Eni-Drilling Design Manual
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ARPO
ENI S.p.A. Agip Division
ORGANISING DEPARTMENT
TYPE OF ACTIVITY'
ISSUING DEPT.
DOC. TYPE
REFER TO SECTION N.
PAGE.
OF
STAP
P
1
M
1
230
6100
TITLE DRILLING DESIGN MANUAL
DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities
NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and 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
„ ƒ ‚ • € Issued by
REVISIONS
P. Magarini E. Monaci 28/06/99
C. Lanzetta
A. Galletta
28/06/99
28/06/99
PREP'D
CHK'D
APPR'D
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
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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0
INDEX 1.
2.
3.
4.
INTRODUCTION
9
1.1.
PURPOSE AND OBJECTIVES
9
1.2.
IMPLEMENTATION
9
1.3.
UPDATING, AMENDMENT, CONTROL& DEROGATION
9
PRESSURE EVALUATION
10
2.1.
FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS
10
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
11 12 12 13 14 16
2.3.
TEMPERATURE PREDICTION 2.3.1. Temperature Gradients 2.3.2. Temperature Logging
19 20 20
SELECTION OF CASING SEATS
21
3.1.
CONDUCTOR CASING
24
3.2.
SURFACE CASING
24
3.3.
INTERMEDIATE CASING
24
3.4.
DRILLING LINER
25
3.5.
PRODUCTION CASING
25
CASING DESIGN
26
4.1.
INTRODUCTION
26
4.2.
PROFILES AND DRILLING SCENARIOS 4.2.1. Casing Profiles
27 27
4.3.
CASING SPECIFICATION AND CLASSIFICATION 4.3.1. Casing Specification 4.3.2. Classification Of API Casing
28 28 29
4.4.
MECHANICAL PROPERTIES OF STEEL 4.4.1. General 4.4.2. Stress-Strain Diagram
29 29 29
4.5.
NON-API CASING
31
4.6.
CONNECTIONS 4.6.1. API Connections
32 32
4.7.
APPROACH TO CASING DESIGN 4.7.1. Wellbore Forces 4.7.2. Design Factor (DF) 4.7.3. Design Factors
33 33 34 35
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4.7.4.
PAGE
Application of Design Factors
0 35
4.8.
DESIGN CRITERIA 4.8.1. Burst 4.8.2. Collapse 4.8.3. Tension
36 36 39 42
4.9.
BIAXIAL STRESS 4.9.1. Effects On Collapse Resistance 4.9.2. Company Design Procedure 4.9.3. Example Collapse Calculation
43 43 45 46
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
47 47 47 49 50
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
52 52 53 55 56 57
4.12. SALT SECTIONS 4.12.1. Company Design Procedure
58 59
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
60 60 60 61 63 63 64
4.14. TEMPERATURE EFFECTS 4.14.1. Low Temperature Service
68 68
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)
69 69 69 70 70 71
MUD CONSIDERATIONS
72
5.1.
GENERAL
72
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
72 72 73 74 74 74 74
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
75 75 78 79 79
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6.
7.
8.
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5.3.5.
PAGE
Oil Based Mud
0 80
5.4.
SOLIDS
80
5.5.
DENSITY CONTROL MATERIALS
81
5.6.
FLUID CALCULATIONS
81
5.7.
MUD TESTING PROCEDURES
84
5.8.
MINIMUM STOCK REQUIREMENTS
85
FLUID HYDRAULICS
87
6.1.
HYDRAULICS PROGRAMME PREPARATION
87
6.2.
DESIGN OF THE HYDRAULICS PROGRAMME
88
6.3.
FLOW RATE
88
6.4.
PRESSURE LOSSES 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
90 93 93 93 93 94 94
6.5.
USEFUL TABLES AND CHARTS
95
CEMENTING CONSIDERATIONS
97
7.1.
CEMENT 7.1.1. API Specification 7.1.2. Slurry Density and Weight
97 97 100
7.2.
CEMENT ADDITIVES 7.2.1. Accelerators 7.2.2. Retarders 7.2.3. Extenders 7.2.4. Weighting Agents
102 102 103 103 104
7.3.
SALT CEMENT
105
7.4.
SPACERS AND WASHES
106
7.5.
SLURRY SELECTION
107
7.6.
CEMENT PLACEMENT
108
7.7.
WELL CONTROL
108
7.8.
JOB DESIGN 7.8.1. Depth/Configuration 7.8.2. Environment 7.8.3. Temperature 7.8.4. Slurry Preparation
110 110 111 111 111
WELLHEADS
112
8.1.
DEFINITIONS
112
8.2.
DESIGN CRITERIA 8.2.1. Material Specification
112 112
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PAGE
0
8.3.
SURFACE WELLHEADS 8.3.1. Standard Wellhead Components 8.3.2. National/Breda Wellhead Systems
113 113 113
8.4.
COMPACT WELLHEAD
116
8.5.
MUDLINE SUSPENSION
119
PRESSURE RATING OF BOP EQUIPMENT 9.1.
BOP SELECTION CRITERIA
10. BHA DESIGN AND STABILISATION
122 122
125
10.1. STRAIGHT HOLE DRILLING
125
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
125 125 126 126 126 126 126 126
10.3. HOLE ANGLE CONTROL 10.3.1. Packed Hole Theory 10.3.2. Pendulum Theory
128 128 129
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
129 129 129 131 131
10.5. PACKED BOTTOM HOLE ASSEMBLIES
131
10.6. PENDULUM BOTTOM HOLE ASSEMBLIES
133
10.7. REDUCED BIT WEIGHT
134
10.8. DRILL STRING DESIGN
135
10.9. BOTTOM HOLE ASSEMBLY BUCKLING
138
10.10.SUMMARY RECOMMENDATIONS FOR STABILISATION
140
10.11.OPERATING LIMITS OF DRILL PIPE
142
10.12.GENERAL GUIDELINES
142
11. BIT SELECTION
143
11.1. PLANNING
143
11.2. IADC ROLLER BIT CLASSIFICATION 11.2.1. Major Group Classification 11.2.2. Bit Cones
143 144 145
11.3. DIAMOND BIT CLASSIFICATION 11.3.1. Natural Diamond Bits 11.3.2. PDC Bits 11.3.3. IADC Fixed Cutter Classification
146 146 146 146
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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
148 148 149 149 150 150 150
11.5. CRITICAL ROTARY SPEEDS
150
11.6. DRILLING OPTIMISATION
152
12. DIRECTIONAL DRILLING
153
12.1. TERMINOLOGY AND CONVENTIONS
153
12.2. CO-ORDINATE SYSTEMS 12.2.1. Universal Transverse Of Mercator (UTM) 12.2.2. Geographical Co-ordinates
155 155 156
12.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 12.3.1. Horizontal Displacement 12.3.2. Target Direction 12.3.3. Convergence
158 158 159 159
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
160 161 163 165 167 172
13. DRILLING PROBLEM PREVENTION MEASURES
173
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
173 174 175 176 178
13.2. OIL PILLS 13.2.1. Light Oil Pills 13.2.2. Heavy Oil Pills 13.2.3. Acid Pills
179 179 179 180
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
181 181 182 182
13.4. FISHING 13.4.1. Inventory Of Fishing Tools 13.4.2. Preparation 13.4.3. Fishing Assembly
183 183 183 184
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
184 184 184 185 185 185
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13.6. MILLING PROCEDURE
186
13.7. JARRING PROCEDURE
187
14. WELL ABANDONMENT
189
14.1. TEMPORARY ABANDONMENT 14.1.1. During Drilling Operations 14.1.2. During Production Operations
189 189 189
14.2. PERMANENT ABANDONMENT 14.2.1. Plugging 14.2.2. Plugging Programme 14.2.3. Plugging Procedure
190 190 190 191
14.3. CASING CUTTING/RETRIEVING 14.3.1. Stub Termination (Inside a Casing String) 14.3.2. Stub Termination (Below a Casing String)
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
16. GEOLOGICAL DRILLING WELL PROGRAMME
198
200
16.1. PROGRAMME FORMAT
200
16.2. IDENTIFICATION
200
16.3. GRAPHIC REPRESENTATIONS
200
16.4. CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME 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)
201 201 207 208 209
17. FINAL WELL REPORT
210
17.1. GENERAL
210
17.2. FINAL WELL REPORT PREPARATION
210
17.3. FINAL WELL OPERATION REPORT STRUCTURE 17.3.1. General Report Structure 17.3.2. Cluster/Platform Final Well Report Structure
211 211 212
17.4. AUTHORISATION
213
17.5. ATTACHMENTS
213
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APPENDIX A - REPORT FORMS
0
214
A.1.
