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
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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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7.
8.
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REVISION STAP-P-1-M-6100
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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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.
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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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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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0
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 â&#x20AC;&#x2DC;worst caseâ&#x20AC;&#x2122; 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: â&#x20AC;˘ No buoyancy changes occur during cementing. â&#x20AC;˘ 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 â&#x20AC;&#x2DC;Holmquist & Nadaiâ&#x20AC;&#x2122; 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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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 â&#x20AC;&#x2DC;effect of tension on collapse resistanceâ&#x20AC;&#x2122; 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
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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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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: 3째/30m Maximum angle: 30째 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 </= 7%. Volumetric wear is proportional to an empirical ‘wear factor’ which is defined as the coefficient of friction divided by the volume of casing material removed per unit of energy input. The wear factor depends upon several variables including : • • • • Note:
Mud properties Lubricants Drill solids Tool-joint roughness. The chemical action of gases such as H2, CO2 and O2 tends to reduce the surface hardness of steel and, thus, contributes significantly to the rate of wear.
4.11.2. Volumetric Wear Rate The volume of casing worn away by the rotating tool joint equals: Wear Volume Per Foot(V) =
Energy Input Per ft Specific Energy
where: Specific Energy
=
The amount of energy required to wear away a unit volume of casing material.
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The frictional energy imparted to the casing by the rotating tool joint equals: Energy Input Per Foot = Friction Force Per Foot x Sliding Distance where: Friction Force Per Foot
=
Friction Factor x Tool Joint Lateral Load Per Foot
Sliding Distance
=
n x TJ Diameter x Rotary Speed x Contact Time
and: Tool Joint Contact Time =
S × TJL DPJL
where: S
=
Drilling Distance
TJL
=
Tool Joint Length
P
=
Rate of Penetration
DPJL.
=
Drill Pipe Joint Length
The lateral load on the drill pipe equals: Drill Pipe Lateral load per Foot (L) =
TJLLPF x TJL DPJL
where: TJLLPF =
Tool Joint Lateral Load Per Foot
TJL
=
Tool Joint Length
DPJL.
=
Drill Pipe Joint Length
The Wear Factor controlling the wear efficiency is defined as: Wear Factor = Friction Factor/Specific Energy Combining the above equations. shows that the Wear Volume, V, equals:
v=
60 x π x F x L x D x N x S P
where: V
=
Wear Volume Per Foot (ins3/ft)
F
=
Wear factor (ins2/lbs)
L
=
Lateral Load on Drill Pipe Per Foot (lbs/ft)
D
=
Tool Joint Diameter (ins)
N
=
Rotary Speed (RPM)
S
=
Drilling Distance (ft)
P
=
Penetration Rate (ft/hr)
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The tool joint and drill pipe lengths do not appear in Equation 6 because they do not effect the amount of casing wear in the linear model. Note:
Wear volume increases non-linearly with wear depth, because grooves become wider as the wear depth increases.
4.11.3. Wear Factors Wear Factor (F) Tool Joint
(10-1 psi-l)
Water+Betonite+Barite
Smooth
0.5 -
Water+Betonite+Lubricant (2%)
Smooth
0.5 - 5
Water+Betonite+Drill Solids
Smooth
5 - 10
Water
Smooth
10 - 30
Water+Betonite
Smooth
10 - 30
Water+Betonite+Barite
Slightly Rough
20 - 50
Water+Betonite+Barite
Rough
50 - 150
Water+Betonite+Barite
Very Rough
200 - 400
Drilling Fluid
Table 4.A - Typical Casing Wear Factors Wear Factor Drilling Fluid Water+Betonite+Barite Water
Tool Joint
(10-1 psi-l)
Rubber Protector
1-2
Rubber Protector 4 - 10 Table 4.B - Typical Casing Wear Factors (Shell-Bradley, 1975)
Drilling Fluid
Mud Weight
Tool
Weighting
Wear Factor
(lbs/al)
Joint
Material
(10-l0psi-1)
Oil+Bentonite
10
Smooth
Barite
0.9 - 1.2
Water+Bentonite
10
Smooth
Barite
0.8 - 1.6
Water+Bentonite
10
Smooth
Iron Oxide
3-4
Water+Betontite
10
Smooth
Drill Solids
5 - 11
Water+Betontite
10
Smooth
Sand
11 - 13
Water+Betontite
8.8
Smooth
None
22 - 27
Table 4.C - Effect of Weighting Material on Casing Wear Factor (Bol, 1985)
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4.11.4. Wear Allowance In Casing Design With the design loads recommended it is highly unlikely that a reduction in collapse resistance due to wear will be critical at shallow depths or similarly that the reduction in burst resistance will be critical at the lower end of the casing string. The most likely wear points in a deviated wells are at the kick-off point and near surface in the vertical portion where buckling may occur (particularly at the top of cement). In the vertical wells, wear points may also develop at the top of cement if buckling occurs but unless there are known sudden changes in formation dip, which could cause a large â&#x20AC;&#x2DC;drilled doglegâ&#x20AC;&#x2122;, wear is likely to be small and uniformly spread over the entire length of the string. For most purposes, consideration of wear allowances can be restricted to deviated wells, with the most likely wear point at the kick-off point where burst reduction will be the prime consideration. Since wear estimates are order-of-magnitude calculations, it is recommended that wear allowances be considered only in cases where the burst (or collapse) resistance of the casing at the wear point will be approached during the anticipated operating time in the string. In marginal cases, it may well prove cost effective to run a base caliper survey to re-survey the casing prior to entering a hydrocarbon bearing zone (or pressure test the casing to the equivalent of the burst pressures anticipated from the zone) than to run heavy walled casing through all the anticipated wear sections. The recommended procedure is therefore: 1) 2)
3) 4)
Conduct the casing design. At the wear points, calculate the allowable reduction in wall-thickness so that the burst (or collapse) resistance of the casing just equals the burst (or collapse) load, including the appropriate Design Factor applied. Estimate the wear rate in terms of loss of wall thickness per operating day. Calculate, from the allowable loss in wall thickness and the rate of wear, the allowable operating time in the string.
If the allowable operating time is less than the anticipated operating time, use heavier casing (or increases the grade) 100m above and to 60m below the wear point until the allowable operating time exceeds the anticipated operating time. If the allowable operating time is greater than the anticipated operating time (say estimated 50 days allowable versus estimated 20 days operating) do not include a wear allowance. If the allowable operating time and the anticipated operating time are about the same, either: a)
include a wear allowance or
b)
monitor casing wear during drilling, and commission an intermediate string if the worn casing strength approaches the design loads.
In any given situation whether option a) or b) is exercised will be dependent upon a number of factors, many of which are beyond the scope of routine casing design.
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Option a) Is the conservative approach, but it may be too high, given the gross uncertainties inherent in wear estimations. However, in rank wildcats, particularly in remote locations, it may be justified. Option b) Requires a base caliper survey to be run immediately after installing the casing string, followed by runs at discrete intervals during the drilling phase. If wear is proven to have occurred, and an intermediate string has to be commissioned early, the deeper objectives of the well may not be reached. However, conditions as drilling proceeds may indicate that the design loads assumed are not going to be encountered and the reduction in casing strength is acceptable. In any event, valuable data on casing wear in the area will be obtained and field practices may be improved as result of the attention paid to wear, eventually leading to a reduction in overall wear rates. In most cases, option b) is preferred. 4.11.5. Company Design Procedure There is no reliable method of predicting casing wear and defining the corresponding reduction in casing performance. Because the reduction in burst and collapse rating is directly proportional to wall thickness the revised theoretical value may be calculated. The normal procedure to cater for possible wear when designing casing is to select the next casing grade or wall thickness, therefore, in a vertical well, casing wear is usually in the first few joints below the wellhead or intervals with a high dogleg severity. Consideration should be given to increasing the grade or wall thickness of the first few joints below the wellhead. In deviated wells, wear will be over the build-up and drop-off sections. Again the casing over these depths can be of a higher grade or heavier wall thickness.
