英文版钻井设计手册ENI- Drilling Design Manual - 图文

ARPO ENI S.p.A. Agip Division TITLE ORGANISING TYPE OF ISSUING DOC. REFER TO PAGE. DEPARTMENT ACTIVITY' DEPT. TYPE SECTION N. OF1 230 STAP P 1 M 6100 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 a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue: 28/06/99 ??????????????Issued by ????????P. Magarini E. Monaci 28/06/99 REVISIONS The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for

reasons different from those owing to which it was given

????????C. Lanzetta 28/06/99 CHK'D ????????A. Galletta 28/06/99 APPR'D PREP'D

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 2 OF 230 REVISION 0 1.

INTRODUCTION

1.1. PURPOSE AND OBJECTIVES 1.2. IMPLEMENTATION

INDEX 9

9 9 9

1.3. UPDATING, AMENDMENT, CONTROL& DEROGATION

2.

PRESSURE EVALUATION

2.1. FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS 2.2. OVERPRESSURE EVALUATION

2.2.1. Methods Before Drilling 2.2.2. Methods While Drilling 2.2.3. Real Time Indicators

2.2.4. Indicators Depending on Lag Time 2.2.5. Methods After Drilling 2.3. TEMPERATURE PREDICTION

2.3.1. Temperature Gradients 2.3.2. Temperature Logging

10

10 11 12 12 13 14 16 19 20 20

3.

SELECTION OF CASING SEATS

3.1. CONDUCTOR CASING 3.2. SURFACE CASING 3.3. INTERMEDIATE CASING 3.4. DRILLING LINER 3.5. PRODUCTION CASING

21

24 24 24 25 25

4.

CASING DESIGN

4.1. INTRODUCTION

4.2. PROFILES AND DRILLING SCENARIOS

4.2.1. Casing Profiles

4.3. CASING SPECIFICATION AND CLASSIFICATION

4.3.1. Casing Specification

4.3.2. Classification Of API Casing 4.4. MECHANICAL PROPERTIES OF STEEL

4.4.1. General

4.4.2. Stress-Strain Diagram 4.5. NON-API CASING 4.6. CONNECTIONS

4.6.1. API Connections 4.7. APPROACH TO CASING DESIGN

4.7.1. Wellbore Forces 4.7.2. Design Factor (DF) 4.7.3. Design Factors

26

26 27 27 28 28 29 29 29 29 31 32 32 33 33 34 35

ARPO ENI S.p.A. Agip Division 4.7.4.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 3 OF 230 REVISION 0 Application of Design Factors

35 36 36 39 42 43 43 45 46 47 47 47 49 50 52 52 53 55 56 57 58 59 60 60 60 61 63 63 64 68 68 69 69 69 70 70 71

4.8. DESIGN CRITERIA

4.8.1. Burst 4.8.2. Collapse 4.8.3. Tension

4.9. BIAXIAL STRESS

4.9.1. Effects On Collapse Resistance 4.9.2. Company Design Procedure 4.9.3. Example Collapse Calculation 4.10. BENDING

4.10.1. General

4.10.2. Determination Of Bending Effect 4.10.3. Company Design Procedure 4.10.4. Example Bending Calculation 4.11. CASING WEAR

4.11.1. General

4.11.2. Volumetric Wear Rate 4.11.3. Wear Factors

4.11.4. Wear Allowance In Casing Design 4.11.5. Company Design Procedure 4.12. SALT SECTIONS

4.12.1. Company Design Procedure 4.13. CORROSION

4.13.1. Exploration And Appraisal Wells 4.13.2. Development Wells

4.13.3. Contributing Factors To Corrosion 4.13.4. Casing For Sour Service 4.13.5. Ordering Specifications

4.13.6. Company Design Procedure 4.14. TEMPERATURE EFFECTS

4.14.1. Low Temperature Service 4.15. LOAD CONDITIONS

4.15.1. Safe Allowable Pull

4.15.2. Cementing Considerations 4.15.3. Pressure Testing 4.15.4. Company Guidelines 4.15.5. Hang-Off Load (LH)

5.

