressure control equipment, arethe safety of the personnel, rig and the wellbore. In order to assure this safety requirement,several factor need to be considered.

It should be noted that each drilling area may have regulations unique to that particular areawhich may exceed the general requirements covered within this manual. In addition,different operating companies and contractors may vary from these general requirements ifdictated by individual company policy and philosophy.

The anticipated formation pressure is the governing parameter which dictates the casingdepth, casing selection, BOP selection and pressure rating of the BOP equipment.

The weakest element within any pressure control system determines the maximum pressurethat can be safely contained.

Individual elements of the pressure control system may exceed the assembly WP, butunder no circumstances should components be used which are less than thedesignated assembly WP. For instance, a 10,000psi choke may be rigged up with a2,000psi BOP stack in anticipation of its later use when a 10,000psi BOP stack is nippledup for a subsequent string of casing.

The equipment in the well control system with the lowest pressure rating will set the ratingfor entire system e.g. 2,000psi stack and 10,000psi choke manifold would be rated to only2,000psi.

Since the well control system must be able to contain any anticipated formation pressuresthat may be encountered, the maximum anticipated surface pressures must first becalculated.

Many different methods are available to determine the maximum casing pressures whichmay be encountered during a kick.

9.1. BOP SELECTION CRITERIA

Blow-out preventer equipment shall consist of an annular preventer and the specifiednumber of ram type preventers.

The working pressure of any blow-out preventer shall exceed the maximum anticipatedsurface pressure to which it may be subjected, except that the WP of the annular preventer.

The graph illustrated in the attached figure 9.a has been prepared to enable the firstapproximation of the BOP rating necessary for use in drilling an exploration well. To use thegraph, the setting depths of the various casings and the relative pore pressure gradientsmust be found or determined during the design phase.

The co-ordinates in the graph are ‘depth’ and ‘pressure’ and comprises of two groups oflines respectively, are representing the BOP’s to be used while drilling, and the other theBOPs to be used during well testing.

Each group outlines the different solutions available to the various pore pressure gradients.

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Example:

The casing program assumes that a well test will be carried out at the shoe of 7” casing.From the diagram shown in table 9.a the maximum test, drilling pressure values and thesize of BOP to be used should be obtained which is given in table 9.a.

Casing(ins)

ShoeDepth

(m)

OverburdenGradient

(kg/cm2/10m)

Pore Press.Gradient

(kg/cm2/10m)

FractureGradient

(kg/cm2/10m)

BOPDrilling

(psi)

SizeProductionTest (psi)

20 750 2.23 1.03 1.83 2,000 -

13 3/8 2.620 2.36 1.30 2.01 5,000 -

9 5/8 4.200 2.42 1.70 2.18 10,000 -

7 4.830 2.43 2.00 2.29 - 15,000

Table 9.A - BOP Selection Example Data

The maximum theoretical stress possible at the casing head (Pmax) occurs when the well isfull of gas and the fracture pressure has been reached at the shoe of the last casing run.

This pressure is:

)(Kg/cm Dg)-GF(10H

Pmax 2=

where:

H = Casing shoe depth (m)

Gf = Fracture gradient of the casing shoe (kg/cm2/10m)

Dg = Gas density, assumed = 0.3 (kg/dm3)

In the case of a well test, this pressure roughly corresponds to the limit value required forpumping gas into the formation and is thus actually attainable in practice.

This hypothesis however is completely unrealistic in the drilling design, for which 60% of thepressure Pmax will be used as limit value according to company policy in burst designcriteria of the ‘Casing Design Manual’.

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Figure 9.A - BOP Selection Example

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10. BHA DESIGN AND STABILISATION

10.1. STRAIGHT HOLE DRILLING

Drilling a perfectly straight hole is certainly an impossibility. A well designed bottom holeassembly only controls veering off-line to be maintained within acceptable pre-plannedlimits.

The exact cause of holes becoming crooked is not well known but some logical theorieshave been presented based on appearance. It has been confirmed that the drilling bit willattempt to up dip in laminar formations with dips up to 40o.

Another factor for consideration is the bending characteristics of the drill stem. With noweight on the bit, the only force acting on the bit is the result of the weight of the stringportion between the bit and the tangency point. This force tends to bring the hole backtowards the vertical. When weight is applied, there is another force on the bit which tends todirect the hole away from vertical. The results of these two forces may be in such a directionas to increase angle, decrease angle, or to maintain a constant angle. This theory is basedon the assumption that the drill string will lie on the low side of an inclined hole.

In general, drilling in soft formations makes the problem of drilling a straight or nearlyvertical hole much easier than in very hard formations. In particular the effects of the drillstring bending and encountering dips may be much less when drilling soft formations whilein hard formations which have high dip angles require high bit weight which are the factorsagainst drilling a straight or vertical hole.

10.2. DOG-LEG AND KEY SEAT PROBLEMS

10.2.1. Drill Pipe Fatigue

If a programme is designed in such a way that drill pipe damage is avoided while drilling thehole, then the hole will be acceptable for conventional casing, designs, tubing andproduction string as far as dog-leg severity is concerned. A classical example of the severedog-leg condition which produces fatigue failures in drill pipe can be seen in figure 10.a.The stress at point B is greater than the stress at point A; but as the pipe is rotated, point Amoves from the inside of the bend to the outside and back to the inside again, so that everyfibre of the pipe under goes both minimum tension and maximum tension every rotation.Cyclic stress reversals of this nature cause fatigue failures in drill pipe, usually within thefirst two feet (0.6m) of the body adjacent to the tool joint due to the abrupt change ofsection.

To avoid rapid fatigue failure of pipe, the rate of change of the hole angle must becontrolled. Suggested limits are given in figure 10.b. This graph is a plot of the tension inthe pipe versus change in hole angle in degrees per 100ft. This curve is designed for a 41/2"16.60lbs/ft Grade ‘E’ drill pipe and represents the stress endurance limits of the drill pipeunder various tensile loads and in various rates of change in hole angle. If conditions fall tothe left of this curve, fatigue damage is avoided, but to the right, fatigue damage will buildup rapidly and failure of the pipe is likely.

It can be seen from this plot that with a dog-leg high WP in the hole with high tension in thepipe, only a small change in angle can be tolerated. Conversely, if the dog-leg is close tototal depth, tension in the pipe will be low and a larger change in angle can be tolerated.

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Note: Refer to figure 10.c for the maximum safe dog-leg limits when using Grade‘E’ drill pipe. If the stress endurance limit of the drill pipe is exceeded, anexpensive fishing job or a junked hole could occur.

10.2.2. Stuck Pipe

Sticking can occur by sloughing, heaving of the hole or also by extra large OD drill collarscontacting a key seat while tripping the drill string out of the hole.

10.2.3. Logging

Logging tools and wire line can become stuck in key seats. The wall of the hole can also bedamaged, causing future hole problems.

10.2.4. Running casing

Running casing through a dog-leg can cause serious problems. If the casing becomes stuckin the dog-leg, it will not extend through the productive zone. This would make it necessaryto drill out the shoe and set a smaller size casing through the productive interval. Even ifrunning the casing to bottom through the dog-leg is successful, the casing could beseverely damaged, thereby preventing the running of production equipment inside thecasing.

10.2.5. Cementing

Dog-legs will force casing tightly against the wall of the hole, preventing a good cementbond as no cement can circulate between the wall of the hole and the casing at this point.

10.2.6. Casing Wear While Drilling

The lateral force of the drill pipe rotating against the casing in the dog-leg or draggingthrough it while tripping, can cause substantial wear to the casing. This could cause drillingproblems and/or a possible serious blow-out.

10.2.7. Production Problems

In rod pump completions rod wear and tubing leaks associated with dog-legs can causeexpensive remedial costs. It may be difficult to run packers and tools in and out of the wellwithout getting stuck because of distorted or collapsed casing.

It is obviously preferred to produce through straight tubing to avoid friction losses andprevent turbulence.

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Figure 10.A - Dog Leg and Key Seating

Figure 10.B - Endurance Limit For 16.60# Grade E Drill Pipe

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Figure 10.C -Maximum Safe Dog leg Limits

10.3. HOLE ANGLE CONTROL

In order to reduce the possible causes of bit deviation and the problems associated withcrooked holes, There are two possible solutions, one using the pendulum and the other thepacked BHA concepts.

10.3.1. Packed Hole Theory

A packed hole assembly is used to overcome crooked hole problems and the pendulum isused only as a corrective measure to reduce angle when the maximum permissibledeviation has been reached. The packed hole assembly is sometimes referred to as the‘gun barrel’ approach because a series of stabilisers is used in the hole already drilled toguide the bit straight ahead.

The object is to select a bottom hole assembly to be run above the bit with the necessarystiffness and wall contact tools to force the bit to drill in the general direction of the holealready drilled. If the proper selection of drill collars and bottom hole tools is made, onlygradual changes in hole angle can develop. This should create a useful hole with a full-gauge, smooth bore free from dog-leg, key seats, offsets, spirals and ledges, therebymaking it possible to complete the well.

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10.3.2. Pendulum Theory

The forces which act upon the bit can be resolved into:

1) The axial load supplied by the weight of the drill collars.

2) The lateral force, the weight of the drill collar between the bit and the first point ofcontact with the wall of the hole by the drill collar i.e. Pendulum force. This force is thetendency of the unsupported length of drill collar to swing over against the low side ofthe hole due to gravity. It is the only force that tends to bring the hole back towardsvertical.

3) The reaction of the formation to these loads may be resolved into two forces, oneparallel to the axis of the hole and one perpendicular to the axis of the hole.

10.4. DESIGNING A PACKED HOLE ASSEMBLY

The following factors need to be considered when designing a packed hole assembly.

10.4.1. Length Of Tool Assembly

It is important that wall contact assemblies provide sufficient length of contact to assurealignment with the hole already drilled. Experience confirms that a single stabiliser justabove the bit generally acts as fulcrum or pivot point and will build angle because the lateralforce of the unstabilised collars above will cause the bit to push to one side as weight isapplied. Another stabilising point, for example, at 30ft (10m) above the bit will nullify someof the fulcrum effect. With these two points, this assembly will stabilise the bit and removesome of the hole angle-building tendency, but it would still not be considered a goodpacked hole assembly.

As shown in figure 10.d, two points will contact and follow a curved line, but the addition ofone more point makes it impossible to follow a curve. Therefore, three or more stabilisingpoints are needed to form a packed hole assembly.

10.4.2. Stiffness

Stiffness is probably the most misunderstood of all the issues to be considered about drillcollars. Realisation of diameter and its proportion to stiffness is an important factor. If a bardiameter is doubled its stiffness is increased 16 fold.

table 10.a shows moments of inertia (I), which is proportional to stiffness which is given forthe most popular drill collars in various diameters.

Large diameter drill collars are the ultimate in stiffness, so it is important to select themaximum diameter collars that can be safely run.

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Three or more stabilising points make a packed bottom hole assembly.

Figure 10.D - Packed Hole Assembly Stabilising Points

OD (ins) ID (ins) I (ins4)

5" 2 /4" 29

6 1/4" 21/4" 74

6 1/2" 21/4" 86

6 3/4" 21/4" 100

7" 213/16" 115

8" 213/16" 198

9" 213/16" 318

10" 3" 486

11" 3" 713

Table 10.A - Drill Collar Stiffness

1

2

1

2

1

2

3

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10.4.3. Clearance

The closer the stabiliser is to the bit, the more exacting the clearance requirements are. If,for example, a 1/16" undergauge from hole diameter is satisfactory just above the bit, then60ft above the bit, 1/8" clearance can be critical factor for a packed hole assembly.

10.4.4. Wall Support and Length of Contact Tool

Bottom assembly must adequately contact the wall of the hole to stabilise the bit andcentralise the drill collars. The length of contact needed between the tool and the wall of thehole will be determined by the formation. The surface area in contact must be sufficient toprevent the stabilising tool from digging into the wall of the hole. If this should happen,stabilisation would be lost and the hole would drift. If the formation is strong, hard anduniform, a short narrow contact surface is adequate and will insure proper stabilisation.

On the other hand, if the formation is soft and unconsolidated, a long blade stabiliser maybe required. Hole enlargement in formations that erode quickly tends to reduce affectivealignment of the bottom hole assembly.

This problem can be reduced by controlling the annular velocity and mud properties.

10.5. PACKED BOTTOM HOLE ASSEMBLIES

Proper design of a packed bottom hole assembly requires a knowledge of crooked holetendencies and the degree of drillability of the formations to be drilled in each particulararea.

For basic design practices the following are considered pertinent parameters and aredefined:

Crooked Hole Drilling Tendencies

• Mild crooked hole• Medium crooked hole• Severe crooked hole.

Formation Firmness

• Hard to medium hard formations• Abrasive• Non abrasive• Medium hard to soft formations.

figure 10.e shows three basic assemblies required to provide the necessary stiffness andstabilisation for a packed hole assembly. A short drill collar is used between Zone 1 andZone 2 to reduce the amount of deflection that might be caused by the drill collar weight. Asa general rule of thumb, the short drill collar length in feet is approximately equal to the holesize in inches, plus or minus two feet. For example a short drill collar length of 6 to 10ft (2-3m) would be satisfactory in an 8 “ hole.

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* The short drill collar length is determined by the hole size

Hole size (inches) = Short DC (ft) +/- 2ft

Figure 10.E - Basic Packed BHAs

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10.6. PENDULUM BOTTOM HOLE ASSEMBLIES

Because all packed assemblies will bend to some extent, however small the amount ofdeflection drilling, a perfectly vertical hole is not possible. The rate of hole angle changemay be kept to a minimum but occasionally conditions will arise where the total holedeviation must be reduced.

When this condition occurs the pendulum technique is employed. If it is anticipated that thepacked hole assembly will be required after reduction of the hole angle, the packedpendulum technique is recommended.

The pendulum assembly is based on the principle that the only force available to straightena deviated hole is the weight of the drill collars between the point of tangency (stabiliser)and the bit.

In the packed pendulum technique, the pendulum length of collars are slung below theregular packed hole assembly. When hole deviation has been dropped to an acceptablelimit, the pendulum collars are removed and the packed hole assembly again is run abovethe bit. It is only necessary to ream the length of the pendulum collars prior to resumingnormal drilling.

If a vibration dampening device is used in the packed pendulum assembly, it should remainin its original pick-up position during the pendulum operations. (Refer to figure 10.f).

Figure 10.F - Pendulum BHA

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10.7. REDUCED BIT WEIGHT

By reducing the weight on the bit, the bending tendency of the drill string are changed andthe hole will be straighter.

One of the earliest techniques for straightening the hole was to reduce the weight on the bitand speed up the rotary table. In recent years it has been found that this is not always thebest procedure because reducing the bit weight sacrifices considerable penetration rate.

Worse than this, it frequently causes dog-legs as illustrated in. Therefore as a point ofcaution, the straightening of a hole by reducing bit weight should be done very gradually sothat the hole will tend to return to vertical without sharp bends and be much safer for futuredrilling. A reduction of bit weight is usually required when changing from a packed holeassembly to a pendulum or packed pendulum drilling operation.

Figure 10.G - Reduced Bit Weight

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10.8. DRILL STRING DESIGN

The normal drill string design practice aim is to avoid abrupt changes in component crosssectional areas.

Abrupt changes can lead to concentrations in bending stresses which in turn can lead to atwist off (Refer to figure 10.h).

The ratio I/C between the moment of inertia (I) and radius (C) of the pipe is directly relatedto the resistance to bending. The following are used to determine the section modulus I/C:

I = Moment of inertia

= π/64 x (OD4- ID4)

C = Radius of the tube

= OD/2

At a crossover from one tubular size to another size, the ratio (I/C large pipe)/(I/C smallpipe) should be less than 5.5 for soft formations and less than 3.5 for hard formations.

table 10.b shows the ratio (I/C) for the most common sizes of drill pipes, HW drill pipes anddrill collars.

table 10.c illustrates some possible drill strings and their acceptability.