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SALT SECTIONS Salt formations often exhibit plastic flow properties which can cause exceedingly high loads on casing. The rate of salt flow is a function of its composition, temperature, depth or overburden pressure and also probably influenced by how it is bedded or interbedded with other formations. The problem of salt formations has to be assessed on an individual well to well and/or area to area basis. The objectives for drilling through salt zones should be: • •
To achieve trouble free drilling. Prevent casing collapse during the drilling and the production life of the well.
With regards to trouble free drilling, sticking due to salt flow, mud problems from salt contamination, hole enlargement and the well's overall casing programme, are the prime factors to be considered. There are other factors that have to not be under evaluated such as: • • •
Control of gas flows from porous zones interbedded in the salt, differential sticking in porous zones. Abnormal pressure due to entrapment of pressure by salt Shale sloughing from interbedded or boundary shales.
To prevent casing collapse, the designer should plan for non-uniform salt loading, obtaining the best possible cement job, using casing with higher than normal collapse ratings and possibly two strings of casing through the salt section. In some cases, two strings may be more advantageous as experience has demonstrated that it is not practical to design a casing string to resist collapse. This technique is probably the most reliable and safest approach for preventing casing collapse but is probably not necessary in the majority of salt sections.
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4.12.1. Company Design Procedure In designing casing for any application, the accepted design load is the one for which the casing is subjected to the greatest conceivable loads. In the particular case of casing design opposite salt formations, certain guidelines can be considered: • • • • •
For production casing exposed to salt formations, assume the casing will be always evacuated at some point during the well life. The uniform external pressure exerted by salt on the casing (or cement sheath) due to overburden pressure should be given a value equal to the true vertical depth to the point in question. Proper cement placement opposite a salt section is often difficult due to washout. Any beneficial effects of the cement sheath should be ignored during design of the casing. If the wellbore is deviated, additional axial forces due to hole curvature should be considered when determining the collapse resistance of the casing.
Conclusions: • • •
Running casing in salt sections is rather a cementing problem than a casing problem. If the pipe is well cemented, it is sufficient to design for collapse load in the traditional mode (overburden pressure/design factor). If the casing is poorly cemented the collapse effect may be very high. In this case, it may help to run heavier wall casing.
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CORROSION A production well design should attempt to contain produced corrosive fluids within tubing. They should not be produced through the casing/tubing annulus. However, it is accepted that tubing leaks and pressured annuli are a fact of life and as such, production casing strings are considered to be subject to corrosive environments when designing casing for a well where hydrogen sulphide (H2S) or carbon dioxide (CO2) laden reservoir fluids can be expected. During the drilling phase, if there is any likelihood of a sour corrosive influx occurring, consideration should be given to setting a sour service casing string before drilling into the reservoir. The BOP stack and wellhead components must also be suitable for sour service.
4.13.1. Exploration And Appraisal Wells Routine measures to be taken during drilling include: • • •
Use of casing and wellhead equipment with a metallurgy suitable for sour service. Use of high alkaline mud to neutralise the H2S gas. Use of inhibitors and/or scavengers.
These measures will provide a degree of short term protection necessary to control corrosion of the casing in the hole during the drilling phase. 4.13.2. Development Wells Casing corrosion considerations for development wells can be confined to the production casing only. Internal corrosion The well should be designed to contain any corrosive fluids (produced or injected) within the tubing string by using premium connections. Any part of the production casing that is likely to be exposed to the corrosive environment, during routine completion/workover operations or in the event of a tubing or wellhead leak, should be designed to withstand such an environment. External corrosion Where the likelihood of external corrosion due to electrochemical activity is high and the consequences of such corrosion are serious, the production casing should be cathodically protected( either cathodically or by selecting a casing grade suitable for the expected corrosion environment).
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4.13.3. Contributing Factors To Corrosion Most corrosion problems which occur in oilfield production operations are due to the presence of water. Whether it may be present in large amounts or in extremely small quantities, it is necessary to the corrosion process. In the presence of water, corrosion is an electrolytic process where electrical current flows during the corrosion process. To have a flow of current, there must be a generating or voltage source in a completed electrical circuit. The existence, if any, of the following conditions alone, or in any combination may be a contributing factor to the initiation and perpetuation of corrosion: Oxygen (O2) Oxygen dissolved in water drastically increases its corrosivity potential. It can cause severe corrosion at very low concentrations of less than 1.0 PPM. The solubility of oxygen in water is a function of pressure, temperature and chloride content. Oxygen is less soluble in salt water than in fresh water. Oxygen usually causes pitting in steels. Carbon dioxide (CO2) When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water and increase its corrosivity. It is not as corrosive as oxygen, but also usually results in pitting. The important factors governing the solubility of carbon dioxide are pressure, temperature and composition of the water. Pressure increases the solubility to lower the pH, temperature decreases the solubility to raise the pH. Corrosion primarily caused by dissolved carbon dioxide is commonly called â&#x20AC;&#x2DC;sweetâ&#x20AC;&#x2122; corrosion. The partial pressure of carbon dioxide can be determined by the formula: Partial Pressure = Total pressure x Mol Fraction of C02 in the gas Example: In a well with a bottom hole pressure of 3,500psi and a gas containing 2% carbon dioxide: Partial pressure
= 3,500 x 0.02 = 70psi
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Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the following relationships have been found: • • •
Partial pressure > 30 psi usually indicates high corrosion risk. Partial pressure 3-30 psi may indicates high corrosion risk. Partial pressure < 3 psi generally is considered non corrosive.
Hydrogen Sulphide (H2S) Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion. The combination of H2S and CO2 is more aggressive than H2S alone and is frequently found in oilfield environments. Other serious problems which may result from H2S corrosion are hydrogen blistering and sulphide stress cracking. It should be pointed out that H2S also can be generated by introduced micro-organisms. Temperature Like most chemical reactions, corrosion rates generally increase with increasing temperature. Pressure Pressure affects the rates of chemical reactions and corrosion reactions are no exception. In oilfield systems, the primary importance of pressure is its effect on dissolved gases. More gas goes into solution as the pressure is increased this may in turn increase the corrosivity of the solution. Velocity of fluids within the environment Stagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as the corrosion scale is washed off the casing exposing fresh metal for further corrosion. High velocities and/or the presence of suspended solids or gas bubbles can lead to erosioncorrosion, impingement or cavitation.
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4.13.4. Casing For Sour Service All temperatures (1)
150째 F (65째C) (3) or greater
175째 F (80째C) or greater
API Specification 5CT Grade API Specification 5CT Grade API Specification 5CT Grade H40, (2) K55 and J 55 N80 (Q and T) H40, N80 Grade C75 (2)
Grade C 95
Grade P110
Proprietary Grades:
Proprietary Grades:
Proprietary Grades:
see NACE standard
Q and T, with a maximum yield strength of 100,000psi
with 110,000psi
and L80
MR-01-75
(689,475kPa)
(758,420kPa) minimum to 140,000psi (965,265kPa) max. yield strength
Q and T = quenched and tempered. 1) 2) 3)
Impact resistance may be required by other standards and codes for low operating temperatures. 80,000 psi (551,580kPa) maximum yield strength permissible. The latest revision of API Specification 5CT includes this requirement. Continuous minimum temperature; for lower temperatures, select from column 1. Table 4.D - Operation Temperature
4.13.5. Ordering Specifications When ordering tubulars for sour service, the following specifications should be included, in addition to those given in the above table.