MUD CONSIDERATIONS

5.1. GENERAL

5.2. DRILLING FLUID PROPERTIES

5.2.1. Cuttings Lifting

5.2.2. Subsurface Well Control 5.2.3. Lubrication

5.2.4. Bottom-Hole Cleaning 5.2.5. Formation Evaluation 5.2.6. Formation Protection 5.3. MUD COMPOSITION

5.3.1. Salt Muds

5.3.2. Water Based Systems 5.3.3. Gel Systems

5.3.4. Polymer Systems

72

72 72 72 73 74 74 74 74 75 75 78 79 79

ARPO ENI S.p.A. Agip Division 5.3.5. 5.4. SOLIDS

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 4 OF 230 REVISION 0 Oil Based Mud

80 80 81 81 84 85

5.5. DENSITY CONTROL MATERIALS 5.6. FLUID CALCULATIONS 5.7. MUD TESTING PROCEDURES 5.8. MINIMUM STOCK REQUIREMENTS

6.

FLUID HYDRAULICS

6.1. HYDRAULICS PROGRAMME PREPARATION 6.2. DESIGN OF THE HYDRAULICS PROGRAMME 6.3. FLOW RATE

6.4. PRESSURE LOSSES

6.4.1. Surface Equipment 6.4.2. Drill Pipe 6.4.3. Drill Collars 6.4.4. Bit Hydraulics 6.4.5. Mud Motors 6.4.6. Annulus 6.5. USEFUL TABLES AND CHARTS

87

87 88 88 90 93 93 93 93 94 94 95

7.

CEMENTING CONSIDERATIONS

7.1. CEMENT

7.1.1. API Specification

7.1.2. Slurry Density and Weight 7.2. CEMENT ADDITIVES

7.2.1. Accelerators 7.2.2. Retarders 7.2.3. Extenders

7.2.4. Weighting Agents 7.3. SALT CEMENT

7.4. SPACERS AND WASHES 7.5. SLURRY SELECTION 7.6. CEMENT PLACEMENT 7.7. WELL CONTROL

7.8. JOB DESIGN

7.8.1. Depth/Configuration 7.8.2. Environment 7.8.3. Temperature

7.8.4. Slurry Preparation

97

97 97 100 102 102 103 103 104 105 106 107 108 108 110 110 111 111 111

8.

WELLHEADS

8.1. DEFINITIONS

8.2. DESIGN CRITERIA

8.2.1. Material Specification

112

112 112 112

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 5 OF 230 REVISION 0 113 113 113 116 119

8.3. SURFACE WELLHEADS

8.3.1. Standard Wellhead Components 8.3.2. National/Breda Wellhead Systems 8.4. COMPACT WELLHEAD 8.5. MUDLINE SUSPENSION

9.

PRESSURE RATING OF BOP EQUIPMENT

9.1. BOP SELECTION CRITERIA

122

122

10. BHA DESIGN AND STABILISATION

10.1. STRAIGHT HOLE DRILLING

10.2. DOG-LEG AND KEY SEAT PROBLEMS

10.2.1. Drill Pipe Fatigue 10.2.2. Stuck Pipe 10.2.3. Logging

10.2.4. Running casing 10.2.5. Cementing

10.2.6. Casing Wear While Drilling 10.2.7. Production Problems 10.3. HOLE ANGLE CONTROL

10.3.1. Packed Hole Theory 10.3.2. Pendulum Theory

10.4. DESIGNING A PACKED HOLE ASSEMBLY

10.4.1. Length Of Tool Assembly 10.4.2. Stiffness 10.4.3. Clearance

10.4.4. Wall Support and Length of Contact Tool 10.5. PACKED BOTTOM HOLE ASSEMBLIES 10.6. PENDULUM BOTTOM HOLE ASSEMBLIES 10.7. REDUCED BIT WEIGHT 10.8. DRILL STRING DESIGN

10.9. BOTTOM HOLE ASSEMBLY BUCKLING

10.10.SUMMARY RECOMMENDATIONS FOR STABILISATION 10.11.OPERATING LIMITS OF DRILL PIPE 10.12.GENERAL GUIDELINES

125

125 125 125 126 126 126 126 126 126 128 128 129 129 129 129 131 131 131 133 134 135 138 140 142 142

11. BIT SELECTION

11.1. PLANNING

11.2. IADC ROLLER BIT CLASSIFICATION

11.2.1. Major Group Classification 11.2.2. Bit Cones 11.3. DIAMOND BIT CLASSIFICATION

11.3.1. Natural Diamond Bits 11.3.2. PDC Bits

11.3.3. IADC Fixed Cutter Classification

143

143 143 144 145 146 146 146 146

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 6 OF 230 REVISION 0 148 148 149 149 150 150 150 150 152