INITIAL ACTIVITY REPORT (ARPO 01)
215
A.2.
DAILY REPORT (ARPO 02)
216
A.3.
CASING RUNNING REPORT (ARPO 03)
217
A.4.
CASING RUNNING REPORT (ARPO 03B)
218
A.5.
CEMENTING JOB REPORT (ARPO 04A)
219
A.6.
CEMENTING JOB REPORT (ARPO 04B)
220
A.7.
BIT RECORD (ARPO 05)
221
A.8.
WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06)
222
A.9.
WELL PROBLEM REPORT (ARPO 13)
223
APPENDIX B - ABBREVIATIONS
224
APPENDIX C - WELL DEFINITIONS
228
APPENDIX D - BIBLIOGRAPHY
230
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INTRODUCTION
1.1.
PURPOSE AND OBJECTIVES
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1.
PAGE
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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.
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2.
PRESSURE EVALUATION
2.1.
FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS A well programme must contain a technical analysis including graphs of pressure gradients (overburden, pore, fracture) and temperature gradient. The following information must be included in the analysis: a)
Method for calculating the Overburden Gradient, if obtained from electric logs of reference wells or from seismic analysis.
b)
Method for defining the Pore Pressure Gradient, if obtained from data (RFT, DST, BHP gauges, production tests, electric logs, Sigma logs, D exponent) of reference wells or from seismic analysis.
c)
Formula used to derive the Fracture Gradient.
d)
Source used to obtain the Temperature Gradient.
The formulas normally used to calculate the Overburden Gradient are:
∆t =
PiP × 1000 3.28 × ∆H
D = 1.228 Gov =
∆t − 47 ∆t + 200
10 D × ∆h ∑ Hi 10
where: PiP
=
Numbers of ηsecond (calculated from sonic log for regularly depth interval, i.e. every 50/100/200m)
∆t
=
Transit time (second 10-3)
D
=
Density of the formation
Gov
=
Overburden gradient
∆H
=
Formation interval with the same density D
Hi
=
Total depth (Σ ∆H)
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Equations used by ENI Agip division for fracture gradient calculation, (when overburden gradients and pore pressure gradients have been defined), are listed below: Terzaghi equation (commonly used):
Gf = Gp +
2ν (Gov − Gp) 1− ν
When the formation is deeply invaded with water:
Gf = Gp + 2ν (Gov − Gp ) When the formation is plastic:
Gf = Gov where: Gf
=
Fracture pressure
Gov
=
Overburden gradient
Gp
=
Formation pressure
v
=
Poissions modulus
when Poisson’s modulus may have the following values:
2.2.
ν
=
0.25 for clean sands, sandstone and carbonate rocks down to medium depth
ν
=
0.28 for sands with shale, sandstone and carbonate rocks at great depth.
OVERPRESSURE EVALUATION There are three methods of qualitative and quantitative assessment of overpressure: a)
Methods before drilling
b)
Methods while drilling
c)
Methods after drilling.
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2.2.1.
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0
Methods Before Drilling 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.
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2.2.3.
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Real Time Indicators Penetration Rate
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.
Hole Fill
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.
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MWD
PAGE
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.
Bottomhole mud temperature can also be an indicator of overpressure as discussed below. 2.2.4.
Indicators Depending on Lag Time Mud Gas
The monitoring and interpretation of gas data are 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.
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Mud Temperature
PAGE
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:
Cutting Analysis
• 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.
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• 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’.
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Fig.1,2-1 INDUCTION LOG 1
Resistivity (OHMM) 10
100
1500
2000
2500
3000
Top Overpresure
3500
4000
4500
5000
Figure .2.A - Induction Log Shale Formation Factor (Fsh) Method:
This is more sophisticated than the IES method described above. It eliminates the inconveniences due to water salinity 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:
Fsh =
Rsh Rw
Where: Rsht
=The shale resistivity read on the log in the points where they are most cleaned
Rw
= 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’.
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F shale 10
0
100
1500
2000
Depth (m)
2500
3000 Top Overpresure 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’.
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10
100
0
1000
0 500 1000
Depth (m)
1500 2000
Top Overpresure
2500 3000 3500 4000 4500 5000
Figure 2.C Sonic log 2.3.
TEMPERATURE PREDICTION The temperature at various depths to which a well is drilled must be evaluated as it has 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.
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2.3.1.
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Temperature Gradients 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.
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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.
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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
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Figure 3.B - Example Casing Seat Selection (for a typical geopressurised well using a pressure profile).
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CONDUCTOR CASING 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
=
Minimum driving depth (m) from seabed
E
=
Elevation (m) distance from bell nipple and sea level
H
=
Water depth (m)
df
=
Maximum mud weight (kg/l) to be used
GOVhi = 3.2.
integrated density of sediments (kg/dm3/10m)
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.
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This can cause either, kicks causing loss of circulation and possibly an underground blowout 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.
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4.1.
INTRODUCTION
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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.
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4.2.
PROFILES AND DRILLING SCENARIOS
4.2.1.
Casing Profiles
0
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.
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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.
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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.
MECHANICAL PROPERTIES OF STEEL
4.4.1.
General Failure of a material or of a structural part may occur by fracture (e.g. the shattering 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 crosssectional 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.