Note:
a)
Downgraded grade N 80, P 105 or P 110 tubulars are not acceptable for orders for J 55 or K 55 casing.
b)
The couplings must have the same heat treatment as the pipe body.
c)
The pipe must be tested to the alternative test pressure (see API Bulletins 5A and 5 AC).
d)
Cold die stamping is prohibited, all markings must be paint-stencilled or hot die stamped.
e)
Three copies of the report providing the ladle analysis of each heat used in the manufacture of the goods shipped, together with all the check analyses performed, must be submitted.
f)
Three copies of a report showing the physical properties of the goods supplied and the results of hardness tests (Refer to step 3 above) must be submitted.
g)
Shell modified API thread compound must be used. Recommendations for casing to be used for sour service must be specified according to the API 5CT for restricted yield strength casings.
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The casing should also meet the following criteria: • •
The steel used in the manufacture of the casing should have been quenched and tempered. (This treatment is superior to tubulars heated/treated by other methods e.g. normalising and tempering). All sour service casing should be inspected using non-destructive testing or impact tests only, as per API Specification 5CT.
4.13.6. Company Design Procedure CO2 Corrosion The following guidelines should be used for the appropriate corrosive environment. • •
In exploration wells, generally the presence of CO2 in the formation causes little problems, and will have no influence on material selection for the casing. In producing wells, the presence of CO2 may lead to corrosion on those parts coming in contact with CO2 which normally means the production tubing and part of the production casing below the packer.
Corrosion may be limited by: • •
The selection of high alloy chromium steels, resistant to corrosion. Inhibitor injection, if using carbon steel casing. Generally, wells producing CO2 partial pressure higher than 20 psi requires inhibition to limit corrosion.
H2S Corrosion In exploration wells, if there is high probability of encountering H2S, consideration should be given to limit casing and wellhead yield strength according to ‘API’ 5CT and ‘NACE’ standard MR-01-75. In producing wells, casing and tubing material will be selected according to the amount of H2S and other corrosive media present. Refer to figure 4.hand figure 4.i for partial pressure limits.
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Figure 4.H - Sour Gas Systems
Figure 4.I - Sour Multiphase Systems
0
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Figure 4.J - Sumitomo Metals
0
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Domain
Mild Environment
Domain ‘A’
Sulphide Stress Corrosion Cracking (medium pressure and temperature)
Domain ‘B’
Sulphide Stress Corrosion Cracking (high pressure and temperature)
Domain ‘C’
Wet CO2 Corrosion
Domain ‘D’
Material
Domain ‘E’
Domain ‘F’
SM 95G SM 125G
API
SM 80S SM 90S SM 95S SM 85SS SM 90SS SM C100 SM C110 SM 9CR 75 SM 9CR 80 SM 9CR 95 SM 13CR 75 SM 13CR 80 SM 13CR 95 SM 22CR 65* SM 22CR 110** SM 22CR 125** SM 25CR 75* SM 25CR 110** SM 25CR 125** SM 25CR 140** SM 2535 110 SM 2535 125 SM 2242 110 SM 2242 125 SM 2035 110 SM 2035125 SM 2550-110 SM 2550-125 SM 2550-140 SM 2060-110*** SM 2060-125*** SM 2060-140*** SM 2060-155*** SM C276-110*** SM C276-125*** SM C276-140***
L80 C90 T95 1Cr 0.5Mo Steel Modified AISI 4130
9Cr-1Mo Steel
22Cr 5Ni 3Mo Steel
25Cr 35Ni 3Mo Steel 22C 42Ni 3Mo Steel 20Cr 35Ni 5Mo Steel
Most Corrosive Environment
Domain ‘G’
SM’ Designation
J55 N80 P110 (Q125) Cr or Cr-Mo Steel
25Cr 6Ni 3Mo Steel
Wet CO2 with H2S Corrosion
0
API
13Cr Steel Modified AISI 420 Wet CO2 with a little H2S Corrosion
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Application
PAGE
25Cr 50Ni 6Mo Steel
20Cr 58Ni 13Mo Steel
16Cr 54Ni 16Mo Steel
(Refer to figure 4.j)
Notes
Higher yield strength for sour service
Quenched and tempered Quenched and tempered Duplex phase Stainless steels *
Solution Treated
** Cold drawn As cold drawn
As cold drawn
*** Environment with free Sulphur
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4.14.
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TEMPERATURE EFFECTS For deep wells, reduction in yield strength must be considered due to the effect on steel by higher temperatures. It no information is available on temperature gradients in an area, a gradient of 3째C/100m should to be assumed (Refer to section 2.3). Use figure 4.k below for reductions in yield strength against temperature.
Figure 4.K - Temperature Effects 4.14.1. Low Temperature Service Operations at low temperatures require tubulars made from steel with high ductility at low temperatures to prevent brittle failures during transport and handling.
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4.15.
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0
LOAD CONDITIONS When running casing, shock loads are exerted on the pipe due to: • •
Sudden deceleration forces (e.g.: if the spider accidentally closes or the slips are kicked-in when the pipe is moving or the pipe hits a bridge). Sudden acceleration forces (e.g.: picking the pipe out of the slips or if the casing momentarily hangs up on a ledge then freed).
Either of the above will cause a stress wave to be created which will travel through the casing at the speed of sound. This effect is quantified as follows: SL
=
150 x V x Af
SL
=
Shock load (lbs x ins2)
V
=
Peak velocity when running (ins/sec)
Af
=
Cross-sectional area (ins2)
150
=
Speed of sound in steel (lbs x sec/ins)
Where:
4.15.1. Safe Allowable Pull The safe allowable pull must be calculated and stipulated during the casing string design process and communicated to the well site prior to running casing, particularly, when reciprocating pipe during the cementing procedure. The application of the pulling load should only be considered as an emergency measure to retrieve the casing string from the wellbore. It is normal to incorporate in the casing string design an overpull contingency of 100,000lbs (45t), over the weight of the string in mud. 4.15.2. Cementing Considerations The cement sheath can protect the casing against several types of potential downhole damage including: • • •
Deformation through perforating gun detonations. Formation movement, salt flows, etc. (Refer to previous section 4.13). Loss of bottom joint on surface/intermediate strings during drilling.
However, the following aspects need to be considered: • •
Adding resistance to casing collapse for design purposes is questionable. In fault slippage zones, doglegs and certain sand control failures, the cement sheath may contribute to problems.
As a cement slurry is pumped into the casing, the weight indicator increases to a maximum when mud has been displaced from the casing by the full amount of cement. The maximum weight of the string occurs when the cement reaches the casing shoe or when the top cement plug is released.
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This weight increase can approach the remaining allowable pull in the string. If reciprocation is contemplated, this problem may be severe enough to prevent reciprocation and, hence stretching the pipe. After considering the above loading, the design engineer may decide that a higher allowable pull is required. For design calculation, a worst case situation is assumed as follows: • • •
The mud weight in the annulus is the lowest planned for the section. The inside of the casing is full of cement slurry, with mud above. The shoe instantaneously plugs-off just as the cement reaches it and the pressure rises to a value of circa ‘1,000psi’ before the pumps are able to be shut-down.
The load is calculated as follows: CCL = [(Cw - Mw) x D + 1000] x Ai where: CCL
=
Cementing contribution load (lbs)
Cw
=
Cement weight (psi/ft)
Mw
=
0utside mud weight (psi/ft)
D
=
Length over which Cw & Mw act(ft)
Ai
=
Internal area of casing (ins2)
1,000
=
Pressure increment (psi)
4.15.3. Pressure Testing Casing pressure tests will be carried out according to the pressure stated in the drilling programme. When establishing an internal casing pressure test, the differential pressure due to a difference in fluid level and/or fluid density, inside and outside the casing, shall be taken into account. Each casing shall be pressure tested at the following times: • • •
When cement plug bumps on bottom with a pressure stated in the drilling programme. When testing blind/shear rams of the BOP stack against the casing. After having drilled out a DV collar.
