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 11 OF 230 REVISION 0 Equations used by ENI Agip division for fracture gradient calculation, (when overburden gradients and pore pressure gradients have been defined), are listed below: Terzaghi equation (commonly used):

2??Gf?? Gp???(Gov??? Gp)

1?????When the formation is deeply invaded with water:

Gf?? Gp?? 2? (Gov??? Gp)

When the formation is plastic:

Gf?? Gov

where:

Gf Gov Gp v ??

= = = = =

Fracture pressure Overburden gradient Formation pressure Poissions modulus

0.25 for clean sands, sandstone and carbonate rocks down to medium

depth

0.28 for sands with shale, sandstone and carbonate rocks at great depth.

when Poisson?s modulus may have the following values:

??

=

2.2.

OVERPRESSURE EVALUATION

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

a) b) c)

Methods before drilling Methods while drilling Methods after drilling.

ARPO ENI S.p.A. Agip Division 2.2.1.

Methods Before Drilling

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 12 OF 230 REVISION 0 Gradients prediction is based, on the most part, analysis and processing of seismic data and data obtained from potential reference wells. This includes:

Drilling Records

These can be used in determining hole problems, abnormal pressures, lost circulation zones, required mud weights and properties, etc.

Wireline Logs

These can provide useful geological information such as

lithology, formations tops, bed thicknesses, dips, faults, wash out, lost circulation zones, formation fluid content and formation fluid pressure (pore pressure).

Seismic Surveys

Provides two of the most important applications of seismic data in; the detection of formations characterised by abnormal pressures and; in the forecasting of probable pressure gradient. The data from seismic surveys are analysed and interpreted to evaluate transit times and propagation velocity for each interval in the formation. Since overpressurised zones have a porosity higher than normal, it is reflected in a travel time increase.

It is obvious that if the drilling is explorative and is the first well in a specific area, the seismic data analysis may be the sole source of information available.

The prediction of the gradients is essential for planning the well and must be included in the drilling programme. This initial drilling phase may be able to detect zones of potential risk but cannot guarantee against the potential presence and magnitude of abnormal pressures and, hence caution must be exercised.

2.2.2.

Methods While Drilling

Given all the predictive methods available, successful drilling still depends on the effectiveness 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 do signal the presence of an abnormal conditions due to the existence of an abnormally

behaving zone. Such methods, therefore, provide a warning that a more careful and diligent observation must be maintained on the well.

The most critical situation occurs when a well with normal gradient penetrates a high pressure zone without any indications caused by faulting or outcropping at a higher

elevation. However, when abnormal pressure occurs as a result of compaction only, many of the following real time indicators appears before a serious problem develops.

ARPO ENI S.p.A. Agip Division 2.2.3.

Real Time Indicators Penetration Rate

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 13 OF 230 REVISION 0

While drilling in normal pressured shales of a well, there will be a uniform decrease in the drilling rate due to the increase in shale density. When abnormal pressure is encountered, the density of the shale is decreased with a resultant increase in porosity. Therefore, the drilling rate will gradually increase as the bit enters an abnormal pressured shale. The corrected ?d? exponent and Eni-Agip Sigmalog eliminate the effects of drilling parameter variations and give a representative measure of formation drillability.

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

A copy of corrected the ?d? exponent or Agip Sigmalog shall be sent on daily basis to the Company?s Shore Base Drilling Office by telefax for further checking.

Drilling Break

A drilling break is defined as a rapid increase in penetration rate after a relatively long interval of slow drilling.

Any time a drilling break is noticed, drilling shall be suspended and 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 pressured shale section is penetrated due to the swelling of plastic clay causing a decrease in hole diameter and/or accumulation of large cuttings around the bit and the stabilisers.

Also torque is not easy to interpret in view of many

phenomena which can affect it (hole geometry, deviation, bottom hole assembly, etc.), it must be thought as the

second-order parameter for diagnosing abnormal pressure.

Tight Hole During Connections

Tight hole when making connections can indicate that an abnormal pressured shale is being penetrated with low mud weight. When this occurs it is confirmed when the hole must be reamed several times before a connection can be made. When making up connections, cavings may settle preventing the bit returning to bottom.

Wall instability, in an area of abnormal pressure, may cause sloughing. It should be noted that fill may be due to other causes, such as wall instability through geomechanical reasons (fracture zones), inefficient well cleaning by the

drilling mud, rheological properties of mud insufficient to keep cuttings in suspension, etc.