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Figure 4.A- Stress - Strain Diagram In steels, a curious phenomenon occurs after the end of the elastic limit, known as yielding. This gives rise to a dip in the general curve followed by a period of deformation 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’.
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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
Min. Yield Strength
H 40
40,000psi
J 55
55,000psi
C 75
75,000psi
N 80
80,000psi
etc. In the design of casing and tubing strings the minimum yield strength of the steel is taken 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. 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.
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CONNECTIONS 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" casing or when also subjected to bending stresses, i.e. doglegs, directional drilled holes. etc. Buttress threads have, according to API calculations, higher joint strength than the 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" and larger pipe 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.
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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: • • • •
4.7.1.
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.
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) 2) 3) 4) 5)
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.
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4.7.2.
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Design Factor (DF) 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.
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Design Factors The following DF’s must be used in casing design calculations:
Note
4.7.4.
Casing Grade Design Factor H 40 1.05 J 55 1.05 K 55 1.05 C 75 1.10 L 80 1.10 Burst N 80 1.10 C 90 1.10 C 95 1.10 P 110 1.10 Q 125 1.20 All Grades 1.10 Collapse < C-95 1.70 > C-95 1.80 Tension 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. 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. 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
Use only column 11 of API casing tables and divide by the DF to obtain the collapse resistance for design calculation.
Tension
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.
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4.8.
DESIGN CRITERIA
4.8.1.
Burst
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.
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Intermediate Casing 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.
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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 = 0.3kg/dm3). 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:
External Pressure
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 head in the casing plus a safety margin of 70kg/cm2 (1,000psi) will be assumed.
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.
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Intermediate Casing and Liner If a drilling liner is to be used in the drilling of a well, the casing above where the liner 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.
Internal Pressure
Surface Casing For wells with a surface wellhead, the casing is assumed to be completely empty.
External Pressure
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:
Net Collapse Pressure
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.
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Internal Pressure
PAGE
0
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/cm2/10m) Then H = Hloss (dm-1.03)/dm Hloss
=
Depth at which circulation loss is expected (m)
dm
=
Mud density expected at Hloss (kg/dm2)
Gp
=
Pore pressure of thief zone (kg/cm2/10m) - usually Normally pressured with 1.03 as gradient.
When thief zones cannot be confirmed, or otherwise, during 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
Internal 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.
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External Pressure
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0
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
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4.8.3.
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Tension 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. Tension
Surface Casing Calculate the casing string weight in air. 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.
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4.9.
PAGE
0
BIAXIAL STRESS 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:
4.9.1.
The effects of axial stress on burst resistance are negligible for the majority of wells.
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.
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Figure 4.C - Ellipse of Biaxial Yield Stress
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4.9.2.
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0
Company Design Procedure The value for the percentage reduction of rated collapse strength is determined as follows: 1) 2) 3) 4)
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.
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
Collapsresistence with tensile load Collapse resistence without tensile load
0.1 0.2 0.3 0.4 0.5 0.6
Y=
0.7 0.8 0.9 1 1.1
Figure 4.D - Effect Of Tension On Collapse Resistance
0.9
1
1.1
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4.9.3.
PAGE
0
Example Collapse Calculation Determine the collapse resistance of 7", N 80, 32lbs/ft (4kg/m), BTR casing with the shoe at a depth of 5,750m and a mud weight of 1.1kg/dm3. Collapse resistance without tensile load
= 8,610psi (605 kg/cm2)
Pipe body yield strength
= 745,000lbs (338 t)
Buoyancy factor
= 0.859
Weight in air of casing
=
Weight in mud of casing
= 274 x 0.859 = 235 t
x=
5,750 x 47.62 = 274t 1,000
Weight in mud of casing 235 = = 0.695 Pipe Body Yield Strength 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
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4.10.
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0
BENDING
4.10.1. General When calculating tension loading, the effect of bending should be considered if applicable. The bending of the pipe causes additional stress in the walls of the pipe. This 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 × α × D × Af where: α
=
Rate (degrees 30m)
D
=
Outside diameter of casing (ins)
Af
=
Cross-section area of casing (cm2)
TB
=
Additional tension (kg)
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The formula is obtained from the two following equations:
σ=
MB × D 2× J
where: MB
=
Bending moment (MB = E x J/R) (Kg x cm)
D
=
Outside diameter of casing (cm)
J
=
Inertia moment (cm4)
σ
=
Bending stress (kg/cm2)
ExJ
=
Bending stiffness (kg x cm2)
R
=
Radius of curvature (cm)
σ=
MB × L E×J
where: MB
=
Bending moment (kg x cm)
L
=
Arch length (cm)
E
=
Modulus of elasticity (kg/cm2)
J
=
Inertia moment (cm4)
θ
=
Change in angle of deviation (radians)
Obtaining MB =
48 OF 230
θ×E×J thus the equation becomes: L
σ=
θ×E×D 2×L
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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:
θ=
TB Af
TB =
θ × E × D × Af 2×L
R=
180 × 30 π×α
L=
1 R
TB =
π × α × E × D × Af 180 × 2 × 30
E = 21,000kg/mm2 = 2.1 x 106kg/cm2
TB =
(
)
π × α × 2.1 × 10 6 (25 × 4 ) × D × Af × 2 × 180 30 × 100
TB = 15.52 x α x D x Af when:
Note:
Af
=
Square inches
α
=
Degrees/100ft
TB
=
218 x α x D x Af (lbs) or 63 x α x D x W(lbs)
W
=
Casing weight (lbs/ft)
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.
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4.10.4. Example Bending Calculation Data: Casing: OD. 13 3/8", 72lbs/ft (107.14kg/m), C 75, BTR Directional well with casing shoe at 2,000m. (MD) Kick-off point at 300m Build-up rate: 3°/30m Maximum angle: 30° Mud weight : 1.1kg/dm3 Pipe body yield strength: 1,558,000lbs (707t) Design factor : 1.7 Calculation: Casing weight in air (Wa)
Wa = 107.14 x 2,00 = 214t
Casing weight in mud (Wm)
Wm = 214 x 0.859 = 184t
Additional tension due to the bending effect (TB) TB = 15.52 x 3 x 13.375 x 133.99 = 83,441kg = 83t This stress will be added to the tensile stress already existing on 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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Figure 4.F - Bending Load Example
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4.11.
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CASING WEAR
4.11.1. General Casing wear decreases the performance properties of casing. The burst and collapse resistance of worn casing is in direct proportion to its remaining wall thickness.
Figure 4.G - Casing Wear
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A major contributing factor to reducing the life of a casing string is poor handling throughout the supply chain. All personnel in this chain must adopt the proper handling procedures. The major factors affecting casing wear are: • • • • • •
Rotary speed Tool joint lateral load and diameter Drilling rate Inclination of the hole Severity of dog legs Wear factor.