Figure 10.H - Bending Moment

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Drill Collar Drill PipeOD (ins) ID (ins) I/C OD (ins) ID (ins) WT I/C

31/2 11/2 4.1 23/8 2 4.85 0.741/8 2 6.6 23/8 1.815 6.65 0.943/4 21/4 9.8 27/8 2.441 6.85 1.153/4 21/4 18.3 27/8 2.151 10.40 1.653/4 213/16 17.6 31/2 3 9.50 2.06 21/4 20.8 31/2 2.764 13.30 2.66 23/16 20.2 31/2 2.602 15.50 2.9

61/4 21/4 23.3 4 3.476 11.85 2.761/4 23/16 22.7 4 3.340 14.00 3.261/2 21/4 26.7 41/2 3.958 13.75 3.661/2 23/16 26.2 41/2 3.826 16.60 4.363/4 21/4 30.1 41/2 3.640 20.00 5.163/4 23/16 29.6 5 4.408 16.25 4.97 23/16 32.7 5 4.276 19.50 5.7

71/4 23/16 37.5 5 4.000 25.60 7.373/4 23/16 44.6 51/2 4.892 19.20 6.173/4 3 44.4 51/2 4.778 21.90 7.18 23/16 49.5 51/2 4.670 24.70 7.88 3 49.3 65/8 5.965 25.20 9.8

81/4 23/16 55.981/4 3 54.281/2 3 59.29 3 71.0

91/2 3 83.810 3 97.2

111/4 3 138.812 3 154.5

Extra Weight Pipe

OD (ins) ID (ins) WT I/C41/2 213/16 32.0 7.75 3 42.6 10.7

l =(Moment of Inertia) = (1/64) x (OD4 – ID4) x 3.142

C = Radius of the Tube in inches

PipesDrillC/ICollarsDrillC/I

Ratio =

Table 10.B - I/C Ratios for standard Tubulars

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Hole Size(ins)

Drill Collar/Drill Pipe(ins)

I/C I/C Ratio Remarks

DC 91/2 x 3 83.8 1.5

DC 81/4 x 213/16 55.9 9.8

DP 5 x 19.5lbs/ft 5.7 - Not

DC 91/2 x 3 83.8 1.5 Recommended

DC 81/4 x 213/16 55.9 7.1

DP 51/2 x 19.5lbs/ft 7.8 1.4

DP 5x 19.5lbs/ft 5.7 -

171/2 DC 91/2 x 3 83.8 1.5 OK for

DC 81/4” x 213/16 55.9 5.2 SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

DC 91/2 x 3 83.8 1.5

DC 81/4 213/16

” 55.9 2.5 OK For HARD

DC 61/4 x 213/16” 22.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

Note: For every hard formations, add HWDP

DC 91/2” x 3” 83.8 1.5

121/4” DC 81/4 x 213/16” 55.9 2.5 OK For HARD

DC 61/4 x 213/16 22.7 3.9 Formations

DP 5” x 19.5lbs/ft 5.7 -

Note: For every hard formations, add HWDP

DC 91/2” x 3” 83.8 1.5

121/4” DC 81/4 x 213/16” 55.9 5.2 OK For SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5 lbs/ft 5.7 -

DC 61/4 x 213/16” 22.7 Not

DP 5” x 19.5lbs/ft 5.7 3.9 Recommended

85/8 DC 61/4 x 213/16” 22.7

HWDP 5” x 42.6lbs/ft 10.7 Recommended

DP 5” x 19.5lbs/ft 5.7

Table 10.C - Drill String Acceptability

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10.9. BOTTOM HOLE ASSEMBLY BUCKLING

Without weight on the bit, a drill string is straight if the hole is straight. With a sufficient smallweight applied on the bit, the string will remain straight. As the weight is increased, a criticalvalue of weight is reached and the drill string will buckle and contact the wall of the hole. Ifthe weight on the bit is further increased, a new critical value is reached at which the drillstring buckles a second time. This is designated as ‘buckling of the second order’. With stillhigher weights on the bit, buckling of the third and higher orders occur.

When a buckled string is rotated, stresses in the outside fibres of tubular are developed.These stresses increase with the diameter of the hole and results in fatigue failure of thestring. As soon as a drill string buckles in a straight hole, the bit is no longer vertical and aperfectly vertical hole can not be maintained. Therefore, in the design of BHAs, it isimportant to determine the critical values of weight on bit at which buckling occurs.

The critical weight on bit of the first order (Wcr1) and second order (Wcr2) are given by thefollowing equations:

Wcr1 = 1.94 x m x p

Wcr2 = 3.75 x m x p

where:

m = Length of one dimensionless unit, in meters

p = Weight in mud per unit of length of the pipe, in kg/m

The dimensionless unit ‘m’ is a function of Young's modulus for steel, moment of inertia ofthe pipe cross section and weight in mud per unit of length of the pipe. The values of ‘m’ forvarious sizes of drill collar are plotted in figure 10.i.

Under normal conditions, some buckling of the drill string is inevitable, therefore stiffercollars and stabiliser should be used for control of the hole angle.

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Figure 10.I - Dimensionless Unit (m) for Various Sizes of DC

1, 1, 1, 1, 1, 2, 2,14

15

16

17

18

19

20

21

Mud Weight

m

6 3/4" * 2

6 3/4" * 26 1/2" * 2

6 1/2" * 2

6" * 2

6" * 2

4 3/4" * 2

1,0 1,2 1,4 1,6 1,8 2,0 2,218

20

22

24

26

28

Mud Weight

m

11" *

9 1/2" *

8 1/4" *

8 1/4" * 2

8" *

8" * 2

7 1/2" * 2

Dimensionless Unit (m) for Various

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10.10. SUMMARY RECOMMENDATIONS FOR STABILISATION

1) For the vertical section of the hole the purpose of stabilisation, more than any otherfactor, is to maintain the drift angle as low as possible to zero and, if applicable, toprevent wall sticking.

2) For deviated holes, the stabiliser positions in the BHA depend entirely on directionaldrilling requirements and as a rule determined by the Directional Engineer.

3) All stabilisers shall be the ‘integral type’ and machined from a single block of materialor the ‘integral sleeve type’ fitted by head or hydraulic pressure (not threaded).

4) The spiral profile of blades, for both string and near bit type stabiliser, shall be the‘right hand type’.

5) All stabilisers for hole size up to 121/4” must be the tight type in order to assure acomplete (360°) contact with the borehole. All stabilisers for hole size over 121/4" mustbe open type but not less than 210°.

6) All stabilisers should have a fishing neck with the same OD as the drill collars and alength not shorter than 20” for stabilisers up to 6” hole size and 26” for larger hole sizestabilisers.

7) All stabilisers smaller than 15" OD shall have three blades. Stabilisers larger than 15"shall have four blades as standard.

8) Stabilisers (and subs, etc.) should be demagnetised after a magnetic particleinspection.

9) The maximum allowable reduction value on outside diameter of stabilisers should beaccording to the attached tables .

10) Tungsten carbide smooth surface solid body integral blade stabilisers are preferred.Integral sleeve stabilisers may also be used in large hole sizes above 121/4", mainly asthe near bit stabiliser, in order to position the stabilisation point right on top of the bit.

11) The maximum allowable wear of the stabiliser blades should be in accordance withthe previous point. If such a limit is reached at any point, the stabiliser has to bereplaced.

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HoleSize

BodyOD

RotaryConns

Blade ODStringType

Blade ODNear

Bit Type

Length of Fishing

Neck

Length ofPin End

Length ofBox Bit

Min Widthof Blades

53/4 421/32 NC 38 519/32 519/32 20 12 10 257/8 421/32 NC 38 523/32 523/32 20 12 10 26 421/32 NC 38 523/32 527/32 20 12 10 2

83/8 63/8 NC 46 83/16 813/64 26 12 10 21/281/2 63/8 NC 46 85/16 821/64 26 12 10 21/2

121/4 77/8 6 5/8 R 12 123/64 26 12 10 3121/4 93/8 7 5/8 R 12 123/64 26 12 10 316 93/8 7 5/8 R 153/4 153/4 26 12 10 416 107/8 8 5/8 R 153/4 153/4 26 12 10 4

171/2 93/8 7 5/8 R 173/4 171/4 26 12 10 4171/2 107/8 8 5/8 R 173/16 171/4 26 12 10 423 93/8 7 5/8 R 2211/16 223/4 26 12 10 423 107/8 8 5/8 R 2211/16 223/4 26 12 10 426 93/8 7 5/8 R 2511/16 253/4 26 12 10 426 107/8 8 5/8 R 2511/16 253/4 26 12 10 428 107/8 8 5/8 R 2711/16 273/4 26 12 10 4

Main dimensions of string and near bit type stabilisers in ins.

Table 10.D - Acceptable Dimensions For Used String And Near Bit Stabilisers

The maximum overall length, for string type stabilisers only, must be as follows:

• 75" for 53/4" to 6" hole size stabilisers• 85" for 83/8" to 121/4" hole size stabilisers• 100" for 16" to 28" hole size stabilisers.

Hole Size Body OD RotaryConn.

Blade ODString Type

Length ofFishing Neck

LengthPin End

Minimum Widthof Blades

6 421/32 NC 38 527/32 20 12 2 81/2 63/8 NC 46 85/16 26 12 21/2

121/4 77/8 6 5/8 R 12 26 12 3 121/4 93/8 7 5/8 R 12 26 12 3 16 93/8 7 5/8 R 153/4 26 12 4

171/2 93/8 7 5/8 R 173/16 26 12 4 Main dimensions of string and near bit type stabilisers in ins.

Table 10.E - Acceptable Dimensions For Used String And Near Bit Stabilisers

The maximum overall length must be as follows:

• 75" for 6" hole size stabilisers• 85" for 81/2" to 121/4" hole size stabilisers• 100" for 16" to 171/2" hole size stabilisers.

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10.11. OPERATING LIMITS OF DRILL PIPE

The design of the drill string for static tensile loads requires sufficient strength in drill pipe tosupport the submerged weight of drill pipe and drill collar below. The submerged load (P)hanging below any section of drill pipe can be calculated as follow:

( ) ( )[ ] bccdpdp KxWxLWxLP +=

where:

Ldp = Length of drill pipe in feet

Lc = Length of drill collar in feet

Wdp = Weight per foot of drill pipe in air

Wc = Weight per foot of drill collar in air

Kb = Buoyancy factor

The difference between the maximum allowable tension and the calculated load representsthe Margin of Over Pull (MOP):

MOP = (Pt x 0.9) - P

where:

Pt = Theoretical tension load from table

0.9 = Design factor

The minimum recommended value of MOP is 60,000lbs (27t) and it shall be calculated forthe topmost joint of each size, weight, grade and classification of drill pipe. The anticipatedtotal depth with next string run and expected mud weight should be considered whencalculating the MOP.

The overall drilling conditions (directional well, hole drag, likelihood of becoming stuck, etc.)may require higher values of MOP. When the depth is reached where the MOP approachesthe minimum recommended value, stronger drill pipe shall be added to the string.

10.12. GENERAL GUIDELINES

1) Packed hole assemblies shall generally be used unless otherwise dictated by holeconditions.

2) Standard packed hole assembly should be:

3) Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K Monel DC + String Stab +2 DC + String Stab.

4) A stabilised string can be used to drill out shoe-tracks after casing setting unless thereis so much cement left inside the casing to discourage such a procedure.

5) If the bottom hole assembly is different from the one previously used, run in the holewith maximum care, monitoring the weight indicator closely. Any indication of stringdragging must be promptly detected. Tight zones must be reamed free beforeproceeding with the trip.

Any change in the stabilisation from that specified in the drilling programme must beauthorised by the Company Drilling Office

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11. BIT SELECTION

This section is a guide to engineers in the selection of bits and bit optimisation.

11.1. PLANNING

Selection of the proper bits for a well programme is an important decision that has a bigimpact on well costs. Many factors need to considered and evaluated:

• Bit cost• Method of drilling (turbine, rotary, air)• Formation type and properties• Mud system• Rig cost

With emerging improvements in technology on bit design, it is necessary to optimise drillingoperations by evaluating all of the above parameters.

Drilling optimisation can be considered to having three phases:

a) Selection of the proper bit for drilling conditions

b) Monitoring the drilling performance and conditions on the prospect well so thatthe performance is equal to or above the average in the area.

c) Implementing a bit weight-rotary speed programme based on theoreticalcalculations that will improve the performance above the existing bestperformances in the area.

The last phase is difficult to implement in a one or two well drilling programme but isvaluable in development drilling. However, often the first two phases are not given theimportance they deserve

11.2. IADC ROLLER BIT CLASSIFICATION

The array of bit names and nomenclature in earlier years gave rise for the need of astandard classification system. In 1972 the IADC adopted a three digit classification systemfor roller bit nomenclature. Most bit manufacturers adopted the system followed by the APIand the system now appears as API Recommended Practice 7G

The original system uses a three digit code for classification constructed as follows:

A, B, C

where:

A: Is a number from 1-8, which is the major class

B: Is a number from 1-4, which is the subgroup

C: Is a number from 1-9, which is the speciality feature

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11.2.1. Major Group Classification

The major classification number denotes the formation types in which the rollers bit shouldbe used as per table 11.a below:

Group Number Formations

Mill Tooth Bits

1 Soft formations of low compressive strength and high drillability

2 Medium to medium-hard formations with high compressive strength

3 Hard semi-abrasive or abrasive formations

Insert Bits

4 Very soft formations

5 Soft to medium formations with low compressive strength

6 Medium-hard formations with high compressive strength

7 Hard semi-abrasive or abrasive formations

8 Extremely hard and abrasive formations

Table 11.A – Roller Bit Major Group Classification

Sub-Group Classification

The subgroup classification is simply four progressive steps of compressive strength from 1being low up to 4 for the highest within that major group.

For example a 1-2 bit is a mill tooth bit designed to drill formations of a slightly greatercompressive strength than required for a 1-1 bit, etc.

Speciality Feature

The code numbers and relative speciality features are shown in table 11.b below:

Code Number Feature

1 Standard

2 Air

3 Gauge insert

4 Roller seal bearing

5 Seal bearing and gauge protection

6 Friction seal bearing

7 Friction bearing and gauge protection

8 Directional

9 Other

Table 11.B– Special Feature Codes

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11.2.2. Bit Cones

The range of bits listed in the major classification primarily has two types of cone. Theoriginal cutter bits had cone teeth machined out of the cone material by a mill, hence theywere termed ‘Mill Tooth’ bits. These bits, however, were found to wear quickly when hardabrasive rocks were encountered. This resulted in the introduction of cones which had teethinserted into the cone made of more wear resistant materials such as tungsten carbide. Theinserts are of varying shapes to suit the best penetration in a particular rock.

The mill tooth bit cone teeth can be heat treated to provide better wear resistance but onlyare good up to classification 3. Insert bits are used for range 4 through 8, see table 11.cbelow:

Cone offset also has a significant effect on the penetration rate due to the shearmechanism which best suits the formation types.

Type Class Formation Type Tooth Description Offset

1-1, 1-2, Very soft Hard-faced tip 3-4o

Mill 1-3, 1-4 Soft Hard-faced side 2-3 o

Tooth 2-1, 2-2 Medium Hard-faced side 1-2o

Bits 2-3 Medium hard Case hardened 1-2o

3 Hard Case hardened 0o

4 Very soft5-2 Soft Long blunt chisel 2-3o

5-3 Medium-soft Long sharp chisel 2-3o

Insert Bits 6-1 Medium shales Medium chisel 1-2o

6-2 Medium limes Medium projectile 1-2o

7-1 Medium hard Short chisel 07-2 Medium Short projectile 08 Hard chert Conical or hemispherical 0

Table 11.C– Roller Bit Type and Classification

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11.3. DIAMOND BIT CLASSIFICATION

Two types of diamond bits are used for special applications where their cutting action ismost efficient. These are natural diamond and the PDC (Poly-crystalline Compact).

11.3.1. Natural Diamond Bits

Natural diamond bits are constructed with diamonds embedded into a matrix and are usedin conventional rotary, turbine, and coring operations. Diamond bits can provide improveddrilling rates over roller bits in some particular formations and all the diamond bit suppliersprovide comparison tables between roller bit and diamond bit performance to aid users in bitselection based on economic evaluation.

Some of the most important benefits of diamond bits over roller bits are:

• Bit failure potential is reduced due to there being no moving parts.• Less drilling effort is required by the shearing cutting action compared to the

cracking and grinding action of the roller bit.• Bit weight is reduced, therefore deviation control is improved.• The low weight and lack of moving parts make them well suited for turbine

drilling.

11.3.2. PDC Bits

PDC or Stratapax bits were introduced in the 1970s and features the greater abrasionresistance of the diamond complimented by the strength and impact resistance of cementedtungsten carbide.

The advancement in technology in PDC design and performance in recent years has beensignificant and there is now many manufacturers with wide ranges of bits now available.

Due to the diversity of bits and bit features available, there is no IADC classification systemsimilar to roller bits but simply a code to provide a means of characterising the generalphysical of fixed cutter drill bits.

11.3.3. IADC Fixed Cutter Classification

To cater for the wide range of fixed cutter bits including natural diamond and PDC, IADCintroduced the following classification system.

The classification system consists of a four character code

Code 1 - Cutter Type and Body Material (D, M, T, S, O)

Code 2 - Bit Profile (1-9)

Code 3 - Hydraulic Design (1-9)

Code 4 - Cutter Size and Density (1-9)

Code 1 Code 2 Code 3 Code 4

Cutter Type & BodyMaterial

Bit Profile Hydraulic Design Cutter Size andDensity

Table 11.D - IADC Fixed Cutter Classification Code

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Code 1

The subgroup classification is simply a five letter designation categorising the type of cutterand body material.

Group Letter Cutter Type and Body Material

D Natural Diamond Matrix Body

M PDC Matrix Body

T TSP Matrix Body

S PDC Steel Body

O Other

Table 11.E – Code 1 Cutter Type and Body Material

Code 2

The code numbers (1-9) categorise the bit profile by shape.

Code 2 Bit Profile

1 Long Taper Deep Cone

2 Long Taper Medium Cone

3 Long Taper Shallow Cone (parabolic)

4 Medium Taper Deep Cone

5 Medium Taper Medium Cone

6 Medium Taper Shallow Cone (rounded)

7 Short Taper Deep Cone (inverted)

8 Short Taper Medium Cone

9 Short Taper Shallow Cone (flat face)

Table 11.F– Code 2 Bit Profile

Code 3

The code numbers (1-9) describe the hydraulic features.

Changeable Sets Fixed Ports Open Throat

Bladed 1 2 3

Ribbed 4 5 6

Open Faced 7 8 9

Table 11.G - Code 3 Hydraulic Design

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Code 4

The code numbers (1-9) categorise the cutter size and cutter material.

Light Medium Heavy

Large 1 2 3

Medium 4 5 6

Small 7 8 9

Table 11.H - Code 4 Cutter Size and Density

An example bit code would then be M442 equates to a PDC bit with matrix body, mediumtaper-deep cone, changeable jets-ribbed design with large size cutter of medium density.

11.4. BIT SELECTION

Selecting the correct bit for the anticipated drilling conditions requires an evaluation ofnumerous parameters. Since the variety of bits available, outlined in the previous sections,is much wider with the introduction of innovative bit designs and the improvement in existingdesigns, the bit selection process is now much more complicated than it was previously.However there is still a simple guidelines that can be used to increase drill rates and, hencereduce drilling costs.

The parameters involved in the selection of drill bits are:

• Formation hardness• Mud types• Directional control• Rotary system• Coring• Bit size

11.4.1. Formation Hardness/Abrasiveness

As can be seen from the previous IADC bits are generally categorised by the hardness ofthe formation they can drill, however these classifications are vague but unfortunately nosuperior classification method exists.