Hole Fill

ARPO ENI S.p.A. Agip Division MWD

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 14 OF 230 REVISION 0 In addition to directional drilling data, MWD can provide a wide range of bottom hole drilling parameters and formation evaluation, e.g.: bottomhole weight on bit, torque at bit,

gamma ray, mud and formation resistivity, mud pressure and mud temperature.

If the true weight and torque at the bit are known, the drilling rate can be normalised with more accuracy by producing a more accurate ?d? exponent and Agip Sigmalog.

Formation resistivity is plotted and interpreted for pressure development. It should also be noted that differential resistivity between the mud in the drill pipe and in the annular space may be considered as a kick indicator.

2.2.4.

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

Indicators Depending on Lag Time Mud Gas

The monitoring and interpretation of gas data are fundamental to detecting abnormally pressured zones.

? Background gas is the gas released by the formation while drilling. It usually is a low but steady level of gas in the mud which may be interrupted by higher levels resulting from the drilling of a hydrocarbon bearing zone or from trips and connections.

? An increase in the level of background gas, from that

previously found in overlying normally compacted shales, often occurs when drilling undercompacted formations. ? Gas shows can occur when porous, permeable formations containing gas are penetrated. Monitoring the form and the volume of gas shows will make it easier to detect a state of negative differential pressure.

? Trip gas may be an indication of well underbalance. The equivalent 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, the drop in pressure while static may allow gas to flow from the formation into the well. The quantity of gas observed at the surface when circulation is resumed, however will depend on several factors, e.g., differential pressure, formation permeability, drill pipe pulling speed, swabbing. Failure to fill 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 is an important aid to evaluate differential pressure. When an undercompacted zone of uniform shale is drilled without increasing the mud weight, the amount of connection gas will almost always increase.

ARPO ENI S.p.A. Agip Division Mud Temperature

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 15 OF 230 REVISION 0 Measurement of mud temperature can also be used to detect undercompacted zones and, under ideal conditions, or to anticipate their approach. This is because temperature

gradients observed in undercompacted series are, in general, abnormally high compared with overlying normally pressured sequences.

Accurate interpretation of these data is very difficult, due to a number of variables which frequently mask changes in geothermal gradient:

? Inflow temperature, which is dependent on the amount of cooling at surface.

? Flow rate, which affects the speed at which the mud, and the 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.

? 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 a determining factor in this analysis.

? Shale density: is based on the principle that bulk density in an undercompacted zone does not follow the trend of the normally compacted overlying clays and shales. The validity of the density obtained depends on the clay composition (the presence of accessory heavy minerals can greatly change the density), the depth lagging (which can make cutting selection difficult), the mud type (reactive muds have an adverse effect on measurement quality) and clay consolidation (difficult to measure on wellsite the density of clays not sufficiently consolidated).

? Shale factor: undercompacted clays which have been unable to dehydrate often have an unusually high

proportion of smectite and an abnormally high shale factor. However, the initial proportions of the clay minerals in the deposit can mask changes in shale factor and give a false alarm.

? Shape, size and volume of cuttings: the amount of shale

cuttings will usually increase, along with a change in shape, when an abnormal pressure zone is penetrated.

Cutting Analysis

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 21 OF 230 REVISION 0 3. SELECTION OF CASING SEATS

The selection of casing setting depths is one of the most critical factors affecting well

design. These are covered in detail in the ?Casing Design Manual?. The following sections are to provide engineers with an outline of the criteria necessary to enable casing seat selection.

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 to obtain knowledge of the various uncertainties. Information is sourced from:

??

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

Drilling data from offset wells in the area. (Company wells or scouting information).

??

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 last casing seat then installation of a further string of casing is necessary. figure 3.b show typical examples of casing seat selections.

ARPO ENI S.p.A. Agip Division

????

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 22 OF 230 REVISION 0

????

Casing is set at depth 1, where pore pressure is P1 and the fracture pressure is F1.

Drilling continues to depth 2, where the pore pressure P2 has risen to almost equal 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 taken into account.

Figure 3.A - Example of idealised Casing Seat Selection

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 23 OF 230 REVISION 0

Figure 3.B - Example Casing Seat Selection

(for a typical geopressurised well using a pressure profile).

ARPO ENI S.p.A. Agip Division 3.1.