The location and magnitude of volumetric wear in the casing string can be estimated by calculating the energy imparted from the rotating tool joints to the casing at different casing points and dividing this by the amount of energy required to wear away a unit volume of the casing. The percentage casing wear at each point along the casing is then calculated from the volumetric wear. Eni-Agip acceptable casing wear limit is 4600
---
---
---
---
ULTRA DEEP WELL
> 6000
---
---
---
---
DEEPWATER WELL
---
---
---
---
460
HIGH PRESSURE WELL
---
> 1.81
> 690
---
---
HIGH TEMPERATURE WELL
---
---
---
> 150°c
---
Title
Description
WATER WELL
Producing water well
WATER INJECTION WELL
Well for water injection
GAS INJECTION WELL
Well for gas injection
Table 15.A - Well Definitions and Characteristics
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16.
PAGE
0
GEOLOGICAL DRILLING WELL PROGRAMME The Geological and Drilling Well Programme (Refer to STAP-P-2-N-6001E) is a ‘controlled’ live document (i.e. univocally identifying and fulfilling the requirements of EniAgip Division and Affiliate’s Quality Management System) according to a standard format providing information on a specific well and avoiding duplication of data.
16.1.
PROGRAMME FORMAT The Geological and Drilling Well Programme, from now on defined as ‘‘G&DWP’’, comprises four sections: Section 1
-
General Information
Section 2
-
Geological Programme
Section 3
-
Operation Geology Programme
Section 4
-
Drilling Programme.
The ‘G&DWP’ will also be standardised with regard to the following: • • • • • • • 16.2.
Print model Type and size of character Page numbering Identification Distribution list Graphic representations Structure of the sections.
IDENTIFICATION All main sections in the ‘G&DWP’, must be identified by the Name/Designation of the Well. The name of the well must be shown on all the pages of the document along with the acronym of the Project Unit and the District/Affiliates.
16.3.
GRAPHIC REPRESENTATIONS In order to allow section of the ‘G&DWP’ to be easily accessible whether by E-Mail or through shared network disks, the graphic representations shall be in electronic format, using Eni-Agip Division and Affiliate’s standard ‘Windows’ tools Power Point, Freelance Graphics, Excel, etc.
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The sketches and drawings which are not reproducible with this software, must be scanned in and the files saved in the formats of the filters in ‘Word’ (.PCX, .BMP; etc.).The version of word may be updated from time to time and, hence, the filters also altered to suit. The size of the files produced must be rationalised and kept as small as possible to reduce the document memory size hence make easier management. Prints produced with software different from Eni-Agip Division & Affiliates standard such as: prints and diagrams produced by means of ADIS, geological maps and seismic sections, figures taken from catalogues and publications will be produced on a blank page and applied a page number for consistency. The number of these particular types of representations should be minimised to prevent the format being different from A4, different fonts and colours. If unavoidable these must be included as Annexes. 16.4.
CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME The structure of the ‘G&DWP’ and its relevant competencies are detailed in the following sub-sections. The list of contents for each section and the section numbering must be strictly followed. If some subjects are not applicable, the term ‘not envisaged’ will be placed against these relevant sections or subsections. Additional subsections to provide clarity or further explanation of a formal content subject are permitted.
16.4.1. General Information (Section 1) This section contains the main data of the well project and a synthesis of the main subjects which are explained in detail. This section must be proposed in conjunction with the Drilling & Completion and Geology Departments of the particular District/Affiliates. All depths of the well, both for offshore and onshore wells, must be referenced to the Rotary Table (RT). Section 1 comprises the sub-sections numbered and titled as follows: 1.1
GENERAL WELL DATA
1.2
WELL TARGET
1.3
GENERAL RECOMMENDATIONS 1.4
GENERAL CHARACTERISTICS OF THE RIG, BOP STACK AND SAFETY EQUIPMENT
1.5
LIST OF THE MAIN CONTRACTORS
1.6
CONTACTS IN CASE OF EMERGENCY
1.7
REFERENCE MANUALS
1.8
MEASUREMENT UNITS
An explanation of each of these is given in the following sub-sections.
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Authorisation The names and signatures of the technicians and managers involved in the preparation and control of the section will always be specified. General Well Data (Section 1.1) This section lists the main data regarding the well project. This section will be prepared by the District Geology Department following input by the competent Project Department and will contain the information presented in table 16.a. The Local Drilling & Completion Department will provide the Well Profile, the Time Versus Depth Diagram, and the Location Layout. The District Geology Department will provide the scheme Forecast and Acquisition Programmes. Well Target (Section 1.2) This section will be prepared by the Local Geology Department and summarises what is described in sub-section 2.3 of section 2 (e. g. verification of the ‘up-dip’ potential of the structure, and development of ‘probable’ undrained reserves, etc.). General Recommendations (Section 1.3) This section will be prepared with close co-operation between the Drilling & Completion and Geology Local Departments, highlighting the possible operational problems envisaged and which will be described in detail in the following sections (Geological Programme, Operation Geology Programme and Drilling Programme). General Characteristics of the RIG, BOP Stack and Safety Equipment (Section 1.4) This section is prepared by the Local Drilling & Completion Department and will contain the information listed in table 16.b and table 16.c
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ITEM
0
DESCRIPTION IDENTIFIABLE WELL DATA
Affilate in charge Name and acronym of the well Initial classification (LAHEE) Expected final depth Permission/concession Operator Older of the Permit/ Lease (shares specified as %) Municipal Authority (onshore wells) Province (onshore wells) Harbour-master office (offshore wells) Zone (off-shore wells) Distance Rig/coast (offshore wells) Distance Rig/operative base Altitude (onshore wells) Sea Depth (offshore wells) WELL TARGET IDENTIFICATION Reference seismic line Lithology of the main target Formation of the main target Depth of the main target TOPOGRAPHIC REFERENCES Reference meridian Starting latitude (geographic) N/S Starting longitude (geographic) E/W Latitude at the targets (geographic) N/S Longitude at the targets (geographic) E/W Starting latitude (metric) N/S Starting longitude (metric) E/W Latitude at the targets (metric) Longitude at the targets (metric) Type of projection Semi-major axis Squared eccentricity (1/F) Central meridian False East False North Scale Factor Table 16.A - General Well Data
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Item
0
Description
Contractor Rig name Rig type Rotary table elevation at ground level
Only onshore rigs
Rotary table elevation at sea level
Only offshore rigs
Number of slots available
Only offshore rigs
Power installed Drawwork type Rig potential with 5” DP’s Max. operative water depth
Only offshore rigs
Clearance height rotary beams/ground level
Only onshore rigs
Top Drive System type Swivel assembly working pressure
If without Top Drive System
Dynamic hook load Set back capacity Deck load
Only for semi-submersible rigs
Total load
Only for semi-submersible rigs
Rotary table diameter Rotary table capacity Stand pipe working pressure Mud pumps number and type Available liner size Total mud capacity Shaleshaker number and type Drinking water storage capacity
Only for offshore rigs
Industrial water storage capacity Gas oil storage capacity Barite storage capacity Bentonite storage capacity Cement storage capacity Table 16.B -General Rig Data
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Item
Description
Diverter type Diverter size Diverter working pressure BOP stack type BOP size BOP working pressure Choke manifold size and working pressure Kill lines size and working pressure Choke lines size and working pressure BOP control panel type BOP control panel location Inside BOP type Inside BOP location Table 16.C - Equipment Data List of the Main Contractors (Section 1.5) The section will be prepared by the Local Drilling & Completion Department in co-operation with the Local Sub-surface Geology Department and must contain the services required and the name of the provider. The following Table is presented as an example: SERVICE
COMPANY
Rig Mud Water/mud disposal Cementing Mud logging Electrical logging LWD Drilling tools Coring Directional drilling Drilling equipment Tubing and casing tong Testing
Table 16.D - List of the Main Contractors
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Contacts in case of emergency (Section 1.6) This section will be prepared by the Local Drilling & Completion Department and shows: • •
A ‘flow chart’ of emergency contacts The telephone numbers of the relevant people in charge of the emergency.