11.4. BIT SELECTION

11.4.1. Formation Hardness/Abrasiveness 11.4.2. Mud Types

11.4.3. Directional Control 11.4.4. Drilling Method 11.4.5. Coring 11.4.6. Bit Size 11.5. CRITICAL ROTARY SPEEDS 11.6. DRILLING OPTIMISATION

12. DIRECTIONAL DRILLING

12.1. TERMINOLOGY AND CONVENTIONS

12.2. CO-ORDINATE SYSTEMS

12.2.1. Universal Transverse Of Mercator (UTM) 12.2.2. Geographical Co-ordinates

12.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT

12.3.1. Horizontal Displacement 12.3.2. Target Direction 12.3.3. Convergence 12.4. HIGH SIDE OF THE HOLE AND TOOL FACE

12.4.1. Magnetic Surveys 12.4.2. Gyroscopic Surveys

12.4.3. Survey Calculation Methods 12.4.4. Drilling Directional Wells 12.4.5. Dog Leg Severity

153

153 155 155 156 158 158 159 159 160 161 163 165 167 172

13. DRILLING PROBLEM PREVENTION MEASURES

13.1. STUCK PIPE

13.1.1. Differential Sticking

13.1.2. Sticking Due To Hole Restrictions 13.1.3. Sticking Due To Caving Hole

13.1.4. Sticking Due To Hole Irregularities And/Or Change In BHA 13.2. OIL PILLS

13.2.1. Light Oil Pills 13.2.2. Heavy Oil Pills 13.2.3. Acid Pills

13.3. FREE POINT LOCATION

13.3.1. Measuring The Pipe Stretch

13.3.2. Location By Free Point Indicating Tool 13.3.3. Back-Off Procedure 13.4. FISHING

13.4.1. Inventory Of Fishing Tools 13.4.2. Preparation

13.4.3. Fishing Assembly 13.5. FISHING PROCEDURES

13.5.1. Overshot

13.5.2. Releasing Spear 13.5.3. Taper Taps 13.5.4. Junk basket 13.5.5. Fishing Magnet

173

173 174 175 176 178 179 179 179 180 181 181 182 182 183 183 183 184 184 184 184 185 185 185

ARPO ENI S.p.A. Agip Division 13.6. MILLING PROCEDURE 13.7. JARRING PROCEDURE

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 7 OF 230 REVISION 0 186 187

14. WELL ABANDONMENT

14.1. TEMPORARY ABANDONMENT

14.1.1. During Drilling Operations 14.1.2. During Production Operations 14.2. PERMANENT ABANDONMENT

14.2.1. Plugging

14.2.2. Plugging Programme 14.2.3. Plugging Procedure

14.3. CASING CUTTING/RETRIEVING

14.3.1. Stub Termination (Inside a Casing String) 14.3.2. Stub Termination (Below a Casing String)

189

189 189 189 190 190 190 191 192 192 192

15. WELL NAME/DESIGNATION

15.1. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND TARGET

15.1.1. Vertical Well

15.1.2. Side Track In A Vertical Well. 15.1.3. Directional Well

15.1.4. Side Track In Directional Well 15.1.5. Horizontal Well

15.1.6. Side Track In A Horizontal Well

193

193 193 193 194 194 194 194

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

16.1. PROGRAMME FORMAT 16.2. IDENTIFICATION

16.3. GRAPHIC REPRESENTATIONS

16.4. CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME

16.4.1. General Information (Section 1) 16.4.2. Geological Programme (Section 2)

16.4.3. Operation Geology Programme (Section 3) 16.4.4. Drilling Programme (Section 4)

200

200 200 200 201 201 207 208 209

17. FINAL WELL REPORT

17.1. GENERAL

17.2. FINAL WELL REPORT PREPARATION

17.3. FINAL WELL OPERATION REPORT STRUCTURE

17.3.1. General Report Structure

17.3.2. Cluster/Platform Final Well Report Structure 17.4. AUTHORISATION 17.5. ATTACHMENTS

210

210 210 211 211 212 213 213

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 8 OF 230 REVISION 0 APPENDIX A - REPORT FORMS