Some formations such as ‘medium to hard’ are sometimes wrongly defined because theyhad previously experienced low drilling rates although this was actually due to wrong bitselection or operating parameters used.

Where a number of bits can be used, say to drill a soft formations, the bit selected willdepend on other conditions such as mud type and hole size. Therefore, bit selection in softformations becomes a matter of defining the conditions that produce the lowest drillingcosts.

Bit action in hard and abrasive formations is by failure in the compressive mode and as aresult bits which use shear action are not very successful. In this case, roller bits in IADCcode range 6-1-7 or higher are usually more successful as they have been designed forabrasive wear which may be very damaging to shear failure action bits.

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Formations with sticky characteristics, often resulting from clay rocks that are hydratable,the cuttings stick to the teeth or bit structure and impede drilling efficiency. Bits designed forsticky formations have a high degree of teeth inter-fit and hydraulics such as centre jettingcapabilities. PDC, diamond and short tooth roller cone bits have been particularlyunsuccessful unless when PDCs are used with oil based mud.

In general, PDC bits drill faster than mill tooth or diamond bits in soft to medium-soft rocksunless they are sticky. This is substantiated by numerous results test reports.

11.4.2. Mud Types

Oil based muds often reduce the drilling rates with roller cone bits whereas PDC anddiamond bits are not effected. Oil based mud is actually believed to enhance theperformance of PDC bits since they inhibit clay hydration and stickiness.

Air drilling almost certainly requires the use of roller cone bits as air cannot providesufficient cooling as liquids do, therefore causing bit failure. Cone bits are available withinternal porting to the roller bearings keeping them cool enough and, although PDC anddiamond bits do not have ant moving parts, the matrix and blade structures becomes weakand break. Diamonds themselves will fail around 750oC for polycrystallines and 1,200oC fornatural.

11.4.3. Directional Control

Directional control is affected by a number of factors including these relating to drill bits. Thefactors affecting directional control are:

• Method of drilling• BHA design• Type of bit• Rotary bit cone offset, number of cones, cutting structure on the cone• Bit weight

Rotary drilling operations are inclined to right-hand walk. This tendency is increased whenusing roller bits are used as cone offset from the bit centre increases. The advantage ofincreased drilling rate when using cones with higher offsets must be balanced with thedifficulty in maintaining directional control.

Turbine drilling may have a tendency to left-hand walk. This is controlled by the turbineused, bit gauge length, and BHA stabilisation.

Some bit manufacturers have developed two and four coned roller bits purely for directionalcone purposes. These are include in the IADC codes under special feature #8, e.g. 1-2-8 isa soft bit for directional control.

Roller bits are also available with a special cutting structure that are caused by formationdip which normally induces movement towards the dip. The special feature is outside teeththat dig into a dipping formation thus preventing the movement towards the dip.

High bit weights tend to increase directional control problems and, vice versa, low bitweights help maintain straight hole at a penalty in reduced drilling rate. Due to this PDC bitswith their relatively lower bit weights and no cones, hence cone offset problems arefavoured.

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11.4.4. Drilling Method

The means of turning the bit with either the rig’s rotary system or downhole motor does notplace any restriction on bit selection. However, in general in deep wells, PDC bits arepreferred when using surface rotary systems as reduced weight on bit reduces torque dueto bit and wall friction which can be significant.

Due to turbine drilling efficiency, bits with long life expectancies should be used such asPDC, diamond and journal bearing insert bits.

11.4.5. Coring

Bits used for coring must be designed so that it minimises flushing of the formation fluidsfrom core by the mud. PDC or diamond bits are both used for coring operations and areselected by using the previous parameters outlined.

11.4.6. Bit Size

Roller bits are available off-the-shelf for almost all sizes between the range of 33/8” – 26” inalmost every type, cutting structure and jetting system. PDC and diamond bits are notavailable off-the-shelf as rotary bits in sizes over 15”.

In deep wells with small holes, i.e. 4” or 5”, the PDC bits have much better performance asthey have no moving parts as rotary bits which have high failure rates due their smallbearing areas.

11.5. CRITICAL ROTARY SPEEDS

The effect of rotary drilling speeds on the rate of penetration of toothed rotary bits is difficultto evaluate and has less impact than drilling weight. Apparent inconsistencies sometimesappear in the data which may be due to vibration originating at the bit which helps in therock failure and so aids the drilling process. Vibration on the other hand is undesirable as itcauses drill string material failures such as bearings and bit teeth or failures in drill stringcollars and drill pipe. It has often been proven that slower bit speeds and greater bit weightobtain faster rates of penetration.

It might be thought that drilling rate should be proportional to rotary speed since the drillingoccurs due to contact of between the bit teeth and the rock formations and that these areproportional to rotary speed. However this only holds true if the contact was equallyeffective at both slow and high rotational speeds. This linear assumption is notsubstantiated by any data and in fact penetration rates are less than linear. The followingfigure 11.a shows example drilling rates versus rotary speeds with differing bit weights andit is seen that the penetration rates are not linear to rotational speed.

When drilling in a particular area, the bit records for previous holes drilled in the area orother offset data obtained should be analysed to determine the initial best bit programmethen new technology or individual well requirements evaluated to perfect the programme.This will include rotary speeds.

Most bit suppliers will provide data on optimum bit weight and rotary drilling speeds forspecific areas of operation and most operating companies will also have built up asignificant data base on the types of bits they have used on previous drilling projects withrespective drilling parameters. These data from all of the sources should be evaluated toobtain the optimum drilling parameters.

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In practice the rotary speed should start slowly and increased until an optimum penetrationrate is achieved without vibration. In general, if weight on a bit is increased, the RPM shouldbe decreased and vice versa.

Note: Eni-Agip’s recommended weight on bit is 2ton/inch of hole diameter.

Critical rotary speed can be calculated by:

Critical Rotary speed ( )

2

/22

LP

IDDP4760000 21

+=

where:

DP = Diameter of drill pipe, ins

ID = Internal diameter, ins

LP = Length of pipe joint, ins

Figure 11.A - Rotary Speed Effect on Drilling Rate

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11.6. DRILLING OPTIMISATION

In past years many attempts have been made to optimise drilling operations. Some of theefforts have been directed in:

• Developing drilling fluids to that yield high rates of penetration• Improving solids control equipment to improve mud properties• Designing bits to improve penetration rates, bit life or both

Nowadays, the primary criteria is economic resulting in optimisation based on the correctselection of bit weight, rotary drilling speed and bit types which produce the lowest cost perfoot or metre, i.e. minimum cost drilling or MCD.

The cost of the depth drilled during a single bit run is the sum of three costs, bit cost, tripcosts and rig operating costs for the time required for the depth drilled. Dividing the bit runcost by the footage drilled, results in the cost per foot. The trip costs and rig operating costsare variable whereas the bit cost is fixed and generally less significant (Refer to figure 11.b).

With MCD it should be noted that selection of proper bit weights and drilling speeds doesnot always yield the maximum ROP nor the longest bit runs.

Figure 11.B - Drilling Cost Per foot

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12. DIRECTIONAL DRILLING

Controlled Directional Drilling can be defined as the technique of intentionally deviating awell bore so that, the bottom hole location or any intermediate portion of the hole, ispositioned in a predetermined target(s) area, that is located at a given horizontal andvertical distance from the surface location of the well.

Many new tools and techniques have been developed in recent years to enhance theaccuracy of this technique.

12.1. TERMINOLOGY AND CONVENTIONS

True North: The direction from any point on the earth's surface to thegeographic north pole which is fixed.

Geographic North: The direction from any point on the earth’s surface.

Magnetic North: The direction from any point on the earth's surface to themagnetic north pole.

Magnetic Declination: The angle between True North and the direction shown by thenorth pointer of a compass needle at the location beingconsidered, measured from True North. Magnetic declinationfor a given location changes gradually with time, An annualrate of change is applied to give the present declination. Themagnetic declination and rates of change are obtained fromdetailed charts or computer program. To obtain thegeographic direction, the direction obtained from magneticsurveys shall be corrected simply by adding or subtracting theappropriate declination.

Direction: Directions can be measured and given in three ways:

• Azimuth, where the angle is measured from north in aclockwise direction from 0 to 360° (for example: 252°AZ).

• Quadrant Format (called ‘Field Co-ordinate’ or ‘Oil FieldFormat’), the direction is expressed as an angle E or Wof N or S (the 252 AZ becomes S72° W).

• Bearing Angle, the angle is measured from 0 to 180°East (positive) or West (negative) of North (108° W or –108°).

The correction due to magnetic declination is the same forany of the three formats.

Inclination (Inc) alsotermed Drift:

The angle the centre line of the well bore makes with avertical axis below the well. By definition, straight holes havezero angle of inclination. All inclination angles are positive.

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Target: A predetermined area of interest whose position is defined byits horizontal and vertical distance from the surface location ofthe well.

Well Path: The path of the bore hole drilled by the bit.

Projected Well Path: The path expected of the bit to follow beyond the end of thewell bore.

Station: A survey data point. A station length is the measured footagebetween stations. The well path is described by all of the datapoints therefore a well path survey is all the data pointssurveyed.

Survey Data The inclination angle, the direction of the well bore is pointingand the measured depth of the surveying instrument.

Build Up Rate (BUR): The build-up should be kept as close as possible to thedesignated well trajectory ensuring that the rate of build-upneither lags behind nor exceed the projected well path. Largerates of build-up result in increased torque and wear on drillpipe and casing and in the problems associated withaccidentally side tracking or formation of key seats.Insufficient build-up rate will result in an increased final anglerequired to achieve the objective; generally build-up rates of1.5 to 3.0o/100ft are normally used.

Dog Leg Severity(DLS):

The rate of change of the combination of both inclination anddirection of a well path between data points. It is usuallyexpressed in degrees per 100ft or 30m interval drilled.

Tangent Section: The section of the well starting from the end of build up andwhere direction and inclination are maintained constant.

HorizontalDisplacement (orHorizontal Departure):

The distance projected onto a horizontal plane from the originto the point under consideration.

Vertical Section: The projection of the horizontal displacement onto a verticalplane usually along the target direction.

Lead Angle: When drilling with rotary drilling assemblies there is atendency for the hole to ‘walk to the right’. Turbine drillingassemblies have the opposite tendency, that is ‘walk to theleft’. The lead is the angle to be applied to the projectdirection at kick-off to correct the walking tendency of thedrilling assemblies.

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12.2. CO-ORDINATE SYSTEMS

12.2.1. Universal Transverse Of Mercator (UTM)

In the Transverse Mercator Projection the surface of the spheroid chosen to represent theEarth is wrapped in a cylinder which touches the spheroid along a chosen meridian.

From the centre of the globe (Refer to figure 12.a), shapes on the surface of the spheroidare transferred to the surface of the cylinder (A becomes A1 and B becomes B1). Thecylinder is then unwrapped giving a correct scale representation along the central meridianand an increased scale away from it.

Figure 12.A - Universal Transfer Of Mercator

As a Mercator projection becomes increasingly inaccurate as one moves away from thechosen meridian, a series of reference meridians is used so that it is always possible to usea map with the reference meridian close to the place of work.

The reference meridians used are 6 degrees apart providing 60 maps, called zones, tocover the whole world. The zones are numbered 0 to 60 (from west to east) with zone 31having the 0o meridian (Greenwich) on the left and 6o E on the right.

Each zone is further sub-divided into grid sectors each one covering 8o latitude starting fromthe equator. Grid sectors are identified by the zone number and by a letter ranging from Cto X (excluding I and O) from 80o South to 80o North. Identification of the sector is simplythe number and letter of the relevant area, i.e. 31U being the Southern North Sea (Refer tofigure 12.b).

The co-ordinates for each UTM grid sector are given in meters with the origins (i.e. the zerovalue) at a line 500,000m West of the centre meridian to avoid negative values and at theequator. The co-ordinates are given as Eastings and Northings.

CIRCLE OF CONTACTNORTH POLE (AXIS)

A1 B1

A B

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Example

UTM co-ordinates of the rig:

410,261.0 E

6,833,184.2 N

The rig is 500,000 - 410,261m west of the central meridian and 6,833,184.2m north of theequator.

The bearing between any two points in the same grid sector is referenced to Grid Northwhich is the direction of a straight line running from top to bottom of the map.

Convergence is the angle ‘a’ (Refer to figure 12.b) between the Geographic North and theGrid North for the location being considered measured from Geographic North. In thenorthern hemisphere the convergence is positive for locations east of central meridian andnegative for locations west of central meridian. The opposite applies for the southernhemisphere.

Figure 12.B - Convergence Angle

12.2.2. Geographical Co-ordinates

Generally rig and target co-ordinates are given in either UTM and/or geographical co-ordinates.

Geographical co-ordinates are expressed in degrees, minutes and seconds for Latitude andLongitude. Each degree is subdivided into 60 minutes and each minute further subdividedinto 60 seconds (Refer to figure 12.c).

Example

Rig location:

3° 36' 01.0" E Longitude

40° 43' 06.5" N Latitude

For the purpose of calculations degrees, minutes and seconds are often converted intodecimal degrees. This is done by dividing the minutes by 60 and the seconds by 3,600 sothat 3° 36' 01" becomes:

3 + 36/60 + 1/3600 = 3,600.278°

G G G N G G G True North

a

CENTRAL MERIDIAN

NORD (CENTRALMERIDIAN)

- +

+ -

WESTEST

EQUATOR LINE

SOUTH

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Figure 12.C - Grid Sectors

-24 -18 -12 -6 0 6 12 18 24 30 36 42 48 54 60 66 72-8

0

8

16

24

32

40

48

56

64

31 U

V

U

T

S

R

Q

P

N

27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

THE METHOD OF ZONE NUMBERING ACCORDING TO THE UTM SYSTEM ESCH ZONE IS 6° LONGITUDE IN WIDTH AND EXTENDS FROM 80° NORTH TO 80° SOUTH

5 10 15 20 25 30 35 40 45 50 550

5 10 15 20 25 30 35 40 45 50 5560

N 80° N 80°

S 80° S 80°

DEGREE

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12.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT

The first step in planning a well, starts with the data defining the rig and target locations,generally in UTM or geographical co-ordinates. With these data the horizontal displacementand direction to the target can be calculated.

If the data supplied for the rig and target location are in geographical co-ordinates thesemust first be converted to UTM data.

12.3.1. Horizontal Displacement

Using UTM co-ordinates (Refer to figure 12.d), displacement and direction can bedetermined with trigonometry as shown in the following example.

UTM co-ordinates of rig: 410,261.0 E 6,833,184.2 N

UTM co-ordinates of target: 412,165.0 E 6,834,846.0 N

Absolute difference in Eastings: 1,904.0m

Absolute difference in Northings: 1,661.8m

Figure 12.D - Example Calculation Of Horizontal Displacement

The origin used may correspond to wellhead or slot in a template.

The horizontal displacement (HD) to the target is thus:

HD = (1661.82 + 1904.02)½ = 2527.21m

RIG

TARGET

H D 2527,21 m1661,8 m

1904,0 m

48,9°

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12.3.2. Target Direction

The bearing to the target is:

φ = tan1 (1,904.0 : 1,661.8) = 48.90° or N 48.90° E

12.3.3. Convergence

The target co-ordinates and bearing, as calculated above , are relative to the Grid North.Since survey data make reference to the Geographic North (also called True North), theconvergence must be applied to the target co-ordinates and bearing to present themrelative to the Geographic North.

Taking convergence as being 1.45° in this example (Refer to figure 12.e), it is necessary torotate the target location about the origin of the well by -1.45° to place it in its relativeposition to True North.

Figure 12.E - Example Grid Convergence

In the previous example the bearing of the target with respect to Grid North was 48,90° or N48.90° E. Then the target bearing relative to the True North is:

48.90 - 1.45 = 47.45° or N 47.45° E

The horizontal displacement remains the same but its co-ordinates change. The True Northco-ordinates of the target are calculated with trigonometry as follow:

Eastings = 2,527.21 sin 47.45 = 1,861.76

Northings = 2,527.21 cos 47.45 = 1,708.98

Grid North

True North

Target

Est

Fig. (a)

-1,45°Grid

Convergence

GRID NORTH

RIG

NEW TARGET

ESTFig. (b)

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12.4. HIGH SIDE OF THE HOLE AND TOOL FACE

The high side is the top of the hole viewed along the bore hole axis. Assuming the hole hasan inclination, the low side is the path, that a small, heavy ball would follow if it is rolledslowly down the well (Refer to figure 12.f).

Figure 12.F - Definitions of Inclined Hole

During a kick off or correction run, the measurement of greatest value is tool facing since itindicates the orientation of the bent sub. When a MWD or steering tool is used to controlthe deviation, tool face is referred to the high side of the hole when sufficient inclinationexists (over 5o) or to magnetic North for low inclinations (up to 5o). The gravity tool faceangle (GTF) is the projection onto a plane perpendicular to the hole axis of the anglebetween high side of the hole and tool face.

The magnetic tool face angle (MTF) is the projection onto horizontal plane of the anglebetween magnetic North and tool face(Refer to figure 12.g)

Figure 12.G - Magnetic Tool Face

HIGH SIDE

LEFT RIGHT

LOW SIDE

ROLLING BALL

HIGH SIDE

ROLLING BALL

a

a

LOW SIDE VERTICAL

TOOL FACE

MAGNETIC NORTH 45°

TOOLFACE

LEFT RIGHT

HIGH SIDE

LOW SIDE

Steering the mud motor by means of magnetictoolface Bit and mud motor trying to kick off inthe direction of 45° magnetic azimuth

Steering the mud motor by means ofgravity toolface Bit and mud motor trying tobuild angle and turn well to the right

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12.4.1. Magnetic Surveys

Length Of Non Magnetic Drill Collar

Magnetic instruments must be run inside a sufficient length of non-magnetic drill collars(NMDC or Monel Collar) made of special nickel alloy to allow the instrument to respond tothe earth's magnetic field, by isolating it from the magnetic influence of the drill string.