Reference Manuals (Section 1.7) Reference Manuals will be written by the Local Drilling & Completion Department. It consists in a list of basic manuals to be referred for planning and implementation phases of the well. Measurement Units(Section 1.8) The section ‘Measurement Units’ will be written in strict co-operation between the Drilling & Completion and Sub-surface Geology Local Departments. It will contain a list of the units of measurement for the main parameters used in the Geological Operation and Drilling sections. These are: Depth:
m
Pressures:
kg/cm²
Pressure gradients :
kg/cm²/10m or atm/10m
Specific gravity :
kg/l or kg/dm³
Lengths:
m
Weights:
t
Oil volumes
Sm3
Volumes:
m³
Bit and casing diameters:
ins
Tubular goods weight
lbs/ft
Working pressure :
psi
Gas volume
Sm3
Salinity
ppm of NaCl
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16.4.2. Geological Programme (Section 2) The Geological Programme will be written by the Department in charge of the project in cooperation with the Local Sub-surface Geology Department. All the reference depths will be from: • •
Ground level for ONSHORE wells Sea level for OFFSHORE wells
Section 2 comprises the sub-section headings listed below, numbered and titled as follows: List of contents 2.1
GEOLOGICAL FRAMEWORK
2.2
SEISMIC INTERPRETATION
2.3
WELL TARGETS
2.4
SOURCE ROCKS
2.5
SEALING ROCKS
2.6
LITHOSTRATIGRAPHIC PROFILE
2.7
REFERENCE WELLS Annexes and/or figures
Authorisation The names and signatures of the technicians and managers involved in the preparation and control of the section will be always specified.
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16.4.3. Operation Geology Programme (Section 3) The ‘Operation Geology Programme’ will be prepared by the Local Sub-surface Geology Department. Section 3 will comprise the sub-sections numbered and titled as follows: List of contents 3.1
SURFACE LOGGING
3.2
SAMPLINGS 3.2.1
Cuttings
3.2.2
Bottom Hole Cores
3.2.3
Side Wall Cores
3.2.4
Fluids Sampling
3.3
LOGGING WHILE DRILLING
3.4
WIRELINE LOGGING
3.5
SEISMIC SURVEY
3.6
WIRELINE TESTING
3.7
TESTING
3.8
STUDIES AND DRAWINGS
3.9
REFERENCE WELLS
Authorisation The names and signatures of the technicians and managers involved in the preparation and control of the section will be always specified.
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16.4.4. Drilling Programme (Section 4) The ‘Drilling Programme’ will be prepared by the District Drilling & Completion Department. The Drilling Programme structure is defined in procedure STAP-P-1-N-6001E. Particularly, paragraphs 4.2.1 (forecast on pressure and temperature gradients) and 4.2.2 (drilling problems) will be made in co-operation between the Drilling and Completion and Subsurface Geology Local Departments. Section 4 will comprise the sub-sections numbered and titled as follows: List of contents 4.1
4.2
OPERATIONAL SEQUENCE 4.1.1
Preliminaries
4.1.2
Conductor pipe phase
4.1.3
Superficial phase
4.1.4
Intermediate phases
4.1.5
Final phase
4.1.6
Testing
4.1.7
Completion typology
4.1.8
Well abandonment
WELL PLANNING 4.2.1
Forecast on pressure and temperature gradients
4.2.2
Drilling problems
4.2.3
Casing setting depths
4.2.4
Casing design
4.2.5
Mud programme
4.2.6
Cementing programme
4.2.7
BOP
4.2.8
Wellhead
4.2.9
Hydraulic programme
4.2.10
BHA and stabilisation
4.2.11
Bits and drilling parameters
4.2.12
Deviation project Annexes and/or figures
Authorisation The names and signatures of the technicians and managers involved in the preparation and control of the section will be always specified.
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0
FINAL WELL REPORT This section details the procedure to prepare the ‘Final Well Report’. Properly completed Final Well Reports are essential to enable all personnel involved in drilling and completion activities access to well information for studies, analysis or to help prepare future well programmes.
17.1.
GENERAL Whenever possible or applicable, the well final report shall include reports on both Drilling and Completion activities. In the case of new wells the report will be titled ‘ Final Well Drilling and Completion Report’ or, in case of workover on old wells, as ‘ Final Workover Well Drilling and Completion Report’. Where only Drilling operations are concerned (e.g. Exploration Wells, Dry Holes, Temporary Abandonment, etc.), the report will be titled ‘Final Well Drilling Report’. If completion operations are performed separately after the end of drilling operations are completed (e.g. Temporary Abandoning or Batch Operations) the report will be titled ‘Final Well Completion Report’. When separate drilling and completion reports are prepared, the two reports will be merged. In the case of a multi-well Development Project where, wells are drilled or completed from a single location (platform or cluster) the report will be titled ‘ (platform name) or (cluster name) Final Drilling and Completion Report’. In the following section the structure and competency required in the preparation of the ‘Final Well Report shall be explained. Reporting will be standardised through using the common format as follows: • • • • • • • •
Print Model Type and Size of the Character Page Numbering Identification Distribution List Graphic Representations Chapters Structure Signatures
These criteria shall be common for all Well Operations ‘Final Well Reports’ in both domestic and foreign operations. 17.2.
FINAL WELL REPORT PREPARATION The Final Well Report is prepared by the ‘Engineering Section’ of the Drilling and Completion Department’ in co-operation with the ‘Operations Section’. The numeration and the title of the sections as shown in section 17.3, must be strictly followed. Extra sub-sections for clarity or further explanation are permitted. If some subjects are applicable to a particular well, not envisaged will be typed against the relevant sections.