A.1. INITIAL ACTIVITY REPORT (ARPO 01) A.2. DAILY REPORT (ARPO 02)

A.3. CASING RUNNING REPORT (ARPO 03) A.4. CASING RUNNING REPORT (ARPO 03B) A.5. CEMENTING JOB REPORT (ARPO 04A) A.6. CEMENTING JOB REPORT (ARPO 04B) A.7. BIT RECORD (ARPO 05)

A.8. WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06) A.9. WELL PROBLEM REPORT (ARPO 13)

214

215 216 217 218 219 220 221 222 223

APPENDIX B - ABBREVIATIONS

APPENDIX C - WELL DEFINITIONS

APPENDIX D - BIBLIOGRAPHY 224 228 230

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 9 OF 230 REVISION 0 1.

1.1.

INTRODUCTION

PURPOSE AND OBJECTIVES

The purpose of the Drilling design Manual is to guide experienced technicians and

engineers involved in Eni-Agip?s in the production of well design/studies and in the planning of well operations world-wide, using the Manuals & Procedures and the Technical Specifications which are part of the Corporate Standards. This encompasses the

forecasting of pressure and temperature gradients through casing design to the compilation of the Geological Drilling Programme and Final Well Report.

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

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

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

1.2.

IMPLEMENTATION

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

All engineers engaged in Eni-Agip Division and Affiliates drilling design activities are

expected to make themselves familiar with the contents of this manual and be responsible for 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 and improved by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis.

Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the

District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing.

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

Feedback for manual amendment is also gained from the return of completed ?Feedback and Reporting Forms? from drilling, well testing and workover operations, refer to Appendix A.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 10 OF 230 REVISION 0 2.

2.1.

PRESSURE EVALUATION

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) b)

Method for calculating the Overburden Gradient, if obtained from electric logs of reference wells or from seismic analysis.

Method for defining the Pore Pressure Gradient, if obtained from data (RFT, DST, BHP gauges, production tests, electric logs, Sigma logs, D exponent) of reference wells or from seismic analysis. Formula used to derive the Fracture Gradient. Source used to obtain the Temperature Gradient.

c) d)

The formulas normally used to calculate the Overburden Gradient are:

??t???

PiP??1000 3.28?????H

??t??? 47

D?? 1.228

??t?? 200

D?????h 10 Gov??????Hi 10

=

Numbers of??second (calculated from sonic log for regularly depth

interval, i.e. every 50/100/200m) Transit time (second 10-3) Density of the formation Overburden gradient

Formation interval with the same density D Total depth (????H)

where:

PiP ??t D Gov ??H Hi

= = = = =

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 16 OF 230 REVISION 0 ? Cuttings from normal pressured shales are small with

rounded edges and are generally flat, while cuttings from an abnormal pressure are often long and splintered with angular edges. As the differential between the pore

pressure and the drilling fluid hydrostatic head is reduced, the pressured shales will burst into the wellbore rather than having being drilled. This change in shape, along with an increase in the amount of cuttings at the surface, could be an indication that abnormal pressure has been encountered.

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 the plotting of the shale resistivity values at relative depths on a semilog graphic (depth in decimal scale and resistivity in logarithmical scale).

In formations, if they are normal compacted, the resistivity of the shales increases with depth but, in overpressure zones, it lowers 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 bearing formations which have sufficient and a constant level of salinity.

For the calculation of gradient, refer to the ?Overpressure Evaluation Manual?.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 17 OF 230 REVISION 0 Fig.1,2-1 INDUCTION LOG

1

Resistivity (OHMM)

10

100

1500

??????? ??????? ??????????????????????????????????????????????????????? To ?????? ?????????????????????????????????????????? 2000

2500

3000

3500

4000

4500

5000

Figure .2.A - Induction Log

Shale Formation Factor This is more sophisticated than the IES method described

above. It eliminates the inconveniences due to water salinity (Fsh) Method:

variation. It consists in the plotting of the shale factors on a semilog graph (depth in decimal scale and resistivity in

logarithmical scale)at relative depths. The ?Fsh? is calculated by the following formula:

Rsh Fsh???Rw

Where: Rsht Rw

=The shale resistivity read on the log in the points where they are most cleaned

= The formation water resistivity reported in

?Schlumberger?s tables on the ?log interpretation chart?.