The required length of NMDC is determined by taking into account the following factors:

• The geographical area of operations. Since the earth's horizontal magneticintensity varies geographically, a zone selection map is used to determine whichset of empirical data should be used for a given area.

• The proportion of steel drilling tools below the NMDC.• The direction and inclination of the well.

The Directional Drilling Contractor shall provide updated indication of magnetic intensityrelated to the area of operation.

Compass spacing is generally recommended to be at or below the centre of the non-magnetic collars.

Magnetic Single Shot Surveys

Prior to use, the instrument should be thoroughly checked out and tested to ensure it is ingood working condition. After loading, the timer is set and synchronised with a watch on thesurface.

The time required for the instrument to fall is approximately 1,000ft per minute forinclinations up to 40o and 800ft per minute for inclinations over 40o. A safety margin of 5mins shall be added to the calculated running time. Mud weight and viscosity are importantfactors to be considered, as are drill string restricted internal diameters.

For high inclinations (over 60) sinker bars should be used and the survey barrel may needto be pumped down. The mud pump rate should be very low, giving just sufficient pressureto break circulation. The drill string may be rotated slowly (not however, if running thesurvey on wireline) and reciprocated to prevent sticking and assist the survey tool inreaching bottom.

Drill pipe movement and pumping (if used) should be continued until a minute or so beforethe timer is due to operate..

If run on wireline, it should be taken into account the time the instrument generally takeslonger to assemble and to run. Sandlines are quicker to run but can cause higher wear ondrill pipe protective linings. Whichever wireline is used, thread protectors should be installedon the tool joint.

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Magnetic Multishot Surveys

Magnetic multishot surveys are generally run prior to running casing as a check on thesingle shot surveys taken while drilling. This survey may be run either as an in run orrunning outrun survey, although it is generally run on the outrun wiper trip before casing.This gives an opportunity for the instrument to be retrieved at the casing shoe and checkedwhilst the trip back to bottom is being made. A second opportunity is then available ifnecessary.

As the name implies, the magnetic multishot provides a series of single shot surveys. Thecamera of the instrument, instead of carrying one single shot disc, contains a length ofphotographic film. The film is exposed and advanced continuously, at a set time interval,from the time the instrument is started until stopped. The interval between exposure isgenerally 20secs but it is altered on some instruments.

The survey is normally made by dropping the instrument into the drill string and allowing it toget to bottom before pumping the slug and commencing the trip out of the hole.

As the drill string becomes stationary in the slips after each stand is broken off, the timesince starting the instrument is recorded together with the number of stands out of hole.This enables the survey picture to be correlated to instrument depth. With an instrument seton a twenty second sample rate, good practice is to ensure there are a minimum of twosurveys taken at each depth by remaining stationary.

Steering Tool (with mud motor)

Steering tools use a system of magnetometers and accelerometers to measure the Earth'smagnetic field and gravity in order to determine inclination and direction.

The tool is run on a conductor wireline which provides power for the sensors and returns thesignal to the surface computer where it is decoded and relayed to the rig floor read out.

The tool may be operated on one of two modes displaying tool face with respect to North(Magnetic Tool Face) or relative to the high side of the hole (Gravity Tool Face). Themagnetic tool face mode is used in vertical or near vertical wells for kick off in the desireddirection. As the inclination is increased above about 5o the tool is switched to gravity toolface.

The advantages of steering tools over single shot orientation are in the continual read-out ofthe tool face whilst drilling and in saving time in situations where orientation problems mayrequire repeated single shot surveys.

One of the drawbacks of the system is the time required to pull the tool out of hole formaking pipe connections.

The steering tool system is used only in specific situations, i.e. KOP in a high temperaturezone.

When a motor is used for kick off or correction runs (operations not requiring rotation of thedrill string), a side entry sub may be used. This sub prevents the need to pull the tool tomake connections. The wireline passes through the entry sub enabling the drill pipe to beadded to the string in the normal manner.

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Measurement While Drilling (MWD)

Measurement While Drilling is a technique which takes various downhole measurementsand transmitting these data to the surface for decoding and display. The most commontransmission media is mud pulse telemetry in which the flowing column of drilling mud ismodulated periodically by some mechanical means within the downhole assembly. Theintermittent pressure pulses are transmitted from downhole to the surface where they aredetected by a pressure transducer mounted in the standpipe. The transducer converts themud pulses into electrical signal that is then transmitted to the surface computer. Thecomputer decodes and displays this transmitted information.

There are three distinct types of MWD transmission systems currently available, all usingmud column as their transmission medium:

• The positive system uses a plunger type valve that momentarily obstructs mudflow thus creating a positive, transient pressure pulse.

• The negative pulse system utilises a valve that momentarily vents a portion ofthe mud flow to the borehole annulus, resulting in a negative, transient pressurepulse.

• The continuous wave system utilises a spinning, slotted rotor and slottedstator that repeatedly obstructs mud flow. This operation generates acontinuous low frequency fluctuation in standpipe pressure of approximately50psi.

One of the most common applications for a directional MWD system is to orient downholemotor/bent sub assemblies when changing the course of the well path. Sensors locatedimmediately above the bent sub, taking measurements while the bit is drilling on bottom,provide immediate data (inclination, azimuth and tool face) to the Directional Driller.

As already discussed in the description of steering tool systems, tool face may be referredto magnetic North or high side of the hole, depending on hole inclination.

12.4.2. Gyroscopic Surveys

Gyro instruments are used when the proximity of casings or other magnetic interferenceprecludes the use of magnetic tools.

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Gyro Single Shot Surveys

Gyro single shot surveys are run on wireline. Since gyroscopes are delicate instruments,running speeds should be within that recommended and the tool stopped and started offgently.

The gyro instrument has the same mule shoe feature as the magnetic single shot used fororientation and, although it uses a different system, the data obtained is the same, (i.e. holedirection, inclination and tool face).

The maximum depth to which they can be effectively run is approx. 1,300ft about 400m.This is a limitation imposed by the time taken between orienting the gyro on surface,running into hole, taking the survey, pulling out of hole and checking the orientation.

The difference in azimuth between the initial orientation and final check on return to surfaceis the amount the gyro has drifted or wandered off its true north orientation. The drift isassumed to be constant for the time interval between initial and final orientation. Thecorrection is calculated by simply determining the proportion of drift occurring in the timefrom the initial orientation to the survey picture being taken. Gyro drift is approx. 4o per hourin static conditions and 8o per hour in dynamic conditions.

Gyro Multishot Surveys

The gyroscopic multishot is the survey tool for surveying extended intervals inside casing ordrill pipe without a non-magnetic drill collar. The tool comes in two sizes. The smaller onecan be run in completed wells or through drill pipe. The larger one is a more rugged tool andis used to run surveys inside casing. Depending on the length of survey run, it will be anumber of hours before the calculated survey data are available.

Gyro multishot drifts are the same as that of the single shot gyro.

Surface Read-out Gyroscopes

Surface read-out gyroscopes are used for the same purposes in single shot and multishotdata collection. The instrumentation is more sophisticated and requires a conductingwireline to power the tool and transmit the information back to the surface for decoding bycomputer. With a surface read-out multishot gyro, the drift can be constantly monitored toensure the tool is performing well and the calculated survey is produced shortly aftercompleting the log run.

Gyrocompass (North Seeking Gyroscope)

These instruments use the principle of earth rate gyro compassing to define true azimuthand inclination in near vertical parts of the borehole. Then, as the hole builds angle toabove 15° it switches to a continuous integrating mode. This dual mode makes the toolaccurate in either vertical and deviated borehole where it eliminates the inaccuracies thatgyrocompass based instruments have at high latitude, high inclination or in the East/Westaxis. The rugged construction makes these tools capable of steering and surveying whiledrilling (Gyro While Drilling).

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12.4.3. Survey Calculation Methods

When drilling on a cluster, the co-ordinates of the centre of the 30" conductor shall be usedon the rig for computations of each individual well.

The centre of the cluster may be used by the Company Drilling Office for mapping, planningand reporting.

There are a number of methods of calculating the wellbore trajectory from the survey data.The most common are:

• Average angle method: It assumes the borehole is parallel to the simpleaverage of both the drift and bearing angles between two survey stations. It isfairly accurate and calculation is simple enough for field use with a nonprogrammable scientific calculator.

• Radius of curvature: Using sets of angles measured at the upper and lowerends of sections along the surveyed course length, it generates a space curverepresenting the wellbore path. For each survey interval, it assumes that thevertical and horizontal projections of the curve have constant curvature.

• Minimum curvature method: shall be used on the rig, in Company Drillingoffice and Directional Drilling Contractor office for survey computations. Itassumes the borehole is a spherical arc with minimum curvature (maximumradius of curvature) between survey stations. It is the most accurate for mostboreholes, however it requires very complex calculations using a programmablecalculator or computer.

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Average Angle method

( ) ( ) 2/AAcosx2/LlsinxMDNorth 2121 ++∆=∆

( ) ( ) 2/AAsinx2llsinxMDEast 2121 ++∆=∆( ) 2/llcosxMDVertical 21 +∆=∆

Radius Of Curvature Method

( ) ( )( ) ( )1212

1221

AAxllAsinAsinxlcoslcosxMD

North−−

−−∆=∆

( ) ( )( ) ( )2212

2111

AAxll

AcosAcosxlcoslcosxMDEast

−−−−∆

=∆

Minimum Curvature Method ( ) ( ) RFxAcosxlsinAcosxlsinx2/MDNorth 2211 +∆=∆

( ) ( ) RFxAsinxlsinAsinxlsinx2/MDEast 2211 +∆=∆

( ) ( ) RFxlcoslcosx2/MDVertical 21 +∆=∆

( )2/DLtanxDL/2RF =

( ) ( ) ( )[ ]aAcos1xsinxlsinllcosDLcos −−−−=

Fi

gure 12.H - Survey Calculation Methods

A1

I1

S

EW

N

A2

I2

EW

N

I1

A1

I2

A2

S

S

EW

N

DLI1

A1

DL 2

DL 2

I2

A2

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12.4.4. Drilling Directional Wells

Kicking Off The Well

Jetting is the term used to describe the deviation of a well using bit hydraulics to erode theformation in a particular direction. A special jetting bit may be used or a conventional triconebit run with two undersized and one oversized (or blanked) jet nozzles. Usually the bit is runon a typical build up assembly (bit, full gauge near bit stabiliser, orienting sub, non-magneticand steel-drill collars as required) and once on bottom the blind nozzle, representing the‘tool face’, is oriented in the desired direction. Maximum circulation is then established andthe washing action begun. Some of string weight is slackened on the bit and the weightindicator will give an indication of drilling off if the formation is soft enough to be washedout.

In formations where the degree of compaction makes jetting ineffective, deviation is startedwith a downhole motor. This has become the most commonly adopted method of kick off.

With downhole motors, bent and orienting subs (or combined bent/orienting sub) arerequired. With the deflection assembly in the hole, there is a correction to apply to thedesired tool face setting or proposal direction. This correction is due to the reactive torquedeveloped by downhole motors. Reactive torque is dependent on motor power, weight onbit, formation, hole inclination and drilling assembly design and length. The actual value ofreactive torque must be assessed as drilling proceeds as it is unique to the conditionsprevailing.

During the kick off, the advantages and/or disadvantages of the different methods oforientation are highlighted. With single shot orientation, reactive torque can only beestimated based on the experience of the Directional Driller in the area of operation. Sincethe survey tool is at least one joint above the bit, the first assessment of actual reactivetorque can be made only after the second joint has been drilled.

Steering tools provide the most accurate measurement of tool face position. A continuousread-out on surface enables adjustment of the weight on bit/rate of penetration in order tomaintain a constant tool face. MWD tools provide the same information with the advantageof not require a wireline and the consequent rigging up and trip time. On the other hand,steering tools provide extremely high data rates that may be of critical importance whendrilling with very high rates of penetration.

Build Up Section

After the desired direction has been reached, the kick off assembly may be replaced with arotary build up assembly. However, if jetting has been the method of initial control, drillingcan continue with the same BHA in the rotary mode without requiring a trip. Selection of theappropriate build up assembly is dependent upon the angle achieved during initial kick offand maximum angle required.

The decision of when and if to replace the kick off assembly depends on several factorssuch as hole size, weight on bit and rate of penetration, response of the kick off assembly,residual bit life and final planned inclination. Controlling the BUR is imperative if fatigue todrill pipe and drill collars is to be avoided.

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This can be accomplished by varying the drilling parameters (weight on bit, rotary speedand pump pressure) or changing the BHA. In this case careful assessment must be made toconsider whether the amount of time lost in tripping out of hole to change the assembly,would be gained later with a better rate of penetration or by preventing difficulties.

The alternative is to accept the current performance and make adjustments at the next bittrip.

Tangent Section (Hold On Section)

When the desired inclination has been reached, the kick off or build up assembly isreplaced with a stiff bottom hole assembly that will maintain the inclination and direction.Small variation in behaviour of a BHA can be obtained by adjusting the weight on bit androtary speed.

Providing it is necessary, the earlier a correction to inclination or direction can be made thebetter it is. As the bit get closer to the target, longer corrections are required to get the wellback on the target. Advanced planning should be continuously done during operations toensure that, should a trip become necessary at short notice, any change to the BHA may bemade at the same time.

Drop Off Section

Drilling a directional well it may be necessary to allow the drift angle to straighten back tovertical or near vertical.

Drop off assemblies should be used starting with the least successful. The reason beingthat the higher the inclination, the greater the pendulum effect and the same rate of dropmight be achieved with the least successful assembly at 50° and the most successfulassembly at 30°. Therefore, as the inclination is reduced, stronger dropping tendencyassemblies may be run to maintain the rate of drop required.

Only where the maximum negative side force is required, at low inclinations and in hardformations, should pendulum assemblies be run (i.e. assemblies without a near bit).

Care Of Stabilisers

The bottom 120 (40m) of a drilling assembly is the critical portion for controlling a directionalwell. The stabilisers used in this area should be full gauge to 1/16" under unless undergaugestabilisers are required to hold or drop angle.

Stabilisers shall be gauged each trip: undersized tools should be moved up higher in drillcollar assembly or replaced with full gauge tools.

All stabilisers shall be magnafluxed at the end of each well phase.

As a general rule, do not drill out casing shoe with a ‘packed hole assembly’. However, thedecision whether or not to use stabilisers to drill casing shoe shall be evaluated case bycase.

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Figure 12.I - Build up Assembles

Drill Collars

Near Bit Stabilizer

Bit

String Stabilizer

60' Drill Collars

30' Drill Collars

Near Bit Stabilizer

String Stabilizer String Stabilizer

Bit

BitBit

Near Bit Stabilizer Near Bit Stabilizer

30' Non Mag.Drill Collar

30' Drill Collar


String Stabilizer String Stabilizer

String Stabilizers


String StabilizerString Stabilizers

10' Drill Collar

Near Bit Stabilizer

Bit Bit Bit

Near Bit Stabilizers Near Bit Stabilizers



String Stabilizers

10' Drill Collar 10' Drill Collar

MaximumAngle Building

Assemblies

MaximumAngle Building

Assemblies

PackedHole

Assemblies

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Figure 12.J - Bottom Hole Assembly Response

Bottom Hole Assembly Response

Assembly Response Relative *responsestenght

Bit Near bit stabilizer (Approx.3-5' from bit face to leadingedge of stabilizer)

14 Hold 1 - 3

15a Drop 10

13 Hold 5 - 8

12 8

11 Hold 9

10 Hold 10

9 Hold 1

8 Build (drops under 3 - 2

7 Build 4 - 2

6 Build 5 - 3

5 Build 7 - 5

4 Build 7 - 3

3 Build 7

2 Build 8

17 Drop & Build

1 Build 10

15b Drop 10

16 Drop 5 - 10 **

18 drop (at highter incl.) and/or

19 Drop or Build (highly

90'

60' 30'

60'

30' 30'

30'

30' 30'

30'

30' 30' 30'

30' 30'

30'

30'

30' 30' 30'

30'

30'

30'

15'

15'

15'

15'

5-10'

45'

45'

45'

60 - 70'

60 - 70'

certain circumstances)

Hold

Build (at lower incl.)

dependent on collar OD)

* 10 is the highest and 1 is the lowest

** (smaller holes con be better than 15)

= Undergauge

No.

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Figure 12.K - Common Holding Assembly

Figure 12.L - Drop Off Assembly

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12.4.5. Dog Leg Severity

Changes in hole curvature are often referred to as dog-legs

The severity of a dog-leg is determined by the average changes in angle and/or directioncalculated on the distance this change occurs. For example, if there is a 3° change in angle(no direction change) over 100ft of hole, the dog-leg severity is 3° per 100ft.

Until a dog-leg reaches some threshold value, no drill stem fatigue damage occurs. Thisthreshold value is called Critical Dog-leg. The critical dog-leg is dependent upon thedimension (size) and metallurgy of the drill pipe and drill pipe tension (pull) in the dog-leg.

The planning of directional wells should include a ‘Dog-leg control programme’. Critical dogleg limits should also considered for drill collars.

Dog-leg limits are established to prevent drill pipe fatigue, but when those limits aremaintained, there is also a reduction in associated hole problems. Excessive dog-legscause key seats, casing wear, rotating torque, trip drag, etc. Overall drilling rate can begreatly improved by a carefully planned and executed dog-leg control programme

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13. DRILLING PROBLEM PREVENTION MEASURES

It is necessary to for drilling engineers to anticipate potential drilling problems which mayoccur during a well programme in order that he can make suitable arrangements in theplanning and preparation stage of a project. Anticipation of problems may result in havingsuitable equipment and stocks of materials available on site or in the warehouse, ultimatelyleading to a saving in rig time and cost. Descriptions of some of the problems are givenbelow with possible causes, preventative measures or solutions.