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17.3. FINAL WELL OPERATION REPORT STRUCTURE 17.3.1. General Report Structure 1
GENERAL INFORMATION
2
1.1 GENERAL WELL DATA 1.2 GENERAL RIG SPECIFICATION 1.3 BOP SKETCH 1.4 LIST OF MAIN CONTRACTORS 1.5 OPERATIONS ORGANISATION CHART 1.6 LOCATION MAP WELL HISTORY 2.1
3
FINAL WELL STATUS 2.1.1 Well Sketch 2.1.2 Well Head Sketch 2.1.3 Well Completion Sketch 2.2 DETAILED OPERATIONS HISTORY 2.2.1 Moving 2.2.2 Conductor Pipe Phase 2.2.3 Surface Phase 2.2.4 Intermediate Phases 2.2.5 Final Phase 2.2.6 Well Testing 2.2.7 Completion 2.2.8 Abandoning 2.3 DRILLING PROBLEMS AND RECOMMENDATIONS 2.4 COMPLETION REMARKS DATA ANALYSIS
3.1 Pressure And Temperature Gradients 3.2 Casing Data 3.3 Cementing Data 3.4 Drilling Fluids 3.5 Bit And Hydraulic Data 3.6 Bottom Hole Assembly 3.7 Directional Drilling 3.8 Well Testing Data 3.9 Completion Details 3.10 Time Analysis 4 ATTACHMENTS (Service companies must be requested to supply copies of their own reports as this enhances the quality of the information contained in the report).
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17.3.2. Cluster/Platform Final Well Report Structure 1 CLUSTER/PLATFORM INFORMATION
2
1.1 GENERAL DATA 1.2 GENERAL RIG SPECIFICATION 1.3 BOP SKETCH 1.4 LIST OF MAIN CONTRACTORS 1.5 OPERATIONS ORGANIZATION CHART 1.6 LOCATION MAP 1.7 CLUSTER/PLATFORM WELL BAY LAY-OUT AND ORIENTATION GENERAL DRILLING & COMPLETION ACTIVITY REPORT 2.1
3
FINAL WELLS STATUS 2.1.1 Well Sketches 2.1.2 Wells Head Sketches And Elevations 2.1.3 Completion Schemes 2.1.4 General Cluster/Platform Time Vs Depth Diagram 2.2 DETAILED OPERATIONS HISTORY 2.2.1 Moving 2.2.2 Conductor Pipe Phase 2.2.3 Surface Phase 2.2.4 Intermediate Phases 2.2.5 Final Phase 2.2.6 Testing 2.2.7 Completion 2.2.8 Abandoning 2.3 PRESSURE AND TEMPERATURE GRADIENTS 2.4 DRILLING PROBLEMS AND RECOMMENDATIONS 2.5 COMPLETION REMARKS DATA ANALYSIS
4
3.2 CASING DATA 3.3 CEMENTING DATA 3.4 DRILLING FLUIDS 3.5 BIT AND HYDRAULIC DATA 3.6 BOTTOM HOLE ASSEMBLY 3.7 DIRECTIONAL DRILLING 3.8 WELL TESTING DATA 3.9 COMPLETION DETAILS 3.10 TIME ANALYSIS ATTACHMENTS (Service companies must be requested to supply copies of their own reports as this enhances the quality of the information contained in the report).
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General Information (Section 1) In this sub-section the main data relevant to the Well, Rig and Operation Organisation should be reported. All depths for both offshore and onshore wells must be referred to from Rotary Table (RT), the elevation of which above datum shall be clearly stated. General Drilling and Completion Activity Report (Section 2) In this section the history of the well e.g. final well status, detailed operation history, operation problems register and recommendations for Drilling and Completion activities etc., will be reported. Data Analysis (Section 3) In this part, data relevant to drilling and completion operations will be reported in detail. 17.4.
AUTHORISATION Authorisation for the ‘ Final Well Report’ will be included as follows according to the procedures envisaged in paragraph 6.5 of STAP-G-1-M-9000:
17.5.
Prepared by :
District Drilling and Completion Expert
Controlled by:
District Engineering and operation sections Manager of Drilling and Completion department
Approved by :
District Drilling and Completion Manager
ATTACHMENTS Included In this section there are all paragraphs required for particular purposes, such as: • • • • •
Spider plot Cost analysis Evaluation of service main contractor Weather condition etc.
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Appendix A - Report Forms To enable the contents of this drilling design manual and other operating procedures manuals to be improved, it is essential that ENI - Agip Division and Affiliates obtain feedback from the field. To this end a feed-back reporting system is in use which satisfies this requirement. Feed-back reports for drilling, completion, workover and well testing operations are available and must be filled in and returned to head office for distribution to the relevant responsible departments as soon as possible as per instructions. The forms relevant to drilling operations are: •
ARPO 01
Initial Activity Report
•
ARPO 02
Daily Report
•
ARPO 03A
Casing Running Report
•
ARPO 03B
Casing Running Report
•
ARPO 04A
Cementing Job report
•
ARPO 04B
Cementing Job report
•
ARPO 05
Bit Record
•
ARPO 06
Waste Disposal Management Report
•
ARPO 13
Well Problem Report
Behind each report form are instructions on how to fill in the forms. As the first section is generic to all the forms it is only shown in ARPO 01 instructions. Note:
If not otherwise specified , all depths referred to in this appendix will be from Rotary Kelly Bushing Elevation (this being from the first Rig which drilled the well).
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Initial Activity Report (ARPO 01)
District/Affiliate Company DATE:
INITIAL ACTIVITY REPORT
ARPO 01
Permit/Concession N°
Cost center
Well Code
General Data On shore
WELL NAME FIELD NAME
Depth Above S.L .
Off shore
Joint venture
Ground Level[m]
AGIP:
%
%
Latitude:
Water Depth [m]
%
%
Longitude
Rotary Table Elev.[m]
%
%
Reference
First Flange[m]
Rig Name
Top housing [m]
Type of Operation
Reference Rig
Rig Type Contractor
Ref. Rig RKB - 1st Flange
Program TD (Measured)
[m]
Program TD (Vertical)
[m]
Cellar Pit
Rig Heading [°] Offset FROM the proposed location
Rig Pump
Depth [m]
Manufacturer
Distance [m]
Length [m]
Type
Direction [°]
Width [m]:
Liner avaible [in] Major Contractors
Type of Service
Company
Contract N°
Type of Service
Company
Contract N°
Mud Logging D. & C. Fluids Cementation Waste treatment Operating Time
Jack-up leg Penetration
Supply Vessel for Positioning
Moving
[gg:hh]
Leg
Air gap
Penetration
Positioning
[hh:min]
N°
[m]
[m]
Anchorage
[hh:min]
Rig-up
[hh:min]
Delay
[hh:min]
Lost-time Accidents
[hh:min]
N°
Name
Horse
Bollard pull
Power
[t]
Rig Anchorage Anchor Bow N°
Angle
Mooring Line Weight
Type & Manufacturer
[t]
Piggy Back
Length Cable
Chain
[m]
[m]
Weight N°
[t]
Mooring Line Chain
Tension Operative
Cable
Length
Ø
Length
Ø
[m]
[mm]
[m]
[mm]
Tension
Time
[t]
[t]
[hh:min]
1 2 3 4 5 6 7 8 9 10 11 12 Note:
Total
[Tested]
Supervisor
Superintendent
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Daily Report (ARPO 02)
DAILY REPORT
WELL NAME
Drilling
FIELD NAME
District/Affiliate Company DATE:
ARPO 02
Cost center
Rig Name
RT Elevation
[m]
Type of Rig
Ground Lelel / Water Depth
[m]
Report N°
[m]
Permit / Concession N°
st
RT - 1 flange / Top Housing
Contractor Well
Last casing
BOP
Next Casing
Ø
Type
w.p. [psi]
Well Code of
M.D. (24:00)
[m]
Ø nom.[in]
Stack
T.V.D. (24:00)
[m]
Top [m]
Diverter
Total Drilled
[m]
Bottom [m]
Annular
Rotating Hrs
[hh:mm]
Top of Cmt [m]
Annular
R.O.P.