The value of Fsh, increases with depth in normal compaction zones and lowers in overpressure zones (Refer to figure 2.b). For the gradients calculation, the ?Overpressure Evaluation Manual?.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100

1

1500

F shale

10

0

100

PAGE 18 OF 230 REVISION 2000

2500

Depth (m) 3000

3500

4000

4500

5000

Figure 2.B - ‘F’ Shale

Sonic Log (SL) Method: Also termed ???t shale?, is the most widely used as, from

experience, it gives the most reliability. It consists in the plotting, on a semilog graph (depth in decimal scale and transit 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 shale points where they are cleanest;???t value lowers with the depth increase in normal compaction zones and increases with the depth in overpressure zones (Refer to figure 2.c) For the calculation of gradient, refer to the ?Overpressure Evaluation Manual?.

ARPO

ENI S.p.A. Agip Division

IDENTIFICATION CODE

STAP-P-1-M-6100

10 0 500 1000 1500

100

0

1000

PAGE

19 OF 230

REVISION

3500 Depth (m) 2000 2500 3000

?????????

2.3.

5000 4000 4500

????????? ?????????????????? ????????? ???????????????????????????????????????????? Top ???????? ???????????????? ???????? ???????????????????????????????? Figure 2.C Sonic log

TEMPERATURE PREDICTION

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

The higher temperatures encountered at increasing depth usually have adverse effects upon materials used in drilling wells but may be beneficial in production as it lowers the viscosity 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 become ineffective or unstable at higher temperatures and cement slurry thickening and setting times accelerate (also due to increasing pressure).

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

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

ARPO ENI S.p.A. Agip Division 2.3.1.

Temperature Gradients

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 20 OF 230 REVISION 0 The temperature of the rocks at a given point, formation temperature, and relationship between temperature and depth is termed the thermal gradient. Temperature gradients around 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 temperature

gradients will differ throughout the various regions where there are different rocks. Seasonal variations 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 previous drilling reports, offset well data or any other source. In most regions, the temperature gradient is well known and is only affected when in the vicinity of salt domes. If the temperature gradient is not known in a new area, it is recommended that a gradient of 3oC/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 may help to confirm the accuracy of the temperature prediction.

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

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 26 OF 230 REVISION 0 4.

4.1.

CASING DESIGN

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 many factors, 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 in controlling the handling of the various mixtures of grades and weights by rig personnel without 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 different weights 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 consider upgrading the casing in cases where:

??

??

Extreme wear is expected from drilling equipment used to drill the next hole section 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 not always a major criterion.

Most major operating companies have differing policies and guidelines for the design of casing 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 bottomhole flowing pressures and well head shut-in pressures as the limiting factors for internal pressures expected in the wellbore. These pressures will obviously place 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 to drill adjacent development wells.

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

ARPO ENI S.p.A. Agip Division 4.2. 4.2.1.

Casing Profiles

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 27 OF 230 REVISION 0 PROFILES AND DRILLING SCENARIOS

The following are the various casing configurations which can be used on onshore and offshore 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.

ARPO ENI S.p.A. Agip Division 4.3.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 28 OF 230 REVISION 0 CASING SPECIFICATION AND CLASSIFICATION

There is a great range of casings available from suppliers from plain carbon steel for everyday 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 some important casing issues.

Non-API casing manufacturers have produced products to satisfy a demand in the industry for casing to meet with extreme conditions which the API specifications do not meet. The area of use for this casing are also discussed in section 4.3.1 below and the products available 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 API

specifications. All involved with casing design must have immediate access to the latest copy of API Bulletin 5C2 which lists the performance properties of casing, tubing and drillpipe. 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 their contents.

It should not be interpreted from the above that only API tubulars and connections may be used in the field as some particular engineering problems are overcome by specialist

solutions which are not yet addressed by API specifications. In fact, it would be impossible to drill many extremely deep wells without recourse to the use of pipe manufactured outwith API specifications (non-API).

Similarly, many of the ?Premium? couplings that are used in high pressure high GOR conditions are also non-API.

When using non-API pipe, the designer must check the methods by which the strengths have been calculated. Usually it will be found that the manufacturer will have used the published API formulae (Bulletin 5C3), backed up by tests to prove the performance of his product conforms to, or exceeds, these specifications. However. in some cases, the

manufacturers have claimed their performance is considerably better than that calculated by the using API formulae. When this occurs the manufacturers claims must be critically examined by the designer or his technical advisors, and the performance corrected if necessary.