Refer to the ‘Drilling Procedures Manual’

13.1. STUCK PIPE

The following is a list of the different types of pipe sticking which can occur due to:

• Differential sticking.• Hole restriction.• Caved in hole.• Hole irregularities and/or change in BHA.

It is impossible to lay down hard rules which will successfully cover all the case, however,for each situation, indications about the possible causes of the problem, preventivemeasures and remedial actions are listed in the following subsections.

Detailed procedures should be based on each particular case, evaluating every aspect ofthe problem and applying any past experience gained in the area concerned.

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13.1.1. Differential Sticking

Causes

This phenomenon can occur, where there is case of high differential pressure between themud hydrostatic pressure and the formation pore pressure. Some indications of pipebecoming differentially stuck may be:

• The string becomes stuck in front of a porous formation.• Pipe has not been moved for a period of time before getting stuck i.e. during a

pipe connection.• Circulation is free with no pressure variation.• A normal amount of cuttings is observed at the shaker.

Preventive Measures

When conditions for a potential differential sticking are encountered, the risk can beminimised by applying the following procedure:

a) Reduce the mud weight as much as possible, maintaining the minimum differentialpressure necessary for a safe trip margin.

b) Reduce the contact surface by using spiral type drill collars also called NWS( No WallStick) and using properly a stabilised bottom hole assembly. A shorter BHA with agreater number of HWDPs could be considered.

c) Use mud with minimum solids content and low filtrate in order to obtain a thinner wallcake.

d) Reduce the friction factor by adding lubricants to the mud.

e) Keep the pipe moving and in rotate as much as possible.

f) Consider the use of a drilling jar/bumper.

Methods of Freeing Pipe

1) Work the pipe applying cyclic slack-off and overpull combined with torque Alwayscheck the reduction in the pipe yield stress due to the application of the torque.

2) Spot oil-base mud or oil containing a surfactant around the drill collars.

3) Reduce the mud weight, if possible.

4) Use a drilling jar/bumper.

5) Conduct a DST procedure.

Note: Quick reactions are fundamental in freeing the wall of stuck drill pipe,since the problem becomes worse through time.

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13.1.2. Sticking Due To Hole Restrictions

Causes

The most common causes of hole restriction:

• Too thick a wall cake due to the use of high solids/high filtrate mud acrossporous and permeable formations.

• Swelling of formations containing clay.• Extrusion of gumbo shale into the wellbore in underbalance situations.

Preventive Measures

Problems are usually suspected by incurring increase drag during connections. Once thecause is recognised to be any of the three causes previously listed above, the followingactions should be undertaken:

a) Reduce mud filtrate, cake and solids content.

b) Use inhibited mud.

c) Increase mud weight.

d) Increase mud clearing capacity.

e) Increase flow rate.

In all situations, frequent wiper trips can reduce the problem and provide information on theseverity.


1) Work the pipe applying slack-off if the string has become stuck pulling out, andoverpull if it stuck while running in.

2) Spot a cushion to break and remove the mud cake around the drill collars.

3) Increase the mud weight, if possible.


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13.1.3. Sticking Due To Caving Hole

Causes

This problem is mainly experienced in shale sections. The most common causes are:

• Hydration and swelling of clay minerals when in contact with fresh mud filtrate.• Insufficient supporting action of the mud hydrostatic column.• Mechanical action of the drill string.

Preventive Measures

Depending on the various causes, there are different prevention possibilities, to reduce theseverity of the problem and to avoid the consequences of sticking the string.

Possible mud changes are:

a) Reduce water losses.

b) Lower pH value to 8.5 to 9 (if needed).

c) Use inhibited mud.

d) Add mud stabilising compounds (mainly sodium asphalt sulphonate).

e) Increase the mud weight.

f) Increase the YP/PV ratio to create laminar flow on the wall after pipe.

g) Increase the gel value to obtain a good cutting suspension when circulation isstopped.

Note: It is not always drilling with underbalance which results in a caving hole.

Possible BHA changes are:

a) Use bits without nozzles, particularly when reaming, to avoid scouring the well.

b) Use the minimum acceptable number of stabilisers.

Possible changes in parameters are:

a) Reduce rotary speed, if possible, to 80rpm or less.

b) Reduce the mud flow rate to obtain laminar flow in the annulus between hole and drillcollars.

c) Avoid long circulation times across unstable sections.

d) Do not rotate pipe when tripping. Use a spinner or chain out.

e) Trip out with care to avoid swabbing. If any swabbing occurs, pull out with the kelly on.

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1) If circulation is possible, keep circulating trying to expel the caving.

2) If the string becomes stuck across a carbonate formation, spot an acid pill.

3) If circulation is blocked, try to regain it by applying pressure shocks and working thepipe at the same time. Special care is required to avoid breaking the formation i.e.overcoming fracture gradient below the stuck point.


Note: The problem of pipe sticking due to cuttings dropping out is notnecessarily related to a caving hole. The origin of such problems can alsobe an excessive rate of penetration in large holes and inadequate carryingcapacity of the mud. In this case, change the mud properties and flow rateand, if necessary, limit the rate of penetration.

It is good practice to spot high viscosity pills from time to time to keep the hole clean.

The methods of getting pipe free in this situation are the same as listed above.

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13.1.4. Sticking Due To Hole Irregularities And/Or Change In BHA

Causes

The causes for sticking, related to, hole conditions and change in BHA, are:

• Dog legs.• Key seats.• New bit is run following a dulled bit which was undersize.• New stabilisers run to replace previous worn stabilisers..• String is stiffer than the previous one..• Rock bit run after a diamond or a core bit.

Preventive Measures

a) The formation of dog legs can be prevented by the use of packed bottom holeassemblies.

b) Dog legs can be eliminated by using very stiff BHA's and reamers.

c) A key seat can be eliminated by reaming it with a key seat wiper or an undergaugestabiliser installed on the top of the drill collars.

d) Always ream a whole interval drilled with the previous bit.

e) Ream always the cored section, even if a full gauge core bit was used.


1) Work the pipe applying slack-off if dog leg or key seat (the string becomes stuckpulling out) and overpull if running a new BHA (the string becomes stuck while runningin the hole).

2) Spot on oil-based mud or oil containing a surfactant around the stuck point.

3) If the stuck point is in a calcareous section, spot an acid pill.

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13.2. OIL PILLS

Depending on the specific gravity of the mud in the hole, two different types of oil pill can beused to help free pipe.

13.2.1. Light Oil Pills

To be used for mud specific gravity up to 1,350g/l (11.3 PPG).

The standard pill will be obtained adding 10 to 30l/m3 of surfactant to oil (diesel oil, crude oilor used engine oil).

The procedure for the use of pill is the following:

1) The pill volume shall be at least twice the volume of DC-open hole annulus (take intoaccount excess for compensating hole enlargement).

2) Pump at the maximum practical rate.

3) Displace in order to have a pill volume in the annulus 1.3 times the volume of the DC-open hole.

4) At 30 to 60mins intervals, circulate out of the string batches as a balanced plug.

5) Work the string at the same time.

6) Repeat the procedure if the pill does not succeed (the pill may be active for 4 to 16hours).

13.2.2. Heavy Oil Pills

To be used for mud of a specific gravity greater than 1,350g/l (11.3 PPG).

For pill preparation clean a mud pit and mix (the ratios among the various componentsvaries depending on the required density):

• Fresh water• Calcium chloride• Diesel oil (maximum 200l/minute)• Emulsifier (maximum 1 sack/minute) to be added at the same time as the diesel• Viscosifier (heavy stirring for at least 15 mins is required)• Barite.

While mixing, continuous agitation is compulsory .

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The procedure for the use of the pill will be the following:

1) The pill volume will be at least twice the volume between the drill collars and the openhole (take into account excess for compensating hole enlargement).

2) Pump a cushion of diesel oil with 5% Free Pipe, or similar, ahead and behind of pill.

3) Pump at the maximum practical rate.

4) Displace in order to have a pill volume in the annulus 1.3 times the volume of DC-open hole.

5) At 2 to 3hr intervals, circulate out of the string batches of 300 to 600ltrs.

6) Work the string at the same time.

7) Repeat the procedure if the pill results ineffective (the pill may be active for 20 to48hrs).

Note: When the oil pill is circulated out of the hole it shall be recovered andstored separately.

Note: Take into account the influence of the pill on the hydrostatic pressure.

13.2.3. Acid Pills

The use of acid pills can be successful if the string gets stuck across of a carbonateformation. Considering the risks related to this operation, this should be carried out only ifother methods prove to be ineffective.

a) Decisions concerning pill's characteristics (volume, compositions, strength,displacement schedule, etc.) shall be taken, on a case by case situation, afterconsultation with the Company Drilling Office.

b) Whichever recipe is adopted, consideration has to be given to the corrosion problem.The proper amount of corrosion inhibitor shall be used and the acid pill will be spacedwith oil or water ahead and behind.

c) Due to the acid reaction, gaseous products develop in the well and special care isrequired when circulating out the pill. It may be necessary to circulate through on thechoke and line up the surface equipment to safely dispose of the gas.

d) While displacing the acid in front of the formation, the gaseous product will cool offthe drill string. To avoid breaking, do not work the string but only apply an overpull orslack off.

e) As a result of the acid action, the permeability of the formation will increase, thuscreating the conditions for possible mud losses.

Whenever acid is handled, the appropriate safety measures shall be adopted:

• Wear gloves and protective clothing and have eyes protected with goggles.Ensure there are safety showers available for any personnel who come intocontact with acid.

• Have water sprays ready to wash spilled acid.• Ensure proper ventilation if the pill is mixed in a closed area.

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13.3. FREE POINT LOCATION

If it is confirmed that it is not possible to free the string by working the pipe and spotting oilor acid pills, the string shall be backed-off in order to allow proceeding with a differentmethod, such as running jars or wash pipes, or abandon the hole and side-track.

There are two methods for estimating the depth at which a string is stuck:

• Applying tension and measuring the pipe stretch.• Locating the tow point with a free-point indicating tool.

13.3.1. Measuring The Pipe Stretch

A reasonable estimate of the depth at which the pipe is stuck can be obtained bycalculation using Hooke's Law. Applying two different tensile loads (T1 < T2) to the drilling

string, two magnitudes of stretch (S1 < S2) are measured.

Calculating: the differential stretch (E = S2 - S1), differential pull (P = T2 - T1) and applyingHooke’s Law, it is possible to determine the depth of free point (L) using the followingformula.

SI UNITS API UNITS

P

ExWdpx374.26L =

where:

L = Length of free pipe in m

Wdp = Plain end pipe weight in kg/m

E = Differential stretch in mm

P = Differential pull in kN

P

ExWdpx294,735L =

where:

L = Length of free pipe in ft

Wdp = Plain end pipe weight in lbs/ft

E = Differential stretch in ins

P = Differential pull in lbs

The value obtained is less reliable as deviation increases due to down hole friction.

Another minor inaccuracy is introduced by neglecting the changing cross section of thestring at the tool joints.

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13.3.2. Location By Free Point Indicating Tool

A Free Point survey shall be run to select the back-off point.

Free Point Indicators are essentially accurate strain gauges which measure molecularrearrangement between drag springs, setting dogs or electromagnets.

The tool is run on a logging cable through which measurements of torque and stretch aresent to surface read-out instruments.

The Free Point Indicator is lowered to various depths and, at each depth, tension andtorque are applied to the string at the surface. The strain gauge indicates whether the pipereacts at that depth to the applied tension and applied torque.

The read-out of the instrument is given in percentage i.e. 100% represents entirely freepipe.

Pipe which appears to be free in tension does not always react to applied torque. There is agreater chance of succeeding with the back-off if the pipe is free under both tension andtorque.

Separate slim acoustic logs are designed to indicate intervals of stuck, partially stuck or freepipe, which may exist below the upper stuck point.

Interpretation of free point data is very subjective and susceptible to operator skill, holecondition, etc.

13.3.3. Back-Off Procedure

Drill pipe or drill collars can be unscrewed downhole by exploding a charge inside aselected tool joint connection, close to the stuck point.

Requisites for a successful back-off are the following:

• There must be sufficient minimum inside diameter.• The charge must be accurately placed across the connection• There must be sufficient string shot strength.• Neutral or slightly positive tension is applied at the back-off point.• Sufficient left hand torque must be applied at the back off point.

As a general rule, the first attempt to back-off should be made at the first connection abovethe free point. If there is a failure, the second attempt should be performed on the first standabove the free point. Subsequent attempts should be made moving upward one stand at atime.

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13.4. FISHING

13.4.1. Inventory Of Fishing Tools

The following tools shall be always available on the rig for the various hole sizes drilled:

• Fishing jars to match the drill collars in use.• Bumper subs to match the drill collars in use.• Overshot and oversize guides with grapples, baskets and extension subs, to

catch all diameters of tools in hole.• Taper taps for drill pipe body and tool joints.• Junk baskets or Globe-type baskets.• Reverse circulation junk baskets.• Junk subs.• Fishing magnets.• Milling tools.• Re-dressing tools for 5" and 31/2" sheared DP.• Impression blocks.• Fishing tools to catch electrical log tools (supplied by electrical log contractor)

and relevant crossover.• Safety joints.

13.4.2. Preparation

Before fishing operations the following preparations shall be carried out:

1) Apply the greatest accuracy to all measurements.

2) Draw a complete sketch of the equipment to be run, specifying lengths, inside andoutside diameters and a description of each tool.

3) Make sure that the Contractor's personnel directly involved in operations is fullyacquainted and familiar with equipment to be used and its limitations.

4) The fishing equipment should arrive to the rig fully inspected. Further inspection andmaintenance shall be carried out on the rig if in prolonged use.

5) Keep mud properties in good conditions at all times.

6) Keep rig the equipment in good working conditions at all times.

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13.4.3. Fishing Assembly

The standard fishing assembly consists of the following:

• Fishing tool + Jar and Bumper Sub + Drill Collars + Heavy Weight Drill Pipe +Drill Pipe.

• Use as many drill collars as is in the fish. If the required number of drill collars isnot available on the rig, use a jar accelerator.

• A Safety Joint should not be run. Since the Safety Joint will not transmit lefthand torque, it would not be possible to back-off below it using a string shot.

• However, a Safety Joint could be run between the catching tool and the jarwhen a non releasing tool such as taper tap is being employed.

• Avoid any restrictions in the bore of tools, run above the catching tool, whichwould prevent the use of a cutting tool or the back-off shot within the fish.

• Where losses are expected the use of a Circulation Sub in the fishing assemblyshould be considered.

13.5. FISHING PROCEDURES

13.5.1. Overshot

Plan the operation taking into account the following factors:

• The catching action of the tool will stress the fish neck in words.• A regular, smooth shape of the fish neck is necessary for a successful

operation.• Jarring is only possible only using type SFS, FS and XFS overshots.• If the fish diameter is near the maximum catch or size, a spiral grapple is

recommended. On the other hand, if the fish diameter is considerably below themaximum catch size, a basket grapple is preferable.

• If the hole is enlarged, use an oversize guide or run a bent drill pipe just abovethe overshot.

• When the fish has been milled over, if possible, run an overshot extension toavoid catching the fish by the milled part.

13.5.2. Releasing Spear

Plan this operation taking into account the following factors:

• The fish will be stressed outwards due to the catching action of the tool.• A regular, smooth shape of the fish is essential for a successful operation.• To allow unlatching of the spear, if it is not possible to run an adequate number

of drill collars above the releasing spear, the use of a bumper sub isrecommended.

• Install a pack-off on the tool, if circulation is required after latching the fish.• Use the fishing jar If jarring is required. In this case the use of a spear stop is

required. Check the Spear Stop OD when it is used in open hole and use thestop only if hole condition permits.

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13.5.3. Taper Taps

Plan this operation taking into account the following factors:

• The size of the taper tool should be selected in order to engage the fish with themiddle of the tapered point.

• The taper taps do not allow free passage to the back-off tool.• Excessive torque can damage the tapered thread and swell the top of the fish.• It is nigh impossible to release the tool once engaged. For this reason its use

has to be considered the last resort and only used after consultation with theEni-Agip Shore Base (Drilling Manager/Superintendent).

13.5.4. Junk basket

This procedure is more successful in soft formations.

A reverse circulation type junk basket is preferred to a forward circulation type.

Plan the operation to use the following parameters:

• WOB = 2 to 4t• Rotary = 45rpms• Low Pump Rate (1/2 pump rate while drilling).

13.5.5. Fishing Magnet

Magnets can be successfully used but only in hard formations to retrieve small steel objectssuch as bit cones, bearings, slips, tong pins and milling cuttings.

To avoid sticking the fish in the hole, weight must not be applied.

Fishing magnets may be run on wireline or on pipe. Wireline operations have the advantageof speed and economy. Pipe operations has the great advantage of utilising the circulationholes in the magnet to remove settling above the fish.

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13.6. MILLING PROCEDURE

There is a wide variety of mills specifically designed for various applications. Mills areavailable in two basic categories: ‘hydraulically activated mills’ and ‘fixed milling tools’.

A Section Mill is a hydraulically actuated tool and is used to mill out a complete section ofcasing. Downhole section milling of casing, is generally done for the following reasons:

• To mill a section of casing that permits side-tracking in any direction.• To mill the perforated zone in a production casing string or to expose cased off

formations. The formations may be then underreamed and gravel packed pastthe original completion.

The most commonly used Fixed Mills are:

Junk Mills Used to mill all type of junk, including rock bit cones,reamers cutters, items dropped through the rotary, drillpipe cemented inside and outside, etc.