[m / h] [hh:mm]
Last Survey [°]
at m
Upper Rams
Progressive Rot. hrs
LOT - IFT [kg/l]
at m
Middle Rams
Back reaming Hrs
Middle Rams
Personnel
Reduce Pump Strockes Pressure 1
Pump N°
2
3
[hh:mm] Injured
Middle Rams
Agip
Agip
Liner [in]
Lower Rams
Rig
Rig
Strokes Press. [psi]
Last Test
Others Total
Other Total
Lithology Shows From (hr)
To (hr)
Op. Code OPERATION DESCRIPTION
Operation at 07:00 Mud type Density Viscosity P.V. Y.P. Gel 10"/10' Water Loss HP/HT Press. Temp. ClSalt pH/ES MBT Solid Oil/water Ratio. Sand pm/pom pf mf Daily Losses Progr. Losses
[kg/l] [s/l] [cP] [g/100cm2] / [cc/30"] [cc/30"] [kg/cm2] [°C] [g/l] [g/l] [kg/m3] [%] [%]
Bit Data Manuf. Type Serial No. IADC Diam. Nozzle/TFA From [m] To [m] Drilled [m] Rot. Hrs. R.P.M. W.O.B.[t] Flow Rate Pressure Ann. vel. Jet vel. HHP Bit HSI I [m 3] [m 3] B
N°
Run N°
N°
Run N°
Bottom Hole Assembly N° __________ Rot. hours Ø Description Part. L Progr.L Partial Progr.
Stock
Total Cost O G
D O
L R
I B
O G
D O
L R
Daily Progr.
Quantity
UM
Supervisor:
Supply vessel
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Casing Running Report (ARPO 03)
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Casing Running Report (ARPO 03B)
RUNNING CASING REPORT
District/Affiliate Company DATE: Operation type
ARPO 03 / B Ø [in]
Casing type
WELL NAME FIELD NAME Cost center
Top [m]
Bottom [m]
Joint
Length
Progress.
centr.
Joint
Length
Progress.
centr.
Joint
Length
Progress.
centr.
N°
[m]
[m]
(N°)
N°
[m]
[m]
(N°)
N°
[m]
[m]
(N°)
Remarks:
Supervisor
Superintendent
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Cementing Job report (ARPO 04A)
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0
Cementing Job report (ARPO 04B)
CEMENTING JOB REPORT
District/Affiliate Company DATE:
WELL NAME FIELD NAME
ARPO-04 / B
Operation type
Cost center Stage / No.:
Ø [in] SQUEEZE / PLUG
Type
Ø
Length [m]
Cap.[ l/m]
Bottom [m]
Cement retainer
Manufacturer
Injectivity Test with:
Pump Rate Testing Pr. [l/min] [kg/cm2]
Test
Ø
Depth
[inch]
[m]
Model / Type
Squeeze packer
[kg/cm2]
Tot. Vol.
Final Sqz Pr.
Returns Vol
pumped [l]
[kg/cm2]
[l]
[mins]
Stinger Pressure test Annular pressure CEMENTATION [kg/cm2]
Operation (y/n) Casing Reciprocation
Bump Plug
Casing testing pressure
Casing Rotation
Valve holding
Annulus pressurization
[mins]
Inner string GENERAL DATA Slurry Displacement With
Losses [m 3]
To Surface
pumps
Density
Fluid type:
[kg/l] 3
pH
Dumped [m3]
During csg run Circulation
Volume
[m ]
Mud
Mix/Pump Slurry
Density:
[kg/l]
Spacer
Displacement
Duration:
[mins]
Slurry
Final pressure:
Opening DV
[kg/cm2]
Circ. through DV Total Circulation / Displacement / Squeeze
Time [mins.] Partial
Supervisor
Progr.
Flow Rate
Pressure
Total Volume
[l/min]
[kg/cm2]
[l]
Operation Description
Superintendent
Final Press.
Returns
[kg/cm2]
Vol. [l]
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
0
Bit Record (ARPO 05)
BIT RECORD
District/Affiliate Company DATE:
WELL NAME FIELD NAME ARPO-05
Cost center
Run n°
Bit n° Bit size [in] Bit manufacturer Bit type Special features codes Serial number IADC code Depth in [m] Depth out [m] Drilled interval [m] Rotation hrs Trip hrs R.O.P. [m/h] Average W.O.B. [t] Average R.P.M. D.H.M. R.P.M. Flow rate [l/min] 2 St. pipe pressure [kg/cm ] D.H.M. Press. drop [kg/cm2]
Bit HHP HSI Annulus min vel. [m/min] [1/32 in] 1 [1/32 in] 2 [1/32 in] 3 [1/32 in] 4 [1/32 in] 5 [1/32 in] C 2 [in ] T.F.A. B Inner rows [I] I Outher rows [O] T Dull char. [D] Location [L] D Bearing/Seals [B] U Gauge 1/16 [G] L Other chars [O] L Reason POOH [R] Mud type Mud density [kg/l] Mud visc. Mud Y.P. Survey depth Survey incl. Bit Cost
J E T S
Li
Type
%
Stabilizer
Distance
Diameter
from bit
[in]
[m]
tho lo gy
B H A
Currency Pag.:
Supervisor of:
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Superintendent
ARPO
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0
Waste Disposal Management Report (ARPO 06)
WASTE DISPOSAL
WELL NAME
Management Report
FIELD NAME
District/Affiliate Company DATE:
ARPO-06 Cost center
Report N°
Depth (m)
Mud Type
From [m]
Density (kg/l)
To [m]
Interval Drilled (m) 3 Drilled Volume [m ]
Phase size [in]
Cumulative volume [m ]
Cl- concentration (g/l ) 3
3
Water consumption Usage
3
Phase /Period [m ] Fresh water
Recycled
Cumulative [m ] Total
Fresh water
Recycled
Total
Mixing Mud Others Total 3
3
Fresh water [m ]
Readings / Truck 3
Mud Volume [m ]
Phase
Recycled [m ] Service
Cumulative
Mixed
Company
Contract N°
Mud Company
Lost
Waste Disposal
Dumped
Transportation
Transported IN Transported OUT Waste Disposal Water base cuttings
Period
Oil base cuttings
[t] [t]
Dried Water base cuttings
[t]
Dried oil base cuttings
[t]
Water base mud
[t]
Oil base mud transported IN
[t]
Oil base mud transported OUT
[t]
Drill potable water
[t]
Dehidrated water base mud
[t]
Dehidrated oil base mud
[t]
Sewage water
[t]
Transported Brine
[t]
Cumulative
Remarks
Remarks
Supervisor
Superintendent
ARPO
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Well Problem Report (ARPO 13)
WELL PROBLEM REPORT
District/Affiliate Company DATE: Problem
WELL NAME Cost center
Top [m]
Code Well
ARPO -13
FIELD NAME
Start date
Bottom [m] Ø
Situation
End date
Measured Depth Top [m]
Vertical Depth
Bottom [m]
Top [m]
KOP
Bottom [m]
Open hole
Mud in hole
[m]
Max inclination [°]
Type
@m
Dens.[kg/l]:
DROP OFF [m]
Last casing Well problem Description
Solutions Applied:
Results Obtained:
Solutions Applied:
Results Obtained:
Solutions Applied:
Results Obtained:
Solutions Applied:
Results Obtained:
Supervisor
Supervisor
Supervisor
Remarks at District level:
Superintendent Lost Time Remarks at HQ level
hh:mm Loss value [in currency] Pag. Of