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

ARPO ENI S.p.A. Agip Division 4.3.2.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 29 OF 230 REVISION 0 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 and performances.

4.4. 4.4.1.

MECHANICAL PROPERTIES OF STEEL General

Failure of a material or of a structural part may occur by fracture (e.g. the shattering of glass), 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 solid materials, some deformation may be sustained without permanent deformation, i.e. the material behaves elastically.

Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of plastic, or permanent, deformation, If a material sustains large amounts of plastic

deformation before final fracture. It is classed as ductile material, and if fracture occurs with little 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 by

torsion, compression and shear, but the tension test is the most common and is qualitatively characteristics of all the other types of tests.

The action of a material under the gradually increasing extension of the tension test is

usually 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 (elongation

between two gauge points marked on the test piece divided by the original gauge length) as abscissae.

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 for by Hooke's law, and the slope of this line, or the ratio of stress to strain within the elastic range, 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 (see above) the material will contract along a line generally nearly straight and parallel to the original elastic line, leaving a permanent set.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 30 OF 230 REVISION 0

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 at

approximately constant load. The maximum stress reached in this region is called the upper yield point and the lower part of the yielding region the lower yield point. In the harder and stronger steels, and under certain conditions of temperature, the yielding phenomenon is less prominent and is correspondingly harder to measure. In materials that do not exhibit a marked yield point, it is customary to define a yield strength. This is arbitrarily defined as the stress at which the material has a specified permanent set (the value of 0.2% is widely accepted in the industry).

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

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 by definition, it is customary to designate the end of the straight portion of the curve (by definition the proportional limit) as the elastic limit. Careful practice qualifies this by designating it the ?proportional elastic limit?.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 41 OF 230 REVISION 0 External Pressure Assume the hydrostatic pressure exerted by the mud in which casing is installed. The uniform external pressure exerted by salt on the casing or cement sheath through overburden pressure, should be given a value equal to the true vertical depth of the relative point. Net Collapse Pressure In this case of the casing being empty, the net pressure is equal to the external pressure at each depth. In other cases it will be the difference between external and internal pressures 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 collapse pressure that may occur while drilling below the liner. When well testing or producing through a liner, the casing above the liner is part of the production casing/liner and must be designed according to this criteria. Tie-Back String If the intermediate string above the liner is unable to withstand the collapse pressure calculated according to production collapse criteria, it will be necessary run and tie-back a string of casing from the liner top to surface.

Figure 4.B - Fluid Height Calculation

ARPO ENI S.p.A. Agip Division 4.8.3.

Tension

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 42 OF 230 REVISION 0

Note:

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

To evaluate the tensile loading, the company procedure outlined below applies. Surface Casing Calculate the casing string weight in air. Tension Calculate the casing string weight in mud multiplying the previous weight by the buoyancy factor (BF) in accordance with the mud weight in use. Add the additional load due to bumping the cement plug to the casing string weight in mud. Note: This pull load is calculated by multiplying the expected bump-plug pressure by the inside area of the casing. A calculation of this kind is an approximation because the assumption has been made that: ? No buoyancy changes occur during cementing. ? The pressure is applied only at the bottom and not where there are changes in section. As seen with the previous case, the differences in the calculated values are quite small, which justifies the preference for the simpler approximation method. Once the magnitude and location of the forces are determined, the total tensile load line may be constructed graphically. Note: more than one section of the casing string may be loaded in compression.

ARPO ENI S.p.A. Agip Division 4.9.

BIAXIAL STRESS

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 43 OF 230 REVISION 0 When the entire casing string has been designed for burst, collapse and tension, and the weights, grades, section lengths and coupling types are known, reduction in burst resistance needs to be applied due to biaxial loading.

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

By noting the magnitude of tension (plus) or compression (minus) loads at the top and

bottom 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 the majority of wells.

4.9.1.

Effects On Collapse Resistance

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

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

The adverse effects of tension on collapse resistance usually affects the upper portion of a casing 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 collapse resistance are insignificant.