Pilot Mills Designed to mill drill pipe, casing, tubing, wash pipe,safety joint, swaged casing, etc.

Taper Mills Generally used to eliminate restrictions or to mill throughcollapsed casing.

Washover Shoes Designed to mill away formation or tool obstructionssuch as stabiliser blades, reamer cutters, expandedpackers and bit bodies which may be holding the drill ortubing string in the hole

Special Mills (Window mills,Watermelon mills, etc.)

For casing side-tracking systems.

The following are general guidelines for the use of milling tools:

a) Milled cuttings are much heavier than drilling cuttings. Therefore, mud viscosity shouldbe increased or high viscosity pills should be pumped to help in carrying the steelcuttings out of the hole.

b) Oil based mud has poor carrying capabilities and should be avoided wheneverpossible. Polymer muds are most suitable for milling.

c) Never mill faster than it is possible to remove the cuttings.

d) Magnets placed in the flow line will help in removing metal particles from drilling mud.Removal of mill cuttings and debris reduces the wear on mud pumps and otherequipment.

e) A junk sub placed in the string above the mill can aid in catching the larger cuttings.

f) Whenever possible, a stabiliser should be run within 60 or 90ft (20-30m) above themill to prevent it from moving eccentrically.

g) The stabiliser OD should not exceed the dressed OD of the mill.

h) Always start rotating, with low rpm about 3ft (1m) above the fish. Lower onto the fishand adjust the weight and the rotary speed to obtain satisfactory penetration.

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a) Generally the most efficient milling rates are obtained by running the rotary at 80 to100rpm. Milling with washover shoes is an exception and are usually more efficient atspeeds of 60 to 80rpm. Continuously monitor the torque indicator during millingoperations.

b) ‘Reading the cuttings’ is essential to evaluate the performance of the mill. The idealcuttings are usually 1/32" to 1/16" thick and 1" to 2" long. If cuttings are thin longstringers, penetration rates are probably too low and weight on the mill should beincreased. If fish-scale type cuttings are being returned, penetration rate will improveby decreasing weight and increasing rpm.

c) The type and stability of the fish (cemented or not) together with the hardness of thefish and/or cement are factors that affect milling rates.

13.7. JARRING PROCEDURE

a) Jarring should be done with a Kelly or Top Drive. If the use of a Kelly is not possible,secure the elevator latch by using a piece of rope or chain.

b) Prior to jarring check the drill line sensor. Ensure the weight indicator readings areaccurate and that the dead line anchor is secure and free of debris. Check the derrickand all equipment for any loose items.

c) When jarring, the drill floor must be cleared of all non -essential personnel.

d) Prior to jarring, mark the drill string at the rotary table.

e) Check the drill line usage, slip and cut if necessary. When sustained jarring is carriedout, the drill line should be slipped at regular intervals, depending on the particularsituation. Also check the derrick, lifting equipment and travelling block attachmentbolts.

f) Always allow the jars to trip within their safe working load. Wait until the jars havetripped before pulling the string further. Never exceed the safe working limit withoutconfirmation that the jars have tripped.

g) If a top drive system is used, after jarring, check the TDS as per the maintenance andoperating specification.

Note: For details on jarring procedures, refer to ‘Drilling Jar Acceptance AndUtilisation Procedures’.

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Depth From Surface in feet

Pipe OD ins 0 to 3,000 3,000 to6,000

6,000 to9,000

9,000 to12,000

Over12,000

23/8 1 1 1 2 2

2 7/8 1 1 2 2 3

Tubing 31/2 1 1 2 2 2

4 to 41/2 2 2 2 3 3

23/8 to 7/8 1 2 2-3 3-4 4-6

31/2 to 4 2 3 3-4 4-6 5-8

Drillpipe 41/2 to 69/16 2 3-4 4-6 5-9 6-12

65/8 3 4-5 5-7 6-10 7-14

31/2 to 4 2-4 2-5 3-7 3-8 4-9

41/8 to 51/5 2-4 3-6 4-8 4-10 5-12

Drill Collar 53/4 to 7 3-6 4-8 5-10 6-12 7-15

71/4 to 81/2 4-6 5-9 6-12 7-15 8-18

71/4 to 93/4 6-12 8-12 8-15 8-18

41/2 to 51/2 3 3 3 3 3

6 to 7 3 3 3 4 4

Casing 75/8 4 4 4 4 5

75/8 5 5 5 5 5

95/8 5 5 5 6 6

103/4 6 6 6 7 7

Table 13.A - Recommended Strands of 80 Gr/ft RDX Primacord for String-Shot

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14. WELL ABANDONMENT

14.1. TEMPORARY ABANDONMENT

14.1.1. During Drilling Operations

Any well drilled which is to be temporarily abandoned shall be cemented with drilling/killweight mud below. Where there is an open hole below the deepest string of casing acement plug shall be placed in such manner that extends at least 50m above and below thecasing shoe.

The top of the cement plug shall be located and verified by mechanical loading.

If the condition of the formation makes cementing difficult, a bridge plug may be positionedin the lower part of the casing, but not more than 50m above the shoe and a cement plug atleast 20m long shall be placed on top of the mechanical plug.

Then, a cement plug shall be set at least 50 - 100m in length into the casing, depending oncasing diameter, between 20 - 50m below ground level or the seabed. The top of thecement plug shall be located and verified by mechanical loading.

14.1.2. During Production Operations

1) Plugging programme before a production well test:

Open Hole

In the part of borehole where casing has not been installed and where permeablezones containing liquid or gas have been found, cement plugs shall be placed in sucha way as to prevent liquid or gas from cross flowing into other zones. For eachindividual zone the cement plug shall be positioned such that its upper and lower endsare located at least 50m above and below the zone respectively.

The top of each cement plug shall be located and verified by mechanical loading.

Deepest Casing Shoe

Where there is an open hole below the deepest string of casing, a cement plug shallbe placed in such a manner that it extends at least 50m above and below the casingshoe.

The top of the cement plug shall be located and verified by mechanical loading.

If the condition of the formation makes cementing difficult, a mechanical plug may bepositioned in the lower part of the casing, but not more than 50m above the shoe anda cement plug at least 20m long shall be placed on top of the mechanical plug.

These plugs shall be verified by mechanical loading or pressure tested for sufficienttime and with enough differential pressure to detect a possible leak.

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2) Plugging programme after a production test:

Uninteresting perforated zones

These intervals shall be isolated by means of a mechanical plug and shall be squeezecemented. If the condition of the formation makes cementing difficult a cement plug50m high will be set on top of the mechanical plug.

If this is not possible, a cement plug shall be placed in such a way that the upper andlower ends of the plug are located at least 50m above and below the perforated zonerespectively, or down to the nearest plug if the distance is less than 50m. All the plugsshall be described, as seen in the previous subsection.

Interesting perforated zones

These intervals shall be isolated by means of a mechanical plug.

Then, a cement plug shall be set at least 50 - 100m in length into the casing,depending on casing diameter, between 5 - 50m below the sea bottom. The top of thecement plug shall be located and verified by mechanical loading.

14.2. PERMANENT ABANDONMENT

14.2.1. Plugging

A well has to be plugged so as to effectively seal-off all potential hydrocarbon bearingzones from fresh water bearing formations and to protect any zones which may containother minerals.

14.2.2. Plugging Programme

Open Hole

All permeable zones in an open hole shall be plugged so that formation fluid is preventedfrom flowing from one zone to another.

Plug(s) shall be set so that the top and the bottom is at least 50m above and below thezone(s). Each plug has to be tested.

Deepest Casing Shoe

At the top of the open hole a cement plug shall be set so that the upper and lower ends ofthe plug are located at least 50m above and below the casing shoe. The plug shall betested by mechanical loading.

Perforated Casing Zones

Each zone tested through casing perforations shall be squeeze-cemented as soon as thetest is finished, should the well be abandoned. A cement retainer will be set 10-15m abovethe perforated zone (avoid setting it on a casing collar) and an injection test shall beperformed using fresh water and recording the pressure/flow rate ratios.

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The cement slurry volume will be calculated in order to have the cement from bottomperforation to the cement retainer and a minimum of 100ltrs slurry per metre of perforatedzone into the formation. At the end of the squeeze, a 50m cement plug shall be set abovethe cement retainer. The length of this plug may be reduced to avoid any interference withupper intervals to be tested or produced.

Liner Top

At the hanging point of the liner, a cement plug shall be set so that the top and bottom ofthe plug is at least 50m above and below the hanging point.

Intermediate Casing Shoe

In case any of the intermediate casings is not cemented up to at least 100m inside theprevious casing shoe, the casing shall be cut at least 100m above the shoe of the previouscasing string, the casing recovered, and a cement plug shall be placed so that it extends atleast 50 - 100m above and below the casing cut point.

Surface plug

A surface plug (at least 150m long) shall be set so that the top of the plug be 50m or lessbelow ground level or seabed.

After setting the surface plug, each surface casing and conductor pipe shall be cut at least5m below sea bed, using mechanical cutters.

14.2.3. Plugging Procedure

1) Cement plugs, set when abandoning wells, should be formed from neat slurrieswhenever possible. If static bottom hole temperature exceeds 110°C use special nondegradable cements (i.e. Geotherm).

2) Spacers should be pumped ahead and behind slurry.

Special consideration should be given to the composition and volume of the spacerswhen the mud is oil based, calcium chloride or lignosulphonate treated.

The hydrostatic head reduction due to the spacer volume and density should becalculated. The spacers should have a volume corresponding to a length of at least328ft (100m).

3) The slurry volume should be calculated using a calliper log, if available. When acalliper log is not available, use a slurry volume excess based on local experience.Plugs exceeding 200m in length should not be set in one stage.

4) If the hole is badly washed out or when potential losses are expected; it is preferableto set two short plugs instead of one long one.

5) All cement plugs shall be placed using a tubing stinger.

6) Displacement should be calculated in order to spot a balanced cement plug(hydrostatic heads inside the string and outside in the annulus shall be the same).

7) An under displacement of 1 or 2bbl is suggested to help draining the slurry off thepipe when pulling out of hole.

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8) As soon as the plug is set, pull out slowly 30 - 50m above the theoretical top of theplug and direct circulate (reverse circulation can also be considered if conditions allowit).

9) Monitor and record spacer and slurry returns.

10) Never stab the stinger back into the plug to avoid plugging of the stinger.

11) The position and efficiency of all cement plugs shall be verified by locating the top ofthe plug and by applying bit weight on the plug after cement setting, usually 20,000-40,000lbs, but dependent on hole size) .

12) Record shall be kept of all plugs set and the results of tests shall be available forinspection.

14.3. CASING CUTTING/RETRIEVING

Consideration can be given, if deemed economically profitable, to cut and retrieve sectionsof uncemented 7" and 95/8" casing.

Mechanical cutters are used for this operation.

After cutting the casing, a complete circulation shall be made to reduce friction and balancethe mud.

If the casing is cut and recovered leaving a stub, one of the following methods shall be usedto plug the casing stub:

14.3.1. Stub Termination (Inside a Casing String)

A stub inside a casing string shall be plugged by:

• A cement plug is set so as to extend 50m above and 50m below the stub,• A permanent bridge plug set 10-15m above the stub and capped with at least

20m of cement.

14.3.2. Stub Termination (Below a Casing String)

If the stub is below the next larger string, plugging shall be accomplished in accordance withthe previous section.

The plug shall be mechanically tested.

After setting a surface plug, each surface casing and conductor pipe shall be cut at least5m below sea bed using mechanical cutters.

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15. WELL NAME/DESIGNATION

The original name will be set by the geology or exploration department. There are threecategories of well which need to be coded.:

1) Wells With The Same Well Head And The Same Target

2) Wells With The Same Well Head Different Targets

3) Wells With Different Well Heads And The Same Target

15.1. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND TARGET

15.1.1. Vertical Well

Is defined as having the same well head and target co-ordinates as defined in the wellprogramme.

The well code will be:

Prospect/Field name: Amelia

Well Number: 1

Therefore the name/number is:

Illustration Line 1) Amelia 1

15.1.2. Side Track In A Vertical Well.

The term Side Track will only be used when there is amechanical Side Track due to operational problems. If a newhole is drilled due to a operational problem maintaining thesame target co-ordinates, this does not alter the well name.To permit the identification of the various side-tracks each isgiven a number. 1 is the original hole, 2 is the first side-track,3 the second, etc. This is shown in the figure and in thefollowing example:

Illustration Line 1) Field name: Amelia 1

Illustration Line 2) 1st Side Track: Amelia 1 (hole No. 2)

Illustration Line 3) 2nd Side Track: Amelia 1 (hole No. 3)

1

1

23

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15.1.3. Directional Well

Is defined directional as a well where the target co-ordinates are different from the wellhead co-ordinates. (see Figure). The well code will be

Field name: Amelia

Well number : 1

Code: DIR

So the final well code will be:

Illustration Line 1) Amelia 1 DIR

15.1.4. Side Track In Directional Well

This is considered the same condition as for a vertical well:

Illustration Line 1) Original Well name/number: Amelia 1 DIR

Line 2) Side Track: Amelia 1 DIR (hole n. 2)

15.1.5. Horizontal Well

Is defined as a well that has a final hole path with ainclination of 90°.

The name will be:

Field name: Amelia

Well number: 1

Extension: OR

Therefore the final well code will be:

Illustration Line 1) Amelia 1 OR

Note: The pilot hole into the reservoir willalso be deemed part of the horizontal well.

15.1.6. Side Track In A Horizontal Well

This is considered the same condition as for a vertical well:

Original well name/number Amelia 1 OR

Illustration Line 2) Side Track: Amelia 1 OR (hole n.2)

1

1

1

1

2

2

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15.2. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND DIFFERENTTARGETS

In this category are wells with:

The original well head co-ordinates with more than one hole and different target co-ordinates.

Each new hole will be given a new code as will the operations necessary to prepare for theside-track (cement plug, casing window operation, etc.).

The name of the first hole will have the original code (AMELIA 1), the following holes will beadded to the original code with one of the following two additions:

The first one indicates the well type:

• DIR, directional well• OR, horizontal well• APPR, deepened well

The second one indicates the targets new co-ordinates:

• A, second target• B, third target

Example #1

Illustration Line 1) Original well (vertical) Amelia 1

Illustration Line 2) Directional hole: Amelia 1 DIR (A)

Illustration Line 3) Horizontal hole: Amelia 1 OR (B)

Example #2

Illustration Line 1) Original Directional Well: Amelia DIR

Illustration Line 2) Directional Well with the second target:Amelia 1 DIR (A)

1

1

2

2

3

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Example #3

Illustration Line 1) Original Directional Well: Amelia 1 DIR

Illustration Line 2) Vertical well with a second target:

Amelia 1 (A)

Example #4

Illustration Line 1) Original Vertical Well: Amelia 1

Illustration Line 2) Horizontal hole with a second target:

Amelia 1 OR (A)

Illustration Line 3) Horizontal hole with a third target:

Amelia 1 OR (B)

Example #5

Illustration Line 1) Original Directional Well: Amelia 1 DIR

Illustration Line 2) Directional hole with a second new target:Amelia 1 DIR (A)

Illustration Line 3) Horizontal well with a third target:

Amelia 1 OR (B)

Example #6

Illustration Line 1) Original Vertical Well: Amelia 1

Illustration Line 2) Directional hole with a second target:

Amelia 1 DIR (A)

Illustration Line 3) Deepened well with a third target:

Amelia 1 APPR (B)

Illustration Line 4) Deepened well with a fourth new target:Amelia 1 DIR APPR (C)

1

1

1

2

2

2

1

3

2

3

3

4

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15.3. WELLS WITH DIFFERENT WELL HEAD CO-ORDINATES AND SAME ORIGINALTARGETS

In this category are the wells where the target co-ordinates remain the same while thewellhead location has been moved. This condition can only occur where there has been adrilling problem in the well.

There are two different cases:

Case 1

When there is one or more strings of casing set, it can be considered that every hole is asingle well, so the name of the wells after the first will be the original well plus the code todefine the well type (DIR OR) with the added code BIS for the second well, TRIS for thethird well, etc.

Example #1

Illustration Line 1) Original vertical well: Amelia 1

Illustration Line 2) Second well: Amelia 1 BIS

Illustration Line 3) Third well: Amelia 1 TRIS

Case 2 (no casing set)

When no casing string has been set, it can be considered that every hole is part of a singlewell. The code for the following holes is the original well plus (1) for the first hole, (2) for thesecond hole, etc.

Example #2:

Illustration Line 1) Original well: Amelia 1

Illustration Line 2) Second hole: Amelia 1 (2°)

Illustration Line 3) Third hole: Amelia 1 (3°)

Illustration Line 4) Fourth hole: Amelia 1 (4°)

Illustration Line 5) Fifth hole: Amelia 1 (5°)

Illustration Line 6) Sixth hole: Amelia 1 (6°)

12

3

12

3

4

5

6

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15.4. FURTHER CODING

Further codes may be added to give additional information about a well with regard to itslocation in a field or if it is a marine well, i.e.

Location Code Example Field Description

Marine, Mare M Belaym 113 M 35 Belaym 113 Mare 35

North, Nord N Beniboye N 5-2 Beniboye North 5-2

South, Sud S Imbondeiro S 1 Imbondeiro South 1

East, Est E Samabri E 1 Samabri East 1

West, Ovest W Belaym M N W 2 Belaym Mare North West 2

When the well code/name is written out in full the full code name must be placed in front ofthe field name.

Example :

a) North Darag 1

b) Est Makerouga 2

c) South pass 75-2

d) West Butte 9-34-13-20

Listed in the following table 15.a are the definitions and the parameters to identify other wellcharacteristics.