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Appendix B - ABBREVIATIONS API BG BHA BHP BHT BOP BPD BPM BPV BUR BWOC BWOW CBL CCD CCL CDP CET CMT CP CR CRA CW DC DHM DIF DLS DM / D&CM DOB DOBC DOR DP DST DV E/L ECD ECP EMS EMW EOC ESD FBHP FBHT FINS FPI/BO FTHP
PAGE
American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom hole temperature Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Build Up Rate By Weight Of Cement By Weight Of Water Cement Bond Log Centre to Centre Distance Casing Collar Locator Common Depth Point Cement Evaluation Tool Cement Conductor Pipe Cement Retainer Corrosion Resistant Alloy Current Well Drill Collar Down Hole Motor Drill-In Fluid Dog Leg Severity Drilling & Completion Manager Diesel Oil Bentonite Diesel Oil Bentonite Cement Drop Off Rate Drill Pipe Drill Stem Test DV Collar Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight End Of Curvature Electric Shut-Down System Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Ferranti International Navigation System Free Point Indicator / Back Off Flowing Tubing Head Pressure
0
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FTHT GCT GLS GMS GOC GPM GR GSS HAZOP HDT HO HP/HT HW/HWDP IADC IBOP ID KMW KOP LAT LCM LOT LQC LTA LWD MAASP MD MLH MMS MODU MOP MSL MSS MW MWD NACE NB NMDC NSG NTU OBM OD OEDP OIM OMW ORP OWC P&A
PAGE
Flowing Tubing Head Temperature Guidance Continuous Tool Guidelineless Landing Structure Gyro Multi Shot Gas Oil Contact Gallon (US) per Minute Gamma Ray Gyro Single Shot Hazard and Operability High Resolution Dipmeter Hole Opener High Pressure - High Temperature Heavy Weight Drill Pipe International Drilling Contractor Inside Blow Out Preventer Inside Diameter Kill mud weight Kick Off Point Lowest Astronomical Tide Lost Circulation Materials Leak Off Test Log Quality Control Lost Time Accident Log While Drilling Max Allowable Annular Surface Pressure Measured Depth Mudline Hanger Magnetic Multi Shot Mobile Offshore Drilling Unit Margin of Overpull Mean Sea Level Magnetic Single Shot Mud Weight Measurement While Drilling National Association of Corrosion Engineers Near Bit Stabiliser Non Magnetic Drill Collar North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Open End Drill Pipe Offshore Installation Manager Original Mud weight Origin Reference Point Oil Water Contact Plugged & Abandoned
0
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PCG PDC PDM PGB PI PLT POB PPB ppm PV PVT RBP RJ RKB ROE ROP ROU ROV RPM RT S (HDT) S/N SBHP SBHT SCC SD SDE SF SG SICP SIDPP SIMOP SPM SR SRG SSC ST STG TCP TD TFA TG TGB TOC TOL TVD TW
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Pipe Connection Gas Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Production Logging Tool Personnel On Board Pounds Per Barrel Part Per Million Plastic Viscosity Pressure Volume Temperature Retrievable Bridge Plug Ring Joint Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle Revolutions Per Minute Rotary Table High Resolution Dipmeter Serial Number Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Separation Distance Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Simultaneous Operations Stroke per Minute Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Steering Tool Short trip gas Tubing Conveyed Perforations Total Depth Total Flow Area Trip Gas Temporary Guide Base Top of Cement Top of Liner True Vertical Depth Target Well
0
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UAR UGF UR VBR VDL VSP W/L WBM WC WL WOB WOC WOW WP YP
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Uncertainty Area Ratio Universal Guide Frame Under Reamer Variable Bore Rams (BOP) Variable Density Log Velocity Seismic Profile Wire Line Water Base Mud Water Cut Water Loss Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point
0
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Appendix C - WELL DEFINITIONS Definitions and parameters to described wells characteristics.
Definition
Inclination da a
ROC (m)
Parameter BUR (°/m) (°/30 m)
Horizontal Section (m)
Short Radius
x°
90°
5.8 - 30.1
9.8 ÷ 1.9 294 ÷ 57
150 - 250
Intermediate Radius
x°
90°
43.1 12.79
1.33 ÷ 4.48 40 ÷ 70
150 - 250
Minimum Radius
x°
90°
86.8 220.4
0.66 ÷ 0.26 20 ÷ 8
500 - 900
Long Radius
x°
90°
286 - 573
0.2 ÷ 0.1 3÷6
1000 -1600
Definition Drain Hole Extended Reach Well Lateral Well Multi Lateral Well Re-Entry Well Branch Well
Curve Characteristic Short Radius Long Radius
Parameter Displacement Roc (M) (M) 150 - 250
5.8 ÷ 30.1
1000 - 1600
286 ÷ 573
Bur (°/M) (°/30 M) 9.8 - 1.9 294 - 57 0.2 - 0.1 3-6
All are Horizontal wells As shown in section 2 example #5 A well re-entered to production, by drilling operations, in a previous suspended well. See example in chapter 2 A drain hole drilled for extended reach Parameter
Definition
Deep Well Ultra Deep Well Deepwater Well High Pressure Well High Temperature Well
Depth (M)
Pore Press. Bar/10m
SIWH Press. (Bar)
> 4,600 > 6,000 -------
------> 1.81 ---
------> 690 ---
Temp Res. O/WH (°C) --------> 150°c
Water Depth (M)
----460 -----
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Water Well Water Injection Well Gas Injection Well
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Word
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Description Producing water well Well for water injection Well for gas injection
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Appendix D - BIBLIOGRAPHY Eni-Agip Document:
STAP Number
ADIS Casing Design Manual Drilling Fluids Manual Drilling, Jar Acceptance and Utilisation Procedures Drilling Procedures Manual General Well Control Policy Manual Other
TEAP Number
Emergency Operating Procedures
TEAP-P-1-M-6040
API Specifications 5c API Specifications10 NACE Standard MR-01-75
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