4.15.4. Company Guidelines The leading criteria for pressure testing will be the maximum anticipated wellhead pressure. In all cases the test pressure will be no higher than 70% of API minimum internal yield pressure of the weakest casing in the string or to 70% of the BOP WP. The test pressure shall remain stable for at least 5 - 10 minutes.
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4.15.5. Hang-Off Load (LH) The Hang-off load required for a casing is obtained as per algebraic amount of the following loads: LH= Pa + L1 + L2 + L3 + Fc Where: Pa = weight in air of the not cemented casing L1 = stress due to variation of internal pressure L2 = stress due to variation of external pressure L3 = stress due to variation of average temperature Fc = critical force (take into account only if it is positive) l1a = -0.6 ID2 π/4 (γ2 - γ1)/2 H/10 L1 = l1b = 0.03 ID2 π/4 (2N – N2/10) γ0 2 l1c = -0.6 ID π/4 Pi
(for inside casing mud weight variation) (for inside casing mud level drop) (for inside casing pressure applied)
l2a = 0.6 OD2 π/4 (γ2 - γ1)/2 H/10 L2 = l2b = 0.03 OD2 π/4 (2M – M2/H) γ0 l2c = 0.6 OD2 π/4 OD2 Pe
(for outside casing mud density variation) (for inside casing mud level drop “m”) (for outside casing pressure applied)
L3 = 26 (OD – ID ) π/4 ∆tm ; with
∆tm = ∆tm2 - ∆tm1 ∆tm1 = tf1 + (ts1-tf1)/2 H/S ∆tm2 = tf2 + (ts2-tf2)/2 H/S2
2
2
Fc = Pi ID2 π/4 – Pe OD2 π/4 H = uncemented casing length ID = inside diameter M = outside casing mud level drop N = inside casing mud level drop OD = outside diameter Pi = inside pressure applied at casing head Pe = outside pressure applied at casing head S = casing setting depth S2= end of the next phase tf1= flow line mud temperature when the well is at “S” ts1= static bottom hole (S) temperature tf2= flow line mud temperature when the well is at “S2” ts2= static bottom hole (S2) temperature γ 0 = mud density at the time of the inside casing mud level drop γ 1 = mud density during cementing job γ 2 = max mud density during the next drilling phase ∆ tm = temperature total variation ∆ tm1 = variation of temperature at shoe depth ∆ tm2 = variation of temperature at the end of the next phase
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5.
MUD CONSIDERATIONS
5.1.
GENERAL
0
For full information on drilling fluids preparation, refer to Eni-Agip’s Drilling Fluids Manual.
5.2.
a)
A detailed mud programme shall be included as an integral part of the drilling programme.
b)
A Mud Service Contractor may be contracted for the preparation of the mud programme, which shall be submitted to the Company Drilling Office for approval before to integrate into the Drilling Programme.
c)
The same Contractor may be contracted for Mud Engineering on rig site under the control of the Company Drilling and Completion Supervisor.
d)
No variation from the mud program is permitted without previous discussion with and approval of the Company Shore Base Drilling office.
e)
The mud characteristics to be used for specific operations, such as tripping, casing running, etc., shall be based on specifications described the relevant sections of the Drilling Programme.
DRILLING FLUID PROPERTIES Drilling fluids serve many purposes but their primary functions are to • • • • • •
5.2.1.
Lift formation cuttings to surface Control subsurface pressures Lubricate the drill string Clean the hole Aid in formation evaluation Protect formation productivity
Cuttings Lifting Clearing the hole of cuttings is an essential primary function of a drilling fluid system and is often the most misinterpreted and abused. Drill solids are heavier than the mud and will tend to slip downward against the flow. This slip velocity when the fluid is in viscous of laminar flow is directly affected by the thickness or shear characteristics of the mud. The relationship between mud velocity and thickness to enable cutting removal is important and if velocity is low due to pump rate or enlarged hole sections, then the mud must be thickened and vice versa. Water based muds are thickened by adding bentonite, large volumes of solids, flocculation or by the use of special additives. This provides the operator with a choice of options, however the use of bentonite is the most popular as it is relatively cheap. When using bentonite, sometimes a thinner needs to be added to prevent flocculation and water loss control problems. The use of large quantities of solids is an undesirable solution if it is not required to increase mud weight for subsurface pressure control. Usually a mud selection is a compromise of all the various problem solutions and often the lifting capability is not effective. What may have begun as a simple mud thickening problem is complicated by the resulting effects on the other mud objectives.
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5.2.2.
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Subsurface Well Control It is always desirable to utilise the lowest possible mud weight to achieve maximum drilling rate and lost circulation problems are minimised. However, the hydrostatic pressure applied by the mud must be greater than the highest formation pressures to effect pressure control. To determine the mud weight required, it is necessary to obtain predicted formation pore pressures and the fracture gradient. The mud weight selected must exceed the formation pore pressures in each section but to minimise drilling problems and still not exceed the fracture pressure. This is sometimes a fine balancing act between satisfying well control and not exceeding the rock strength in weak zones. Formation pressure and temperature prediction is usually found be using offset well data but can also be predicted (refer to section 2). Normal formation pressure gradients are 0.465psi/ft but vary from region to region. It is important that overpressure are predicted and monitored for during drilling. Once the formation pressures for a section are known, a safety margin must be added and then mud weight calculated:
MW =
PF +SafetyM arg in TVDĂ&#x2014; 0.052
where: MW
=
Mud weight, ppg
PF
=
Formation pressure, psi
TVD
=
True vertical depth, ft
Example: A formation pressure has a pressure of 4,020psi at 8,500ft, a safety margin of 600psi is desired, what is the required mud weight ?.
MW =
4,020psi+600psi = 10.42ppg 8,500 ftĂ&#x2014; 0.052
Safety margins are usually around 0.2ppg but may vary according to conditions. Example, a mud with a 700psi safety margin at 10,000ft will only provide a 350psi margin at 5,000ft. It may be decided to use an increased mud weight at the shallower depths if the margin is too small. To calculate pressure at a given depth and mud weight the calculation is:
PH = 0.052 x MW x TVD Mud weight is increased by the addition of heavy solids.
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5.2.3.
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Lubrication Lubrication and cooling are also important functions of the mud. Working life of expensive equipment can be prolonged by adequate cooling and lubrication. Problems such as excessive torque, drag and differential sticking are also reduced. Lubricants include bentonite, oil, detergents, graphite, asphalts, special surfactants and walnut shells. Bentonite acts as a lubricant by reducing friction between the wall cake and the drill string. Oil is less used today due to the environmental impact and disposal problems and similar to graphite as it also requires oil as a carrier. Asphalt is usually added for its other properties but also acts as a lubricant. Surfactants have been claimed to lubricate but this should be analysed as they are more expensive.
5.2.4.
Bottom-Hole Cleaning Thin fluids with high shear rates through the bit are the most effective at hole cleaning and means that viscous fluids can be used if they have shear-thinning characteristics. In general fluids with low solids contents are more effective in hole cleaning.
5.2.5.
Formation Evaluation Drilling fluids have been effect greatly by the requirement for quality formation evaluation. Viscosity may be increase to ensure improved cutting lift, filtration may be reduced to reduce fluid invasion or special fluids used instead of the mud system for logging and well testing. The procedures for mud conditioning before logging have become standard today. The type of mud will also have an effect, e.g. oil based mud make evaluation of potential producing formations difficult and salt water fluids can mask permeable zones. Thick filter cake can interfere with side wall coring information and water or oil invasion affects resistivity logs. The formation evaluation programme must take all of these considerations into account to obtain the best results.