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DEFINITION PARAMETER

Inclinationda a

ROC(m)

BUR(°/m) (°/30 m)

HorizontalSection (m)

SHORT RADIUS x° 90° 5.8÷ 30.1 9.8 ÷ 1.9294 ÷ 57

150 ÷ 250

INTERMEDIATE RADIUS x° 90° 43.1 ÷ 12.79 1.33 ÷ 4.4840 ÷ 70

150 ÷ 250

MINIMUM RADIUS x° 90° 86.8 ÷ 220.4 0.66 ÷ 0.2620 ÷ 8

500 ÷ 900

LONG RADIUS x° 90° 286 ÷ 573 0.2 ÷ 0.13 ÷ 6

1000 ÷1600

DEFINITION PARAMETERCurve

CharacteristicDisplacement

(m)ROC(m)

BUR(°/m) (°/30 m)

DRAIN HOLE ShortRadius

150 ÷ 250 5.8 ÷ 30.1 9.8 ÷ 1.9294 ÷ 57

EXTENDED REACH WELL LongRadius

1000÷1600 286 ÷ 573 0.2 ÷ 0.13 ÷ 6

LATERAL WELL All the Horizontal wells

MULTI LATERAL WELL As showed in chapter 2 example 5

RE-ENTRY WELL Well re-entered to put in production, by drilling operations, a oldsuspended well. See example in chapter 2

BRANCH WELL Più drain hole con partenza da un unico extended reach

DEFINITION PARAMETER

Depth(m)

Pore Pressurebar/10m

SIWHPressure (bar)

Temp Res.O/WH (°C)

WaterDepth (m)

DEEP WELL > 4600 --- --- --- ---

ULTRA DEEP WELL > 6000 --- --- --- ---

DEEPWATER WELL --- --- --- --- 460

HIGH PRESSURE WELL --- > 1.81 > 690 --- ---

HIGH TEMPERATURE WELL --- --- --- > 150°c ---

Title Description

WATER WELL Producing water well

WATER INJECTION WELL Well for water injection

GAS INJECTION WELL Well for gas injection

Table 15.A - Well Definitions and Characteristics

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16. GEOLOGICAL DRILLING WELL PROGRAMME

The Geological and Drilling Well Programme (Refer to STAP-P-2-N-6001E) is a‘controlled’ live document (i.e. univocally identifying and fulfilling the requirements of Eni-Agip Division and Affiliate’s Quality Management System) according to a standard formatproviding information on a specific well and avoiding duplication of data.

16.1. PROGRAMME FORMAT

The Geological and Drilling Well Programme, from now on defined as ‘‘G&DWP’’,comprises four sections:

Section 1 - General Information

Section 2 - Geological Programme

Section 3 - Operation Geology Programme

Section 4 - Drilling Programme.

The ‘G&DWP’ will also be standardised with regard to the following:

• Print model• Type and size of character• Page numbering• Identification• Distribution list• Graphic representations• Structure of the sections.

16.2. IDENTIFICATION

All main sections in the ‘G&DWP’, must be identified by the Name/Designation of the Well.

The name of the well must be shown on all the pages of the document along with theacronym of the Project Unit and the District/Affiliates.

16.3. GRAPHIC REPRESENTATIONS

In order to allow section of the ‘G&DWP’ to be easily accessible whether by E-Mail orthrough shared network disks, the graphic representations shall be in electronic format,using Eni-Agip Division and Affiliate’s standard ‘Windows’ tools Power Point, FreelanceGraphics, Excel, etc.

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The sketches and drawings which are not reproducible with this software, must be scannedin and the files saved in the formats of the filters in ‘Word’ (.PCX, .BMP; etc.).The version ofword may be updated from time to time and, hence, the filters also altered to suit. The sizeof the files produced must be rationalised and kept as small as possible to reduce thedocument memory size hence make easier management.

Prints produced with software different from Eni-Agip Division & Affiliates standard such as:prints and diagrams produced by means of ADIS, geological maps and seismic sections,figures taken from catalogues and publications will be produced on a blank page andapplied a page number for consistency.

The number of these particular types of representations should be minimised to prevent theformat being different from A4, different fonts and colours. If unavoidable these must beincluded as Annexes.

16.4. CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME

The structure of the ‘G&DWP’ and its relevant competencies are detailed in the followingsub-sections.

The list of contents for each section and the section numbering must be strictly followed.

If some subjects are not applicable, the term ‘not envisaged’ will be placed against theserelevant sections or subsections.

Additional subsections to provide clarity or further explanation of a formal content subjectare permitted.

16.4.1. General Information (Section 1)

This section contains the main data of the well project and a synthesis of the main subjectswhich are explained in detail.

This section must be proposed in conjunction with the Drilling & Completion and GeologyDepartments of the particular District/Affiliates.

All depths of the well, both for offshore and onshore wells, must be referenced to theRotary Table (RT).

Section 1 comprises the sub-sections numbered and titled as follows:

1.1 GENERAL WELL DATA

1.2 WELL TARGET

1.3 GENERAL RECOMMENDATIONS

1.4 GENERAL CHARACTERISTICS OF THE RIG, BOP STACK ANDSAFETY EQUIPMENT

1.5 LIST OF THE MAIN CONTRACTORS

1.6 CONTACTS IN CASE OF EMERGENCY

1.7 REFERENCE MANUALS

1.8 MEASUREMENT UNITS

An explanation of each of these is given in the following sub-sections.

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Authorisation

The names and signatures of the technicians and managers involved in the preparation andcontrol of the section will always be specified.

General Well Data (Section 1.1)

This section lists the main data regarding the well project.

This section will be prepared by the District Geology Department following input by thecompetent Project Department and will contain the information presented in table 16.a.

The Local Drilling & Completion Department will provide the Well Profile, the Time VersusDepth Diagram, and the Location Layout. The District Geology Department will provide thescheme Forecast and Acquisition Programmes.

Well Target (Section 1.2)

This section will be prepared by the Local Geology Department and summarises what isdescribed in sub-section 2.3 of section 2 (e. g. verification of the ‘up-dip’ potential of thestructure, and development of ‘probable’ undrained reserves, etc.).

General Recommendations (Section 1.3)

This section will be prepared with close co-operation between the Drilling & Completion andGeology Local Departments, highlighting the possible operational problems envisaged andwhich will be described in detail in the following sections (Geological Programme, OperationGeology Programme and Drilling Programme).

General Characteristics of the RIG, BOP Stack and Safety Equipment (Section 1.4)

This section is prepared by the Local Drilling & Completion Department and will contain theinformation listed in table 16.b and table 16.c

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ITEM DESCRIPTION

IDENTIFIABLE WELL DATA

Affilate 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 (onshore wells)

Province (onshore wells)

Harbour-master office (offshore wells)

Zone (off-shore wells)

Distance Rig/coast (offshore wells)

Distance Rig/operative base

Altitude (onshore wells)

Sea Depth (offshore wells)

WELL TARGET IDENTIFICATION

Reference seismic line

Lithology of the main target

Formation of the main target

Depth of the main target

TOPOGRAPHIC REFERENCES

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

Table 16.A - General Well Data

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Item Description

Contractor

Rig name

Rig type

Rotary table elevation at ground level Only onshore rigs

Rotary table elevation at sea level Only offshore rigs

Number of slots available Only offshore rigs

Power installed

Drawwork type

Rig potential with 5” DP’s

Max. operative water depth Only offshore rigs

Clearance height rotary beams/ground level Only onshore rigs

Top Drive System type

Swivel assembly working pressure If without Top Drive System

Dynamic hook load

Set back capacity

Deck load Only for semi-submersible rigs

Total load Only for semi-submersible 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 storage capacity Only for offshore rigs

Industrial water storage capacity

Gas oil storage capacity

Barite storage capacity

Bentonite storage capacity

Cement storage capacity

Table 16.B -General Rig Data

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Item Description

Diverter type

Diverter size

Diverter working pressure

BOP stack type

BOP size

BOP working pressure

Choke manifold size and working 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 16.C - Equipment Data

List of the Main Contractors (Section 1.5)

The section will be prepared by the Local Drilling & Completion Department in co-operationwith the Local Sub-surface Geology Department and must contain the services required andthe name of the provider.

The following Table is presented as an example:

SERVICE COMPANY

Rig

Mud

Water/mud disposal

Cementing

Mud logging

Electrical logging

LWD

Drilling tools

Coring

Directional drilling

Drilling equipment

Tubing and casing tong

Testing

Table 16.D - List of the Main Contractors

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Contacts in case of emergency (Section 1.6)

This section will be prepared by the Local Drilling & Completion Department and shows:

• A ‘flow chart’ of emergency contacts• The telephone numbers of the relevant people in charge of the emergency.

Reference Manuals (Section 1.7)

Reference Manuals will be written by the Local Drilling & Completion Department. Itconsists in a list of basic manuals to be referred for planning and implementation phases ofthe well.

Measurement Units(Section 1.8)

The section ‘Measurement Units’ will be written in strict co-operation between the Drilling &Completion and Sub-surface Geology Local Departments. It will contain a list of the units ofmeasurement for the main parameters used in the Geological Operation and Drillingsections.

These are:

Depth: m

Pressures: kg/cm²

Pressure gradients : kg/cm²/10m or atm/10m

Specific gravity : kg/l or kg/dm³

Lengths: m

Weights: t

Oil volumes Sm3

Volumes: m³

Bit and casing diameters: ins

Tubular goods weight lbs/ft

Working pressure : psi

Gas volume Sm3

Salinity ppm of NaCl

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16.4.2. Geological Programme (Section 2)

The Geological Programme will be written by the Department in charge of the project in co-operation with the Local Sub-surface Geology Department.

All the reference depths will be from:

• Ground level for ONSHORE wells• Sea level for OFFSHORE wells

Section 2 comprises the sub-section headings listed below, numbered and titled as follows:

List of contents

2.1 GEOLOGICAL FRAMEWORK

2.2 SEISMIC INTERPRETATION

2.3 WELL TARGETS

2.4 SOURCE ROCKS

2.5 SEALING ROCKS

2.6 LITHOSTRATIGRAPHIC PROFILE

2.7 REFERENCE WELLS

Annexes and/or figures

Authorisation

The names and signatures of the technicians and managers involved in the preparation andcontrol of the section will be always specified.

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16.4.3. Operation Geology Programme (Section 3)

The ‘Operation Geology Programme’ will be prepared by the Local Sub-surface GeologyDepartment.

Section 3 will comprise the sub-sections numbered and titled as follows:

List of contents

3.1 SURFACE LOGGING

3.2 SAMPLINGS

3.2.1 Cuttings

3.2.2 Bottom Hole Cores

3.2.3 Side Wall Cores

3.2.4 Fluids Sampling

3.3 LOGGING WHILE DRILLING

3.4 WIRELINE LOGGING

3.5 SEISMIC SURVEY

3.6 WIRELINE TESTING

3.7 TESTING

3.8 STUDIES AND DRAWINGS

3.9 REFERENCE WELLS

Authorisation

The names and signatures of the technicians and managers involved in thepreparation and control of the section will be always specified.

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16.4.4. Drilling Programme (Section 4)

The ‘Drilling Programme’ will be prepared by the District Drilling & Completion Department.The Drilling Programme structure is defined in procedure STAP-P-1-N-6001E. Particularly,paragraphs 4.2.1 (forecast on pressure and temperature gradients) and 4.2.2 (drillingproblems) will be made in co-operation between the Drilling and Completion and Sub-surface Geology Local Departments. Section 4 will comprise the sub-sections numberedand titled as follows:

List of contents

4.1 OPERATIONAL SEQUENCE

4.1.1 Preliminaries

4.1.2 Conductor pipe phase

4.1.3 Superficial phase

4.1.4 Intermediate phases

4.1.5 Final phase

4.1.6 Testing

4.1.7 Completion typology

4.1.8 Well abandonment

4.2 WELL PLANNING

4.2.1 Forecast on pressure and temperature gradients

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 BHA and stabilisation

4.2.11 Bits and drilling parameters

4.2.12 Deviation project

Annexes and/or figures

Authorisation

The names and signatures of the technicians and managers involved in thepreparation and control of the section will be always specified.

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17. FINAL WELL REPORT

This section details the procedure to prepare the ‘Final Well Report’.

Properly completed Final Well Reports are essential to enable all personnel involved indrilling and completion activities access to well information for studies, analysis or to helpprepare future well programmes.

17.1. GENERAL

Whenever possible or applicable, the well final report shall include reports on both Drillingand Completion activities. In the case of new wells the report will be titled ‘ Final WellDrilling and Completion Report’ or, in case of workover on old wells, as ‘ Final WorkoverWell Drilling and Completion Report’.

Where only Drilling operations are concerned (e.g. Exploration Wells, Dry Holes, TemporaryAbandonment, etc.), the report will be titled ‘Final Well Drilling Report’.

If completion operations are performed separately after the end of drilling operations arecompleted (e.g. Temporary Abandoning or Batch Operations) the report will be titled ‘FinalWell Completion Report’. When separate drilling and completion reports are prepared, thetwo reports will be merged.

In the case of a multi-well Development Project where, wells are drilled or completed from asingle location (platform or cluster) the report will be titled ‘ (platform name) or (clustername) Final Drilling and Completion Report’.

In the following section the structure and competency required in the preparation of the‘Final Well Report shall be explained. Reporting will be standardised through using thecommon format as follows:

• Print Model• Type and Size of the Character• Page Numbering• Identification• Distribution List• Graphic Representations• Chapters Structure• Signatures

These criteria shall be common for all Well Operations ‘Final Well Reports’ in both domesticand foreign operations.

17.2. FINAL WELL REPORT PREPARATION

The Final Well Report is prepared by the ‘Engineering Section’ of the Drilling andCompletion Department’ in co-operation with the ‘Operations Section’.

The numeration and the title of the sections as shown in section 17.3, must be strictlyfollowed. Extra sub-sections for clarity or further explanation are permitted.

If some subjects are applicable to a particular well, not envisaged will be typed against therelevant sections.

ARPO




17.3. FINAL WELL OPERATION REPORT STRUCTURE17.3.1. General Report Structure

1 GENERAL INFORMATION

1.1 GENERAL WELL DATA

1.2 GENERAL RIG SPECIFICATION

1.3 BOP SKETCH

1.4 LIST OF MAIN CONTRACTORS

1.5 OPERATIONS ORGANISATION CHART

1.6 LOCATION MAP

2 WELL HISTORY

2.1 FINAL WELL STATUS

2.1.1 Well Sketch

2.1.2 Well Head Sketch

2.1.3 Well Completion Sketch

2.2 DETAILED OPERATIONS HISTORY

2.2.1 Moving

2.2.2 Conductor Pipe Phase

2.2.3 Surface Phase

2.2.4 Intermediate Phases

2.2.5 Final Phase

2.2.6 Well Testing

2.2.7 Completion

2.2.8 Abandoning

2.3 DRILLING PROBLEMS AND RECOMMENDATIONS

2.4 COMPLETION REMARKS

3 DATA ANALYSIS

3.1 Pressure And Temperature Gradients

3.2 Casing Data

3.3 Cementing Data

3.4 Drilling Fluids

3.5 Bit And Hydraulic Data

3.6 Bottom Hole Assembly

3.7 Directional Drilling

3.8 Well Testing Data

3.9 Completion Details

3.10 Time Analysis

4 ATTACHMENTS

(Service companies must be requested to supply copies of their own reports as thisenhances the quality of the information contained in the report).

ARPO




17.3.2. Cluster/Platform Final Well Report Structure1 CLUSTER/PLATFORM INFORMATION

1.1 GENERAL DATA

1.2 GENERAL RIG SPECIFICATION

1.3 BOP SKETCH

1.4 LIST OF MAIN CONTRACTORS

1.5 OPERATIONS ORGANIZATION CHART

1.6 LOCATION MAP

1.7 CLUSTER/PLATFORM WELL BAY LAY-OUT AND ORIENTATION

2 GENERAL DRILLING & COMPLETION ACTIVITY REPORT

2.1 FINAL WELLS STATUS

2.1.1 Well Sketches

2.1.2 Wells Head Sketches And Elevations

2.1.3 Completion Schemes

2.1.4 General Cluster/Platform Time Vs Depth Diagram

2.2 DETAILED OPERATIONS HISTORY

2.2.1 Moving

2.2.2 Conductor Pipe Phase

2.2.3 Surface Phase

2.2.4 Intermediate Phases

2.2.5 Final Phase

2.2.6 Testing

2.2.7 Completion

2.2.8 Abandoning

2.3 PRESSURE AND TEMPERATURE GRADIENTS

2.4 DRILLING PROBLEMS AND RECOMMENDATIONS

2.5 COMPLETION REMARKS

3 DATA ANALYSIS

3.2 CASING DATA

3.3 CEMENTING DATA

3.4 DRILLING FLUIDS

3.5 BIT AND HYDRAULIC DATA

3.6 BOTTOM HOLE ASSEMBLY

3.7 DIRECTIONAL DRILLING

3.8 WELL TESTING DATA

3.9 COMPLETION DETAILS

3.10 TIME ANALYSIS

4 ATTACHMENTS

(Service companies must be requested to supply copies of their own reports as thisenhances the quality of the information contained in the report).

ARPO




General Information (Section 1)

In this sub-section the main data relevant to the Well, Rig and Operation Organisationshould be reported.

All depths for both offshore and onshore wells must be referred to from Rotary Table (RT),the elevation of which above datum shall be clearly stated.

General Drilling and Completion Activity Report (Section 2)

In this section the history of the well e.g. final well status, detailed operation history,operation problems register and recommendations for Drilling and Completion activities etc.,will be reported.

Data Analysis (Section 3)

In this part, data relevant to drilling and completion operations will be reported in detail.