CONDUCTOR CASING

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 24 OF 230 REVISION 0 The setting depth for conductor casing is usually shallow and selected so that drilling fluid may be circulated to the mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient fracturing resistance to allow fluid circulation to the surface. In wells with subsea wellheads, no attempt is made to circulate through the conductor string to the surface but must be set deep enough to assist in stabilising the subsea 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 E H df

3.2.

= = = =

Minimum driving depth (m) from seabed

Elevation (m) distance from bell nipple and sea level Water depth (m)

Maximum mud weight (kg/l) to be used integrated density of sediments (kg/dm3/10m)

GOVhi =

SURFACE CASING

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

The depth should be enough to provide a fracture gradient sufficient to allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the surface will 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 pressured

formations 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 sloughing shales.

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

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

??

??

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

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

However, in general practice, drilling is allowed until the mud weight is within 50gr/l of the fracture 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 many holes have been lost by attempts to extend the intermediate string setting depth beyond that indicated by the above rule.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 25 OF 230 REVISION 0 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 also cause stuck pipe .

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

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

It is often tempting to ?drill a little deeper? without setting pipe in exploratory wells. When pressure 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 the Drilling Programme.

3.4.

DRILLING LINER

The setting of a drilling liner is often an economically attractive decision in deep wells as opposed to setting a full string. Such a decision must be carefully considered as the intermediate 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 the

intermediate 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 be evaluated.

If a production liner is planned then either the production liner or the drilling liner should be tied 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 for the production liner. By doing so, the intermediate casing can be designed for a lower burst requirement, resulting in considerable cost savings. Also, any wear to the intermediate string is spanned prior to drilling the producing interval.

If increased mud weight will be required while drilling hole for the drilling liner, then leak-off tests should be specified in the Drilling Procedures in the programme for the intermediate casing 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 geological objective. Depths, hence the casing programme, may have to be altered accordingly if depths run high or low.

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

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.:

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??

??

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 31 OF 230 REVISION 0 As extension continues beyond yielding, the material becomes stronger causing a rise of the curve, but at the same time the cross-sectional area of the specimen becomes less as it is drawn out. This loss of area weakens the specimen so that the curve reaches a maximum and then falls off until final fracture occurs.

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

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

Depending on the type or grade, minimum requirements are laid down for the mechanical properties, 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 H 40 J 55 C 75 N 80 etc.

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

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

API specification 5CT ?Restricted yield strength casing and tubing? however specifies, the complete chemical requirements for grades C 75, C 95 and L 80.

Min. Yield Strength

40,000psi 55,000psi 75,000psi 80,000psi

4.5.

NON-API CASING

Eni-Agip Division and Affiliates policy is to use API casings whenever possible. Some

manufacturers produce non-API casings for H2S and deep well service where API casings do not meet requirements. The most common non-API grades are shown in the Casing Design Manual (STAP-P-1-M-6110-4.3).

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

ARPO ENI S.p.A. Agip Division 4.6.

CONNECTIONS

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 32 OF 230 REVISION 0 The selection of a casing connection is dependant upon whether the casing is exposed to wellbore fluids and pressures. API connections are normally used on all surface and

intermediate casing and drilling liners. Non-API or premium connections are generally used on production casing and production liners in producing wells.

API connections rely on thread compound to form the seal and are not recommended for sealing over long periods of time when exposed to well high pressures and corrosive fluids as the compound can be extruded exposing the threads to corrosive fluids which in turn reduces the strength of the connection. Sealing on premium connections are provided by at least one metal-to-metal seal which prevents this exposure of the threads to corrosive elements, 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 pipe body. This in turn requires heavier pipe to meet design requirements, than if the pipe and coupling had the same strength. Problems like ?pullouts? or ?jump-outs? can happen with round thread type coupling on 103/4\doglegs, directional drilled holes. etc.

Buttress threads have, according to API calculations, higher joint strength than the pipe body yield strength with a few exceptions. Buttress threads also stab and enter easier than round threads, therefore, should be used whenever possible, except for 20\where special connections could be beneficial due to having superior make-up characteristics.

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

According to API standards the coupling shall be of the same grade as the pipe except grade 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.

ARPO ENI S.p.A. Agip Division 4.7.

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 33 OF 230 REVISION 0 APPROACH TO CASING DESIGN

Casing design is basically a stress analysis procedure which is fully described in the ?Casing Design Manual?.

As there is little point in designing for loads that are not encountered in the field, or in

having a casing that is disproportionally strong in relating to the underlying formations, there are clearly four major elements to casing design:

??