5.2.6.
Formation Protection In the past it has been proven that the drilling process and fluids will cause damage to producing formations and the utmost precautions should be taken to minimise this damage. The ideal protection policy is to keep all foreign fluids away from the formation, however in most cases this is impractical, unless air drilling, and hence the drilling fluid should be selected according to conditions. For instance, oil based mud can be used when it is desirable to keep water off a zone, however oil based mud may be more damaging to gas zones than salt water fluid, etc. Salt water fluid with high calcium content have also been effective. To help minimise invasion, reduction in the filtration rate may be employed but reliance on static surface testing as assurance may be misleading on actual downhole filtration rates.
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5.3.
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MUD COMPOSITION The composition of drilling mud is a mixture of the base fluid (see the list of liquids below), solids and chemical additives. • • • •
Fresh Water Salt water Oil Mixture of above
The base fluid for most muds is fresh water as it is usually readily available and is cheap. Seawater has become more widely used due to the increase in offshore drilling for obvious reasons. Oil based mud is very popular when it is desired to reduce the amount of water in the system. Two types of oil based mud are available, an oil mud that has less than 5% water by volume and invert emulsion which is between 5 and 50%. 5.3.1.
Salt Muds Salt added to water will provide a range of weights according to the type and amount of salt added. The maximum weight ranges for various types of brines are: Kcl
up to 9.6ppg (1,150kg/m3)
NaCl2
up to 10.0ppg (1,200kg/m3)
CaCl2
10.0 to 11.6ppg (1,200-1,390kg/m3)
The following figures show amount of salt and water required to achieve the range of brine densities.
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Figure 5.A - Material Required For Preparation Of Potassium Chloride Solutions (20o)
Figure 5.B - Material Required For Preparation Of Sodium Chloride Solutions (20o)
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Brine weight is affected by temperature and it is necessary to obtain the average well temperature in order to determine the density reduction from that when it was prepared at surface. figure 5.c below shows brine densities at various temperatures. Average well temperature =
Bottom hole temp + Top hole temp 2
Figure 5.C - Density Vs Temperature For Brine
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If drilling through salt beds or sections, the drill fluid should be saturated which will preserve hole geometry avoiding enlargement. When working with salt at saturation point, it is not uncommon to find salt deposited in the lines and surface tanks with temperature drop. For brine densities below 1,050kg/m3, it is recommended to include 1-3% by weight of KCl in the brine formulation to inhibit interaction between the fluid and water sensitive clays in the formation. Potassium is rarely used in concentrations above 0.4ppg as sodium chloride may be used which is considerably cheaper. Sodium chloride is a cheap brine and has good solubility which varies little with temperature. Calcium chloride is used in the higher weight range but should be prepared with seawater as precipitates may form and the sodium chloride content may crystallise if the weight range is above 1,320kg/m3. 5.3.2.
Water Based Systems High weight mud systems usually contain more solids than low weight systems. Extra solids in high weight mud originate from the gels, chemicals, weight material and drill solids from the rock. Good solids control systems and the proper addition of water and chemicals will eliminate solids build up and problems. figure 5.d shows a field developed guidelines for solids level in water muds.
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Figure 5.D- Guidelines for Clay Based Mud Systems 5.3.3.
Gel Systems The commercial clays added to the mud system are bentonite and attapulgite. Bentonite is added to increase viscosity, gel strengths and suspension. filtration and filter cake properties are also improved with bentonite. Drilled solids also enter the system during drilling. If flocculation of bentonite occurs then a dispersant should be added. Attapulgite is used where bentonite does not react properly.
5.3.4.
Polymer Systems Polymers have been used mainly in completion and workover operations requiring minimum solids content, hence reducing formation damage.
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Oil Based Mud As pointed out earlier oil based muds are used to reduce torque and/or drag beneficial in drilling directional wells and where water based muds may cause hole damage such as in shales. Oil mud is only less damaging if the water phase is dosed with salt to a higher concentration of that in the formations to prevent the water being pulled out and, hence causing sloughing. The salt used for this is usually calcium chloride due to its good solubility properties. Lime must be added to oil mud to convert sodium salts into calcium soaps and combat problems associated with carbon dioxide and hydrogen sulphide intrusion. Changing from water based to oil based mud may cause contamination in long sections of open hole will have absorbed a considerable amount of water, therefore should be restricted to cased hole only. Oil based mud was treated as special purpose mud due mainly to its high cost in comparison to water based mud, however with todayâ&#x20AC;&#x2122;s restocking arrangements available with the suppliers it has become much more economic. In general terms, the costs of drilling with oil based mud is considered to be 30% less than for comparable water based weight mud thought to be due getting more efficient weight on the bit. The hindrance to the use of oil based mud is the environmental disposal of coated cuttings.
5.4.
SOLIDS Solids are divided into two groups, low and high gravity. The low gravity solids are further subdivided into reactive and non-reactive groups. Reactive and non- reactive refers to whether they react to changing downhole conditions. Low gravity solids include sand chert, limestone, dolomite, some shales and mixtures of other minerals. Non-reactive solids are undesirable and if larger than 15 microns in size, they are erosive to circulating equipment. The size of solids in microns and inches with the appropriate screen sizes are given in table 5.a below: Microns
Inches
Shaker Screen Size
1540
0.0606
12 x 12
1230
0.0483
14 x 14
1020
0.0403
16 x 16
920
0.0362
18 x 18
765
0.0303
20 x 20
Table 5.A - Solids Size Versus Screen Size Reactive solids are clays which are reactive to water. The most common clays used are bentonite or gel and attapulgite (salt gel). Bentonite is used to both add thickness and viscosity to the mud and control fluid loss.
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DENSITY CONTROL MATERIALS To drill a well successfully, the formation pressure must be controlled by the hydrostatic weight of the mud. A mud system will normally gain weight due to the addition of drilled solids if proper mechanical solids control equipment is not used or is inefficient. These solids are undesirable in high mud weight systems as they cause problems when weighting materials are added. Common weighting materials are shown in table 5.b below: Material
Average SG
Max Mud Weight (ppg)
Barite
4.25
20-22
Lead Sulphide
6.6
28-32
Calcium Carbonate
2.7
12
Ilmenite
4.5
21-26
Hematite (Itagrite ore)
5.1
24-26
Table 5.B- Common Weighting Materials Water based fluids can be weighted up by salts. 5.6.
FLUID CALCULATIONS The following equations are provided for an engineer to be able to calculate material requirements, stock levels and mud weights. The symbols listed below are used in the following equations and examples. These or variations in these may be found in any drilling fluids handbook. WO
=
Weight of original mud, lbs
WA
=
Weight of material added, lbs
WF
=
Weight of final mud, lbs
VO
=
Volume of original mud, gal
VA
=
Volume of material added, gal
VF
=
Volume of final mud, gal
DO
=
Weight of original mud, ppg
DA
=
Weight of material added, ppg
DF
=
Weight of final mud, ppg
w
=
Weight of material added to original mud, lbs/bbl
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Calculation of solids material required to increase mud weight. Equation:
w=
42(D F −D O ) D 1− F DA
Example: A mud system contains 750bbl of 10.4ppg mud, how many sacks of barite are required to increase the density to 12.4 ?.
w=
42 (12.4 − 10.4 ) = 130lb / bbl 12.4 1− 35.4
Total barite required:
=
750 bbl x 130 lbs / bbs 100lbs / sk
= 975
Calculation of density resulting from adding liquid to decrease mud weight. Equation:
DF = D O −
VA (D O − D A ) VF
Example: A mud system contains 800bbl of 11.3ppg mud, what is the resulting density of adding 100bbl of 42o API oil ?. Calculate SG of oil:
SG=
141.5 =0.816SG 42+131.5
Calculate density of oil:
D A = 0.816 x 8.33 = 6.80ppg Calculate VF: VF = 800 bbl + 100 bbl = 900 bbl 100 (11.3 − 6.80) 900 = 10.8 ppg
D F = 11.3 −
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Calculation of density by adding solids to a mud. Equation:
w 42 DF = w 1+ 42 x D A DO +
Example: 10 tons of barite were added to 800bbl of 9.2ppg mud, what was the final density of the mud ?. First calculate w: 10 t x 2,000 lbs 800 bbl = 25lbs / bbl
w=
Calculate final density: 25 42 DF = 25 1+ 42 x 35.4 = 9.63ppg 9 .2 +
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5.7.