17.4. AUTHORISATION

Authorisation for the ‘ Final Well Report’ will be included as follows according to theprocedures envisaged in paragraph 6.5 of STAP-G-1-M-9000:

Prepared by : District Drilling and Completion Expert

Controlled by: District Engineering and operation sections Manager of Drilling andCompletion department

Approved by : District Drilling and Completion Manager

17.5. ATTACHMENTS

Included In this section there are all paragraphs required for particular purposes, such as:

• Spider plot• Cost analysis• Evaluation of service main contractor• Weather condition• etc.

ARPO




Appendix A - Report Forms

To enable the contents of this drilling design manual and other operating proceduresmanuals to be improved, it is essential that ENI - Agip Division and Affiliates obtain feed-back from the field. To this end a feed-back reporting system is in use which satisfies thisrequirement.

Feed-back reports for drilling, completion, workover and well testing operations areavailable and must be filled in and returned to head office for distribution to the relevantresponsible departments as soon as possible as per instructions.

The forms relevant to drilling operations are:

• ARPO 01 Initial Activity Report

• ARPO 02 Daily Report

• ARPO 03A Casing Running Report

• ARPO 03B Casing Running Report

• ARPO 04A Cementing Job report

• ARPO 04B Cementing Job report

• ARPO 05 Bit Record

• ARPO 06 Waste Disposal Management Report

• ARPO 13 Well Problem Report

Behind each report form are instructions on how to fill in the forms. As the first section isgeneric to all the forms it is only shown in ARPO 01 instructions.

Note: If not otherwise specified , all depths referred to in this appendix will befrom Rotary Kelly Bushing Elevation (this being from the first Rig whichdrilled the well).

ARPO




A.1. Initial Activity Report (ARPO 01)

WELL NAME

FIELD NAME District/Affiliate Company

DATE: ARPO 01 Cost center

Permit/Concession N° Well Code

General Data Depth Above S.L . Joint venture

On shore Off shore Ground Level[m] AGIP: % %

Latitude: Water Depth [m] % %

Longitude Rotary Table Elev.[m] % %

Reference First Flange[m] Type of Operation

Rig Name Top housing [m]

Rig Type Reference Rig Program TD (Measured) [m]

Contractor Ref. Rig RKB - 1st Flange Program TD (Vertical) [m]

Rig Heading [°] Cellar Pit Rig Pump

Offset FROM the proposed location Depth [m] Manufacturer

Distance [m] Length [m] Type

Direction [°] Width [m]: Liner avaible [in]

Major Contractors

Type of Service Company Contract N° Type of Service Company Contract N°

Mud Logging

D. & C. Fluids

Cementation

Waste treatment

Operating Time Jack-up leg Penetration Supply Vessel for Positioning

Moving [gg:hh] Leg Air gap Penetration N° Name Horse Bollard pull

Positioning [hh:min] N° [m] [m] Power [t]

Anchorage [hh:min]

Rig-up [hh:min]

Delay [hh:min]

Lost-time Accidents [hh:min]

Rig Anchorage

Anchor Mooring Line Piggy Back Mooring Line Tension Operative Total

Bow Weight Length Weight Chain Cable [Tested] Tension Time

N° Angle Type & Manufacturer [t] Cable Chain N° [t] Length Ø Length Ø [t] [t] [hh:min]

[m] [m] [m] [mm] [m] [mm]

1

2

3

4

5

6

7

8

9

10

11

12

Note: Supervisor

Superintendent

INITIAL ACTIVITY REPORT

ARPO




A.2. Daily Report (ARPO 02)

WELL NAME

FIELD NAME District/Affiliate Company

DATE: ARPO 02 Cost center

Rig Name RT Elevation [m] Well Code

Type of Rig Ground Lelel / Water Depth [m] Report N° of

Contractor RT - 1st flange / Top Housing [m] Permit / Concession N°

Well Last casing Next Casing BOP Type Ø w.p. [psi] M.D. (24:00) [m]

Ø nom.[in] Stack T.V.D. (24:00) [m]

Top [m] Diverter Total Drilled [m]

Bottom [m] Annular Rotating Hrs [hh:mm]

Top of Cmt [m] Annular R.O.P. [m / h]

Last Survey [°] at m Upper Rams Progressive Rot. hrs [hh:mm]

LOT - IFT [kg/l] at m Middle Rams Back reaming Hrs [hh:mm]

Reduce Pump Strockes Pressure Middle Rams Personnel Injured

Pump N° 1 2 3 Middle Rams Agip Agip

Liner [in] Lower Rams Rig Rig

Strokes Last Test Others Other

Press. [psi] Total Total

Lithology

Shows

From (hr) To (hr) Op. Code OPERATION DESCRIPTION

Operation at 07:00

Mud type Bit N° Run N° N° Run N° Bottom Hole Assembly N° __________ Rot. hours

Density [kg/l] Data Description Ø Part. L Progr.L Partial Progr.

Viscosity [s/l] Manuf.

P.V. [cP] Type

Y.P. [g/100cm2] Serial No.

Gel 10"/10' / IADC

Water Loss [cc/30"] Diam.

HP/HT [cc/30"] Nozzle/TFA

Press. [kg/cm2] From [m]

Temp. [°C] To [m]

Cl- [g/l] Drilled [m]

Salt [g/l] Rot. Hrs. pH/ES R.P.M. MBT [kg/m3] W.O.B.[t]

Solid [%] Flow Rate Stock Quantity UM Supply vessel Oil/water Ratio. Pressure

Sand [%] Ann. vel.

pm/pom Jet vel. pf HHP Bit

mf HSI Total Cost Supervisor:

Daily Losses [m3] I O D L I O D L Daily Progr. Losses [m3] B G O R B G O R Progr.

DAILY REPORT Drilling

ARPO




A.3. Casing Running Report (ARPO 03)

Marco Vitari

disegno mancante

ARPO




A.4. Casing Running Report (ARPO 03B)

WELL NAME

FIELD NAMEDistrict/Affiliate Company

DATE: ARPO 03 / B Cost center

Operation type Casing type Ø [in] Top [m] Bottom [m]

Joint Length Progress. centr. Joint Length Progress. centr. Joint Length Progress. centr.

N° [m] [m] (N°) N° [m] [m] (N°) N° [m] [m] (N°)

Remarks:

Supervisor Superintendent

RUNNING CASING REPORT

ARPO




A.5. Cementing Job report (ARPO 04A)

Marco Vitari

disegnno mancante

ARPO




A.6. Cementing Job report (ARPO 04B)

WELL NAME


DATE: ARPO-04 / B Cost center

Operation type Ø [in] Stage / No.:

SQUEEZE / PLUG

Type Ø Length [m] Cap.[ l/m] Bottom [m] Cement retainer Manufacturer Model / Type Ø Depth

Squeeze packer [inch] [m]

Injectivity Test with: Pump Rate Testing Pr. Tot. Vol. Final Sqz Pr. Returns Vol

[l/min] [kg/cm2] pumped [l] [kg/cm2] [l]

Test [kg/cm2] [mins]

Stinger Pressure test

Annular pressure

CEMENTATION

Operation (y/n) [kg/cm2] [mins]

Casing Reciprocation Bump Plug Casing testing pressure

Casing Rotation Valve holding Annulus pressurization

Inner string

GENERAL DATA

Slurry Displacement To Surface Losses [m3]

With pumps Density pH Dumped During csg run

Fluid type: [kg/l] [m3] Circulation

Volume [m3] Mud Mix/Pump Slurry

Density: [kg/l] Spacer Displacement

Duration: [mins] Slurry Opening DV

Final pressure: [kg/cm2] Circ. through DV

Total

Circulation / Displacement / Squeeze

Time [mins.] Flow Rate Pressure Total Volume Operation Description Final Press. Returns

Partial Progr. [l/min] [kg/cm2] [l] [kg/cm2] Vol. [l]

Supervisor Superintendent

CEMENTING JOB REPORT

ARPO




A.7. Bit Record (ARPO 05)

WELL NAME


DATE: ARPO-05 Cost center

Run n°

Bit n°

Bit size [in]

Bit manufacturer

Bit type

Special features codes

Serial number

IADC code

Depth in [m]

Depth out [m]

Drilled interval [m]

Rotation hrs

Trip hrs

R.O.P. [m/h]

Average W.O.B. [t]

Average R.P.M.

D.H.M. R.P.M.

Flow rate [l/min]

St. pipe pressure [kg/cm2]

D.H.M. Press. drop [kg/cm2]

Bit HHP

HSI Annulus min vel. [m/min]

1 [1/32 in]

J 2 [1/32 in]

E 3 [1/32 in]

T 4 [1/32 in]

S 5 [1/32 in]

C [1/32 in]

T.F.A. [in2]B Inner rows [I]I Outher rows [O]T Dull char. [D]

Location [L]D Bearing/Seals [B]U Gauge 1/16 [G]L Other chars [O]L Reason POOH [R]

Mud type

Mud density [kg/l]

Mud visc.

Mud Y.P.

Survey depth

Survey incl.

Bit Cost

Li Type %

tho

lo

gy

Stabilizer Distance

B Diameter from bit

H [in] [m]

A

Currency Supervisor Superintendent

Pag.: of:

BIT RECORD

ARPO




A.8. Waste Disposal Management Report (ARPO 06)

WELL NAME


DATE: ARPO-06 Cost center

Report N° Depth (m) Mud Type

From [m] Interval Drilled (m) Density (kg/l)

To [m] Drilled Volume [m3] Cl- concentration (g/l )

Phase size [in] Cumulative volume [m3]

Water consumption Phase /Period [m3] Cumulative [m

3]

Usage Fresh water Recycled Total Fresh water Recycled Total

Mixing Mud

Others

Total

Readings / Truck Fresh water [m3] Recycled [m

3]

Mud Volume [m3] Phase Cumulative Service Company Contract N°

Mixed Mud Company

Lost Waste Disposal

Dumped Transportation

Transported IN Transported OUT

Waste Disposal Period Cumulative Remarks Water base cuttings[t]

Oil base cuttings [t]

Dried Water base cuttings [t]

Dried oil base cuttings [t]

Water base mud [t]

Oil base mud transported IN [t]

Oil base mud transported OUT [t]

Drill potable water [t]

Dehidrated water base mud [t]

Dehidrated oil base mud [t]

Sewage water [t]

Transported Brine [t]

Remarks

Supervisor

Superintendent

WASTE DISPOSALManagement Report

ARPO




A.9. Well Problem Report (ARPO 13)

FIELD NAME

WELL NAMEDistrict/Affiliate Company

DATE: ARPO -13 Cost center

Problem Top [m] Start date

Code Bottom [m] End date

Well Ø Measured Depth Vertical Depth KOP [m] Mud in hole

Situation Top [m] Bottom [m] Top [m] Bottom [m] Max inclination [°] Type

Open hole @ m Dens.[kg/l]:

Last casing DROP OFF [m]

Well problem Description

Solutions Applied: Results Obtained:




Supervisor Supervisor Supervisor

Remarks at District level:

Superintendent

Lost Time hh:mm Loss value [in currency]

Remarks at HQ level Pag.

Of

WELL PROBLEM REPORT

ARPO




Appendix B - ABBREVIATIONS

API American Petroleum InstituteBG Background gasBHA Bottom Hole AssemblyBHP Bottom Hole PressureBHT Bottom hole temperatureBOP Blow Out PreventerBPD Barrel Per DayBPM Barrels Per MinuteBPV Back Pressure ValveBUR Build Up RateBWOC By Weight Of CementBWOW By Weight Of WaterCBL Cement Bond LogCCD Centre to Centre DistanceCCL Casing Collar LocatorCDP Common Depth PointCET Cement Evaluation ToolCMT CementCP Conductor PipeCR Cement RetainerCRA Corrosion Resistant AlloyCW Current WellDC Drill CollarDHM Down Hole MotorDIF Drill-In FluidDLS Dog Leg SeverityDM / D&CM Drilling & Completion ManagerDOB Diesel Oil BentoniteDOBC Diesel Oil Bentonite CementDOR Drop Off RateDP Drill PipeDST Drill Stem TestDV DV CollarE/L Electric LineECD Equivalent Circulation DensityECP External Casing PackerEMS Electronic Multi ShotEMW Equivalent Mud WeightEOC End Of CurvatureESD Electric Shut-Down SystemFBHP Flowing Bottom Hole PressureFBHT Flowing Bottom Hole TemperatureFINS Ferranti International Navigation SystemFPI/BO Free Point Indicator / Back OffFTHP Flowing Tubing Head Pressure

ARPO




FTHT Flowing Tubing Head TemperatureGCT Guidance Continuous ToolGLS Guidelineless Landing StructureGMS Gyro Multi ShotGOC Gas Oil ContactGPM Gallon (US) per MinuteGR Gamma RayGSS Gyro Single ShotHAZOP Hazard and OperabilityHDT High Resolution DipmeterHO Hole OpenerHP/HT High Pressure - High TemperatureHW/HWDP Heavy Weight Drill PipeIADC International Drilling ContractorIBOP Inside Blow Out PreventerID Inside DiameterKMW Kill mud weightKOP Kick Off PointLAT Lowest Astronomical TideLCM Lost Circulation MaterialsLOT Leak Off TestLQC Log Quality ControlLTA Lost Time AccidentLWD Log While DrillingMAASP Max Allowable Annular Surface PressureMD Measured DepthMLH Mudline HangerMMS Magnetic Multi ShotMODU Mobile Offshore Drilling UnitMOP Margin of OverpullMSL Mean Sea LevelMSS Magnetic Single ShotMW Mud WeightMWD Measurement While DrillingNACE National Association of Corrosion EngineersNB Near Bit StabiliserNMDC Non Magnetic Drill CollarNSG North Seeking GyroNTU Nephelometric Turbidity UnitOBM Oil Base MudOD Outside DiameterOEDP Open End Drill PipeOIM Offshore Installation ManagerOMW Original Mud weightORP Origin Reference PointOWC Oil Water ContactP&A Plugged & Abandoned

ARPO




PCG Pipe Connection GasPDC Polycrystalline Diamond CutterPDM Positive Displacement MotorPGB Permanent Guide BasePI Productivity IndexPLT Production Logging ToolPOB Personnel On BoardPPB Pounds Per Barrelppm Part Per MillionPV Plastic ViscosityPVT Pressure Volume TemperatureRBP Retrievable Bridge PlugRJ Ring JointRKB Rotary Kelly BushingROE Radius of ExposureROP Rate Of PenetrationROU Radios Of UncertaintyROV Remote Operated VehicleRPM Revolutions Per MinuteRT Rotary TableS (HDT) High Resolution DipmeterS/N Serial NumberSBHP Static Bottom Hole PressureSBHT Static Bottom Hole TemperatureSCC Stress Corrosion CrackingSD Separation DistanceSDE Senior Drilling EngineerSF Safety FactorSG Specific GravitySICP Shut-in Casing PressureSIDPP Shut-in Drill Pipe PressureSIMOP Simultaneous OperationsSPM Stroke per MinuteSR Separation RatioSRG Surface Readout GyroSSC Sulphide Stress CrackingST Steering ToolSTG Short trip gasTCP Tubing Conveyed PerforationsTD Total DepthTFA Total Flow AreaTG Trip GasTGB Temporary Guide BaseTOC Top of CementTOL Top of LinerTVD True Vertical DepthTW Target Well

ARPO




UAR Uncertainty Area RatioUGF Universal Guide FrameUR Under ReamerVBR Variable Bore Rams (BOP)VDL Variable Density LogVSP Velocity Seismic ProfileW/L Wire LineWBM Water Base MudWC Water CutWL Water LossWOB Weight On BitWOC Wait On CementWOW Wait On WeatherWP Working PressureYP Yield Point

ARPO




Appendix C - WELL DEFINITIONS

Definitions and parameters to described wells characteristics.

ParameterDefinition Inclination

da aROC(m)

BUR(°/m) (°/30 m)

Horizontal Section(m)

Short Radius x° 90° 5.8 - 30.19.8 ÷ 1.9294 ÷ 57

150 - 250

Intermediate Radius x° 90° 43.1 -12.79

1.33 ÷ 4.4840 ÷ 70

150 - 250

Minimum Radius x° 90° 86.8 -220.4

0.66 ÷ 0.2620 ÷ 8

500 - 900

Long Radius x° 90° 286 - 5730.2 ÷ 0.1

3 ÷ 61000 -1600

ParameterDefinition Curve

CharacteristicDisplacement

(M)Roc(M)

Bur(°/M) (°/30 M)

Drain Hole ShortRadius

150 - 250 5.8 ÷ 30.19.8 - 1.9294 - 57

Extended Reach Well LongRadius

1000 - 1600 286 ÷ 5730.2 - 0.1

3 - 6Lateral Well All are Horizontal wellsMulti Lateral Well As shown in section 2 example #5Re-Entry Well A well re-entered to production, by drilling operations, in a previous

suspended well. See example in chapter 2Branch Well A drain hole drilled for extended reach

Parameter

Definition Depth(M)

PorePress.

Bar/10m

SIWHPress.(Bar)

TempRes.

O/WH(°C)

Water Depth (M)

Deep Well > 4,600 --- --- --- ---

Ultra Deep Well > 6,000 --- --- --- ---

Deepwater Well --- --- --- --- 460High Pressure Well --- > 1.81 > 690 --- ---

High Temperature Well --- --- --- > 150°c ---

ARPO




Word Description

Water Well Producing water wellWater Injection Well Well for water injectionGas Injection Well Well for gas injection

ARPO




Appendix D - BIBLIOGRAPHY

Eni-Agip Document: STAP Number

ADIS

Casing Design Manual

Drilling Fluids Manual

Drilling, Jar Acceptance and Utilisation Procedures

Drilling Procedures Manual

General Well Control Policy Manual

Other TEAP Number

Emergency Operating Procedures TEAP-P-1-M-6040

API Specifications 5c

API Specifications10

NACE Standard MR-01-75

eni - drilling design manual

Documents

casing design

casing wear

casing profiles

casing specification

conductor casing

surface casing

intermediate casing

production casing