??????

Definition of the loading conditions likely to be encountered throughout the life of the 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 the string.

Next, the collapse load should be evaluated and the string sections upgraded if necessary.

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

The pipe can be upgraded as necessary as the loads are found and the coupling type determined.

The final step is a check on biaxial reductions in burst strength and collapse

resistance caused by compression and tension loads, respectively. If these reductions show the strength of any part of the section to be less than the potential load, the section should again be upgraded.

2) 3) 4) 5)

ARPO ENI S.p.A. Agip Division 4.7.2.

Design Factor (DF)

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 34 OF 230 REVISION 0 The design process can only be completed if knowledge of all anticipated forces is

available. This however, is idealistic and never actually occurs. Some determinations are usually 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 design factors used.

Design factors are necessary to cater for:

??

Uncertainties in the determination of actual loads that the casing needs to

withstand and the existence of any stress concentrations, due to dynamic loads or particular well conditions.

Reliability of listed properties of the various steels used and the uncertainty in the determination of the spread between ultimate strength and yield strength. Probability of the casing needing to bear the maximum load provided in the calculations.

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 and running 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 provide excessive strength and, hence, cost.

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

Casing is generally designed to withstand stress which, in practice, it seldom encounters due to the assumptions used in calculations, whereas, production tubing has to bear pressures 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 effects from formation fluid, a higher DF is used for tubing than casing.

ARPO ENI S.p.A. Agip Division 4.7.3.

Design Factors

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 35 OF 230 REVISION 0 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 burst and collapse resistance are calculated. 4.7.4.

Application of Design Factors

The minimum performance properties of tubing and casing from the ?API? bulletin are only

used to determine the chosen casing is within the DF.

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

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 pressure resistance of casing to be used for design calculation

Collapse Tension

Use only column 11 of API casing tables and divide by the DF to obtain the collapse resistance for design calculation. Use the lowest value from columns 20-27 of the API casing tables and divide by the DF to obtain the joint strength for design calculation.

Note:

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

The term ?Safety Factor? as used in tubing design, implies that the actual physical properties and loading conditions are exactly known and that a specific margin is being allowed for safety. The loading conditions are not always precisely known in casing design, and therefore in the context of casing design the term ?Safety Factor? should be avoided.

ARPO ENI S.p.A. Agip Division 4.8. 4.8.1.

DESIGN CRITERIA Burst

IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 36 OF 230 REVISION 0 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 be established according to the company procedure outlined below.

Internal Pressure Surface Casing The wellhead burst pressure limit is arbitrary, and is generally set equal to that of the working pressure rating of the wellhead and BOP equipment 2 but with a minimum of 140kg/cm . See ?BOP selection criteria? in section 9.1. With a subsea wellhead, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to surface but in any case not less than 2,000psi (140atm). Consideration should be given to the pressure rating of the wellhead and BOP equipment which must always be equal to, or higher than, the pressure rating of the pipe. When an oversize BOP having a capacity greater than that necessary is selected, the wellhead burst pressure limit will be 60% of the calculated surface pressure obtained as difference between the fracture pressure at the casing shoe with a gas column to surface. Methane gas (CH4) with 3 density of 0.3kg/dm is normally used for this calculation. In any case it shall never be considered less than 2,000psi (140atm). The use of methane for this calculation is the ?worst case? when the specific gravity of gas is unknown, as the specific gravities of any gases which may be encountered will usually be greater than that of methane. The bottomhole burst pressure limit is set equal to the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottomhole burst pressure limits with a straight line to obtain the maximum internal burst load verses depth. When taking a gas kick, the pressure from bottom-hole to surface will assume different profiles according to the position of influx into the wellbore. The plotted pressure versus depth will produce a curve. External Pressure In wells with surface wellheads, the external pressure is assumed to be equal 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, at each depth, the external from internal pressure.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 Intermediate Casing PAGE 37 OF 230 REVISION 0 Internal Pressure The wellhead burst pressure limit is taken as 60% of the calculated value obtained as difference between the fracture pressure at the casing shoe and the pressure of a gas column to wellhead. In subsea wellheads, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to the wellhead minus the seawater pressure The bottom-hole burst pressure limit is equal to that of the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottom-hole burst pressure limits with a straight line to obtain the maximum internal burst pressure External Pressure The external collapse pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered. Net Burst Pressure The resultant burst pressure is obtained by subtracting the external from internal pressure versus depth.