PAGE
0
MUD TESTING PROCEDURES The following table summarises the common mud field testing procedures. Refer to API RP 13B for Standards Mud Testing Procedures. Test
Water Based Mud
Oil Based Mud
Mud weight
Mud balance
Mud balance
Viscosity
Marsh funnel & graduated cup
Marsh funnel & graduated cup
Sand content
Sand content kit
N/A*
Rheology n(PV, YP)
Viscometer
Viscometer
Shear strength (nonpressurised
Shearmeter
Shearmeter
Low pressure filtration (100psi)
API filter press
Usually not applicable except with a relaxed filtration mud
High pressure filtration
HP/HT Press
HP/HT Press
Static pressure filtration
High temperature pressurised aging cells
High temperature pressurised aging cells
Hydrogen ion determination
Modified calorimetric method (pHydrion dispenser) or electrometric method (pH meter)
N/A*
Oil, water, solids determination
Retort kit
Retort kit for determination of O/W ratio
Bentonite content
Methylene blue kit
N/A*
Chloride content
Potassium chromate, silver nitrate
N/A*
Water phase salinity and total soluble salts
N/A*
Measurement of calcium chloride and sodium chloride content %BWOW
Alkalinity
N-50 sulphuric acid, phenolphthalien or methyl orange
N/A*
Calcium and magnesium
Versentate hardness test
N/A*
Electrical stability
N/A
Voltage breakdown meter
* Not applicable in most cases or is not customarily evaluated. Table 5.C - Common Mud Testing Equipment and Chemicals
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The following mud properties in the units shown below shall be included in the Drilling programme. These shall be clearly checked, recorded; and also reported to Company Drilling Office on a daily basis:
5.8.
Weight Temperature (especially in oil mud) Funnel viscosity Plastic viscosity Yield point Gel strengths
kg/l 째C secs/gal/4 centipoise g/100cm2 g/100cm2
Water losses Filter cake Sand content Solids content Oil content Calcium content
cm /30mins millimetres % by volume % by volume % by volume mg/l Ca++
Salinity
g/l Cl-
3
MINIMUM STOCK REQUIREMENTS a)
Minimum stock requirements for mud weighting materials, chemicals, pipe freeing agent, dispersant, lost circulation material, cement, kill and reserve mud on the rig, depends on the well pressure prognosis, severity of potential drilling problems and rig load capacity.
b)
The minimum barite stock shall be 100t. When overpressurised formations are anticipated, barite stock shall be based on expected formation pressure gradients, on the actual mud weight and on the volume of the active drilling fluid in the system.
c)
The minimum cement stock shall be 100t. or at least enough to prepare 200m of cement plug.
d)
A minimum volume of 70m3 of kill mud at 1.4kg/l shall be stocked while drilling surface hole without a BOP stack installed.
e)
After nippling up a BOP stack, minimum requirements for kill mud cannot be specified. The volume and density of kill mud shall be adjusted to the well pressure prognosis and pit volumes available on the rig.
f)
Properties of reserve and kill mud should be checked and maintained daily and recorded the mud report.
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0
In addition, the following material is recommended to be available on board for contingencies: • • • • • •
A stock of diesel oil, enough to guarantee five day of operations. Pipe freeing agent. The quantity shall be sufficient to prepare two pills, the volume of each one shall be two times the capacity of the annulus open hole/BHA. Dispersant - 20 drums Mica (fine, medium and coarse) -1.5t of each Wall Nut - 3t Viscosifier for salt water (i.e. Biopolymer): the quantity shall be enough to prepare 200m3.
The inventory of materials on board should be reviewed daily and replenishment arranged immediately when stock levels approach the specified minimum requirement. With regard to barite, cement and diesel oil, should the stocks fall below the minimum requirement, drilling operations shall be suspended.
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6.
PAGE
0
FLUID HYDRAULICS The Eni-Agip IWIS (ADIS) software programme is currently used for all hydraulic programmes and provides all the necessary information to be input into the ‘Geological Drilling Programme’. However it is necessary for drilling engineers to be armed with sufficient information to use the ADIS programme and plan for drilling operations. There are some company guidelines that are helpful in fulfilling this objective outlined in the following sub-sections but more detailed information can be found in the company’s ‘Mud Manual’.
6.1.
HYDRAULICS PROGRAMME PREPARATION Before the design of a hydraulics programme can commence, the following information about the well and drilling equipment should be ascertained: a)
Drilling contractor
b)
Drilling unit
c)
Hole sizes
d)
Depth intervals
e)
Mud weights at the various depths
f)
Whether plastic viscosities are expected
g)
Pumps:
h)
• Manufacturer, type and model • Number of pumps • Horsepower available • Liner sizes available • Max pump speed • Min pump speed • Max pump pressure. Minimum annular velocity
i)
Length and ID of standpipe, swivel, kelly hose and kelly (or top drive)
j)
Drill string design
k)
Priority for the hydraulics programme, i.e. max bit hydraulics, max jet impact force, constant pump speed or variable pump speed
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DESIGN OF THE HYDRAULICS PROGRAMME The first priority of a hydraulics programme is to maximise bottomhole cleaning. Hydraulic design methods include: • • • •
Hydraulic Impact Bit Hydraulic Horsepower Nozzle Velocity A combination of these Methods
Regardless of the design method to be used, the first step is to determine the maximum surface hydraulic horsepower available. This is calculated by using the following equation:
Hp =
PQ 1741
where: Hp
=
Surface horsepower available
P
=
Maximum permitted surface pressure
Q
=
Maximum flow rate
The following example illustrates a typical calculation: Maximum permissible surface pressure: 3,000psi Maximum flow rate:
600gpm
Available horsepower:
Hp =
3000 × 600 = 1,034 1741
If the pump size is 1,500HP then it is capable of delivering the required 1,034HP: 6.3.