ARPO

ENI S.p.A. Agip Division

IDENTIFICATION CODE

0

PAGE 44 OF 230

STAP-P-1-M-6100

REVISION

Figure 4.C - Ellipse of Biaxial Yield Stress

ARPO ENI S.p.A. Agip Division 4.9.2.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 45 OF 230 REVISION 0 Company Design Procedure

The value for the percentage reduction of rated collapse strength is determined as follows: 1) 2) 3)

Determine the total tensile load.

Calculate the ratio (X) of the actual applied stress to yield strength of the casing. Refer to figure 4.d and curve ?effect of tension on collapse resistance? and find the corresponding percentage collapse rating (Y).

Multiply the collapse resistance by the percentage (Y), without tensile loads to obtain the 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.

4)

X=

0

0.1

0.2

0.3

0.4

Tensile load Pipe body yield strength

0.5

0.6

0.7

0.8

0.9

1

1.1

0 0.1 0.2 Y= Collapsresistence with tensile load Collapse resistence without tensile load 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1

Figure 4.D - Effect Of Tension On Collapse Resistance

ARPO ENI S.p.A. Agip Division 4.9.3.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 46 OF 230 REVISION 0 Example Collapse Calculation

Determine the collapse resistance of 7\a depth of 5,750m and a mud weight of 1.1kg/dm3. Collapse resistance without tensile load Pipe body yield strength Buoyancy factor

= 8,610psi (605 kg/cm2) = 745,000lbs (338 t) = 0.859

Weight in air of casing Weight in mud of casing

5,750 x 47 . 62 = ? 274t

1,000

= 274 x 0.859 = 235 t

Weight in mud of casing x???Pipe Body Yield Strength 235 ? 0.695 338 From the curve or stress curve factors in figure 4.d if X = 0.695 then Y = 0.445 and the collapse resistance with tensile load can be determined Collapse resistance under load

= Nominal Collapse Rating x 0.445

ARPO ENI S.p.A. Agip Division 4.10.

BENDING

4.10.1. General

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 47 OF 230 REVISION 0 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 bending causes 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-ups and drop-offs.

Since bending load increases the total tensile load, it must be deducted from the usable rated 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:

B?? 15.52?????? D?? Af

where:

??D Af TB

= = = =

Rate (degrees 30m)

Outside diameter of casing (ins) Cross-section area of casing (cm2) Additional tension (kg)

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 48 OF 230 REVISION 0 The formula is obtained from the two following equations:

????where:

MB D J ??ExJ R

MB?? D 2?? J

= = = = = =

Bending moment (MB = E x J/R) (Kg x cm) Outside diameter of casing (cm) Inertia moment (cm4) Bending stress (kg/cm2) Bending stiffness (kg x cm2) Radius of curvature (cm)

MB?? L ????E?? J

where: MB L E J ??

= = = = =

Bending moment (kg x cm) Arch length (cm)

Modulus of elasticity (kg/cm2) Inertia moment (cm4)

Change in angle of deviation (radians)

??? E?? J

thus the equation becomes: Obtaining MB???L

??????? E?? D 2?? L

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 49 OF 230 REVISION 0 Then, by using the more current units giving the build-up or drop-off angles in degrees/30 m, we obtain the final form of the equation for ?TB? as follows:

TB ????Af TB?????? E?? D?? Af 2?? L ???????

R???180?? 30 1 L???R TB??????????? E?? D?? Af 180?? 2?? 30

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

TB???????????2 . 1?? 10 6????25?? 4??? D?? Af 2?? 180 30?? 100

TB = 15.52 x?? x D x Af when:

Af ??TB W

= = = =

Square inches Degrees/100ft

218 x?? x D x Af (lbs) or 63 x?? x D x W(lbs) Casing weight (lbs/ft)

????

Note:

Since most casing has a relatively narrow range of wall thickness (from 0.25” to 0.60”), the weight of casing is approximately proportional to its diameter. This means the value of the bending load increases with the square 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 direct ratio. The result is that bending is a much more severe problem with large diameter casing than with smaller sizes.

4.10.3. Company Design Procedure

Since bending load, in effect, increases tensile load at the point applied, it must be

deducted from the usable strength rating of each section of pipe that passes the point of bending.

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

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 50 OF 230 REVISION 0 4.10.4. Example Bending Calculation

Data:

Casing: OD. 13 3/8\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) Casing weight in mud (Wm)

Wa = 107.14 x 2,00 = 214t 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 the curved 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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