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 38 OF 230 REVISION 0 Production Casing The ?worst case? burst load condition on production casing occurs when a well is shut-in and there is a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied to the top of the packer fluid (i.e. completion fluid) in the tubing-casing annulus. Internal Pressure The wellhead burst limit is obtained as the difference between the pore pressure of the reservoir fluid and the hydrostatic pressure produced by a colum of fluid which is usually gas (density = 3) 0.3kg/dm . Actual gas/oil gradients can be used if information on these are known and available. The bottom-hole pressure burst limit is obtained by adding the wellhead pressure burst limit to the annulus hydrostatic pressure exerted by the completion fluid. Generally the completion fluid density is, equal to or close to, the mud weight in which casing is installed. Note: It is usually assumed that the completion fluid and mud on the outside of the casing remains homogeneous and retain their original density values. However this is not actually the case particularly with heavy fluids but it is also assumed that the two fluids will degrade similarly under the same conditions of pressure and temperature. Connect the wellhead and bottom-hole burst pressure limits with a straight 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 depth and at the well head pressure minus the hydrostatic 2 head in the casing plus a safety margin of 70kg/cm (1,000psi) will be assumed. External Pressure The external pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered. Net Burst Pressure The resultant burst pressure is obtained by subtracting the external from internal pressure at each depth.

ARPO IDENTIFICATION CODE PAGE 39 OF 230 ENI S.p.A. Agip Division REVISION STAP-P-1-M-6100 0 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 burst pressure that may occur while drilling below the liner. The design of the intermediate casing string is, therefore, altered slightly. Since the fracture pressure and mud weight may be greater or lower below the liner shoe than casing shoe, these values must be used to design the intermediate casing string as well as the liner. When well testing or producing through a liner, the casing above the liner is part of the production string and must be designed according to this criteria Tie-Back String In a high pressure well, the intermediate casing string above a liner may be unable to withstand a tubing leak at surface pressures according to the production burst criteria. The solution to this problem is to run and tie-back a string of casing from the liner top to surface, isolating the intermediate casing.

4.8.2.

Collapse

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

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

No allowance is given to increased collapse resistance due to cementing. Surface Casing For wells with a surface wellhead, the casing is assumed to be Internal Pressure completely empty. In offshore wells with subsea wellheads, the internal pressure assumes that the mud level drops due to a thief zone In wells with a surface wellhead, the external pressure is assumed to be equal to that of the hydrostatic pressure of a column of drilling mud. 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 (if atm). The resultant collapse pressure is obtained by subtracting the internal pressure from external pressure at each depth.

External Pressure Net Collapse Pressure

ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 40 OF 230 REVISION 0 Internal Pressure Intermediate Casing The ?worst case? collapse loading occurs when a loss of circulation is encountered while drilling the next hole section with the maximum allowable mud weight. This would result in the mud level inside the casing dropping to an equilibrium level where the mud hydrostatic equals the pore pressure of the thief zone (Refer to Errore. L'origine riferimento non è stata trovata.). Consequently it will be assumed 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/cm /10m) Then H = Hloss (dm-1.03)/dm Hloss = Depth at which circulation loss is expected (m) dm = Mud density expected at Hloss (kg/dm ) 2 2 2 Gp = Pore pressure of thief zone (kg/cm /10m) - usually Normally pressured with 1.03 as gradient. When thief zones cannot be confirmed, or otherwise, during the collapse design, as is the case in exploration wells, Eni-Agip division and associates suggests that on wells with surface wellheads, the casing is assumed to be half empty and the remaining part of the casing full of the heaviest mud planned to drill the next section below the shoe. In wells with subsea wellheads, the mud level inside the casing is assumed to drop to an equilibrium level where the mud hydrostatic pressure equals the pore pressure of the thief zone. External Pressure The pressure acting on the outside of casing is the pressure of 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 The effective collapse line is obtained by subtracting the internal pressure from external at each depth. Production Casing During the productive life of well, tubing leaks often occur. Also wells may be on artificial lift, or have plugged perforations or very low internal pressure values and, under these circumstances, the production casing string could be partially or completely empty. The ideal solution is to design for zero pressure inside the casing which provides full safety, nevertheless in particular well situations, the Drilling and Completions Manager may consider that the lowest casing internal pressure is the level of a column of the lightest density producible formation fluid. Internal Pressure

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