FLOW RATE The flow rate must be maintained high enough to achieve two functions, to provide enough velocity to remove cavings and cuttings and the jetting requirements of the bit for each hole section. Upward flow velocities of 100-200ft/min are usually sufficient in normal conditions. Obviously this demands much higher circulation volumes when drilling larger hole sizes. The recommended flow rates for the standard bit size are given in table 6.a:
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Hole Size [ins]
Flow Rate [l/min]
1
3,000-4,000 2,800-3,500 2,200-2,600 1,500-1,900 1,200-1,600 1,200-1,600 800-1,000 600-800
17 /2” 15” 121/4” 97/8” 81/2” 77/8” 63/4” 6”
Table 6.A- Rates for the standard casing design Optimum annular velocity can also be calculated by the following equation: Optimum Annular Velocity =
11.8 MW + DH
where: MW
=
Mud weight, lbs/gal
DH
=
Diameter of hole, inches
From a given flowrate, annular velocity can be calculated as follows: Annular Velocity =
24.51(Q) DH2 − DP 2
where: Q
=
Flow, gal/min
DH
=
Diameter of hole, ins
DP
=
Diameter of pipe, ins
The flow rate must also maintain good hole condition so that erosion does not occur or cause invasion of formations that may damage potential producing zones. Rates of circulating above that necessary simply to maintain good hole conditions can be used to obtain faster drilling rates. The additional horsepower and pumping equipment required for this due to increased friction losses must be justified to ensure economy. Critical annular velocity is expressed by: Critical Annular Velocity =
[
(
64.8 PV + 3.04 × DH − DP ×
where: PV
=
Plastic velocity
YP
=
Yield point
(DH − DP) × MW
(YP × MW ))]
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PRESSURE LOSSES Pressure losses are calculated using Bernoulli’s Theorem. Considering two points in a circulating system, the following equation may be used:
h1
U12 2g
+
U 2 p p1 − F + W = h2 2 + 2 − F + W ρ1 2g ρ2
where: h
=
Height above a chosen reference elevation, ft
U
=
Flow velocity, ft/sec
P
=
Pressure of the fluid, lbs/ft2
ρ
=
Density of the fluid, lbs/ft3
g
=
Acceleration of gravity 32ft/sec2
F
=
Sum of flowing pressure losses
W
=
Sum of mechanical energy added
In a mud system, as h1 and h2 are at the same height they cancel each other and the velocity values are negligible, therefore the equation is reduced to: W=F ‘W’ represents the hydraulic horsepower that must be applied to the mud with ‘F’ representing the fluid pressure losses in the system and the nozzles of the bit. Bernoulli’s theorem may be used for the whole circulating system or just part of the system such as the nozzles of the bit. The total friction losses caused by the surface equipment, drill string and annuli can be summed up as: Ps = Ps.e + Pd p. + Pd.c + Pb + Pd.c.a + Pd.pa where: Ps
=
Total pressure drop
Ps.e
=
Pressure drop in the surface equipment
Pd p.
=
Pressure drop in the drill pipe
Pd.c
=
Pressure drop in the drill collars
Pb
=
Pressure drop in the bit
Pd.c.a
=
Pressure drop in the hole and drill collar annulus
Pd.pa
=
Pressure drop in the hole and drill pipe annulus
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Each of the pressure drops for a particular section can be obtained by calculation or from using industry standard tables if the mud properties of rheology and weight are known. The pressure drops also depend largely on whether the flow regime is laminar or turbulent. This aspect and all of the pressure drops in a system are calculated by the ADIS software programme Any alteration in the mud properties or drill string design or bit nozzle area will in turn alter the hydraulic programme. Suitable assumptions must be made for contingency in order that the available pump horsepower is sufficient to cater for most circumstances which may arise. Before pressure drops can be calculated, it is necessary to determine whether flow is laminar or turbulent and the plastic viscosity correction factor. To determine if flow is laminar or not, it is necessary to find out the Reynolds number by: Reynolds number (Rn) =
15.47 × MW × AV (DH − DP ) µ
where: µ
=
300Kη-1
κκ
=
σ300 300
η
=
3.322 log
ρ
=
1.41 × AV DH − DP
σ600
=
2PV + YP
σ300
=
PV + YP
σ600 σ300
If the Reynolds number is less than 2,000 flow is laminar and over 4,000 is turbulent. Laminar flow annulus pressure loss is calculated by: Laminar annular pressure loss (psi) =
L × YP L × AV × PV + 225 (DH − DP) 90000 (DH − DP ) 2
Turbulent annular pressure loss (psi) = where: L
=
Length, ft
(1.4327 × 10 −7 ) MW × L × AV 2 DH − DP
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The plastic viscosity correction factor is found from the following figure 6.a
Figure 6.A - Plastic Viscosity Correction Chart
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6.4.1.
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0
Surface Equipment The lengths and IDs of the surface lines, manifolds, standpipe, kelly or top drive will cause a friction drop. Each of these parameters need to be known for input into the ADIS programme. Pressure drop in pipe bore (psi) =
6.4.2.
0.00061 × MW × L × Q1.86 ID1.86
Drill Pipe If a parallel or tapered drilling string is used, the length of each section for varying depths needs to be determined for each individual size of pipe and then the pressure drops in each combined to obtain the total pressure drop of the string. The calculation is the same as that given in the previous subsection.
6.4.3.
Drill Collars Similar to the drill pipe above, the various lengths of drill collar IDs need to be known, the pressure drop for each length calculated and then added.
6.4.4.
Bit Hydraulics The jetting action across the bit nozzles must be sufficient enough to clean the cuttings away from the bit and up into the hole/drill collar annulus. Eni-Agip recommends that the minimum nozzle velocity is 100m/sec. Further to this, the following is the recommended hydraulic horsepower delivery for roller cone bits in the most common hole sections: 8 ½”
=
8-9 HHP/ins2
12 ¼”
=
5-6 HHP/ins2
17 ½”(16”)
=
3-4 HHP/ins2
The pressure drop across the nozzles are calculated by: Pressure Drop Across Nozzles =
MW × Q 2 10858 × TFA
where: TFA
=
Total flow area, sq ins
Bit HHP can be calculated by: Bit HHP/in = 2
∆P × Q 1346.2 × DH
Jet impact force is calculated by: Jet Impact Force (lbs) = 0.000516 × MW × Q × VJet
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Jet Size
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TFA Of 1 Jet
TFA Of 2 Jet
TFA Of 3 Jet
TFA Of 4 Jet
TFA Of 5 Jet
TFA Of 6 Jet
TFA Of 7 Jet
TFA Of 8 Jet
TFA Of 9 Jet
7
.038
.076
.114
.152
.190
.228
.266
.305
.342
8
.049
.098
.147
.196
.245
.295
.344
.393
.442
9
/32” /32”
.062
.124
.186
.249
.311
.373
.435
.497
.559
10
/32”
.077
.153
.230
.307
.383
.460
.537
.614
.690
11
.093
.186
.278
.371
.464
.557
.650
.742
.835
12
.110
.221
.331
442
.552
.663
.773
.884
.994
13
.130
.259
.389
.518
.648
.778
.907
1.037
1.167
14
.150
.300
.450
.600
.750
.900
1.050
1.200
1.350
15
.172
.344
.516
.688
.860
1.032
1.204
1.376
1.548
16
.196
.392
.588
.784
.980
1.176
1.372
1.568
1.764
18
.249
.498
.747
.996
1.245
1.494
1.743
1.992
2.241
20
.307
.613
.921
1.228
1.535
1.842
2.148
2.455
2.762
22
.371
.742
1.113
1.484
1.855
2.226
2.597
2.468
3.339
24
.441
.883
1.325
1.767
2.209
2.650
3.092
3.534
3.976
/32” /32” /32” /32” /32” /32” /32” /32” /32” /32” /32”
Table 6.B- TFA Comparison (Total Flow Area) 6.4.5.
Mud Motors If mud motors are used, the HHP required will be provided by the supplier and must be added into the total pressure drop of the system.
6.4.6.
Annulus Pressure loss calculations for the annulus between the hole/drill collar annulus and the hole/drill pipe annulus need to be carried out by inputting the collar ODs, drill pipe ODs and corresponding lengths as follows: Turbulent Flow Annulus Pressure Loss (psi) =
(1.4327 × 10 ) × MW × L × AV −7
DH − DP
The equivalent circulating density is calculated: Equivalent Circulating density = MW +
Total Annular Pr essure Drop × 19.25 True Vetical Depth
2
.
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USEFUL TABLES AND CHARTS Mud lbs/gal
Weight lbs cu ft
g/cc or sp gr
8.34 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
62.3 67.3 74.8 82.3 89.8 97.2 104.7 112.2 119.7 127.2 134.6 142.1 149.6 157.1 164.6 172.1 179.5
1.00 1.08 1.20 1.32 1.44 1.56 1.68 1.80 1.92 2.04 2.16 2.28 2.40 2.52 2.64 2.76 2.88
Buoyancy Correction factor .873 .862 .847 .832 .817 .801 .786 .771 .755 .740 .725 .710 .694 .679 .664 .649 .633
Table 6.C - Buoyancy Factors lbs/gal 7.5 8.0 8.3 8.5 9.0 9.5 10.0 10.5 11.0 11.5 12.0 12.5 13.0 13.5
lbs per cu ft 56.0 59.8 62.4 63.4 67.5 71.1 75.0 78.5 82.5 86.0 90.0 93.6 97.5 101.0
SG 0.90 0.96 1.00 1.02 1.08 1.14 1.20 1.26 1.32 1.38 1.44 1.50 1.56 1.62
psi per 1,000 ft 389.6 415.6 431.2 441.6 467.5 493.5 519.5 545.5 571.4 597.4 623.4 649.3 675.3 701.3
lbs/gal 14.0 14.5 15.0 15.5 16.0 16.5 17.0 17.5 18.0 18.5 19.0 19.5 20.0
lbs per cu ft 150.0 108.5 112.3 115.9 120.0 123.4 127.5 130.9 135.0 138.3 142.1 145.8 149.6
Table 6.D - Conversion Units for Various Mud Weights
SG 1.68 1.75 1.80 1.86 1.92 1.98 2.04 2.10 2.16 2.22 2.28 2.34 2.39
psi per 1,000 ft 727.3 753.2 779.2 805.2 831.2 857.1 883.1 909.1 935.1 961.0 987.0 1013.0 1039.0
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Pipe OD (ins) 7
2 /8 7
2 /8 7
2 /8 1
3 /2 1
3 /2 1
3 /2 4 4 4
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Tool Joint
Nominal Weight
Connector
ID (ins)
ID(ins)
IF
1
2.225
6.5 10.4 10.4 13.3
Equivalent
12 /8
2.14
IF
1
2.15
7
2.74
11
2.76
9
2.60
FH
13
2 /16
3.29
IF
1
3.34
FH
11
2 /16
3.18
1
3 /2
3.24
IF
15.5
IF
14.0 14.0 15.7
7
XH FH & XH
13.3
2 /8 2 /8 2 /16 2 /16 2 /16 3 /4
4
15.7
IF
1
16.6
FH
3
3.76
FH
5
3 /32
3.79
XH
1
3 /2
3.78
3
4 /2 1
4 /2 1
4 /2
16.6 16.6
1
4 /2
16.6
IF
3 /4
3.82
1
20.0
FH & XH
3
3.56
IF
5
3 /8
3.64
XH
3
3 /4
4.23
XH
1
3 /2
3.97
REG
3
4.40
13
3 /16
4.6-
4 /2 1
4 /2 5 5 1
5 /2
20.0 19.5 25.6 21.9
1
5 /2
21.9
FH
1
21.9
FH
5 /2 1
5 /2
21.9
1
24.7
5 /2
4
4.75
IF
13
4 /16
4.80
FH
4
4.60
1
3 /2
5.52
5
5.88
29
5.96
5
6 /8
25.2
REG
5
25.2
FH
6 /8 5
6 /8
25.2 For Drill Collar Bores
2 /4
IF
5 /32 Same as ID
Table 6.E - Drill Pipe Sizes Metric and Imperial
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CEMENTING CONSIDERATIONS The objective of the primary cementing process, to place cement in the annulus between the casing and the formations exposed to the wellbore, is to provide zonal isolation. To achieve this, a hydraulic seal must be obtained between the cement and the casing and between the cement and the formations at the same time preventing fluid channels in the cement sheath. This requirement makes the primary cementing operation the most important performed on the well. To this end, it is vital, that engineers are provided with sufficient information and guidelines so that they can plan and conduct successful cementing operations preventing the need to conduct remedial operations which may be damaging to the well and costly in terms of lost rig time. This section provides information, guidelines and the basic calculations necessary to achieve this.
7.1.
CEMENT
7.1.1.
API Specification Portland cement is the most widely used in cementing operations in the oil industry and an API specification (10) was established. API 10 consists of eight classes of cement, A through H, to provide standard to suit a range of well conditions. The API classification system is shown in table 7.a below:
API Class
Mixing Water
Slurry Weight
Static BHP Temperature
Well Depth
o
F
o
gal/sk
ltrs/sk
lbs/gal
kg/ltrs
ft
m
C
A
5.2
19.7
15.6
1.87
0-6,000
0-1,830
80-130
27-77
B
5.2
19.7
15.6
1.87
0-6,000
0-1,830
80-130
27-77
C
6.3
23.8
14.8
1.77
0-6,000
0-1,830
80-170
27-77
D
4.3
16.3
16.4
1.97
6,000-12,000
1,8303,660
170-260
77-127
E
4.3
16.3
16.4
1.97
6,000-14,000
1,8304,270
170-290
77-143
F
4.3
16.3
16.4
1.97
10,000-16,000
3,050-4,880
230-320
110160
G
5.0
18.9
15.8
1.89
0-8,000
0-2,440
80-200
27-93
H
4.3
16.3
16.4
1.97
0-8,000
0-2,440
80-200
27-93
Table 7.A - API Cement Specification Class A
Is intended for use when no special properties are requires.
Class B
Has the same properties as class A except has a moderate to high sulphate resistance (MSR and HSR).
Class C
Is intended for use when conditions require high early strength.
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Classes D, E and F are referred to as retarded cements developed for higher temperature and pressures conditions. Class D
Intended for use in moderately high temperatures and pressures and is available in both MSR and HSR.
Class E
Intended for use in high temperature and pressure conditions and is available in both MSR and HSR.
Class F
Intended for use in extreme high temperature and pressure conditions and is available in both MSR and HSR.
Classes G and H were developed in response to the improved technology in slurry acceleration and retardation by chemical means. These are the most widely used cements today. Class G, H Intended for use as a basic well cement to cover a wide range of well depths and temperatures and is available in both MSR and HSR. Types G and H are essentially identical except that H is significantly coarser than G, evident from their different water requirements. The following table 7.b shows the various properties of neat slurries and API cement. API Class
Water
Slurry Weight
Slurry Volume
gal/sk
ltrs/sk
lbs/gal
kg/ ltrs
Ft3/sk
m3/sk
ltrs 3/sk
A&B
5.2
19.7
15.6
1.87
1.18
0.033
0.33
C
6.3
23.9
14.8
1.77
1.32
0.037
0.37
G
5.0
18.8
15.8
1.89
1.15
0.033
0.33
h
4.3
16.3
16.4
1.97
1.06
0.030
0.30
D, E & F
4.3
16.3
16.4
1.97
1.06
0.030
0.30
Table 7.B - Properties of Neat Slurries and API cement. table 7.d below shows the typical compressive strengths and thickening times of API cements. table 7.d Definitions * ** + Bc ABc
*** ++
Determined by Wagner turbidmeter apparatus Based on 250ml volume percentage equivalent 3.5ml is 1.4% Bearden unit of slurry consistency (Bc) Bearden units of consistency on a preserved consistometer Beaden units of consistency on an atmosphere pressure consistometer The relationship between Bc and ABc is approximately Bc x 0.69 = ABc This relationship is valid for units of consistency less than 30Bc Thickening time required are based on 75% values of total cement times observed in the casing survey, plus 25% safety factor Maximum thickening time required for Schedule 5 is 120 mins
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A B C D E F G H Well Cement Class 46 46 56 38 38 38 44 38 Water % by weight of well cement 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80 Soundness (autoclave expansion), Maximum % 150 160 220 Fineness *(Specific surface) Minimum m 2/kg 3.5** 3.5** Free-Water content, Maximum ml Compressive Strength Test 8-hours Curing time Curing Curing Schedule Minimum Compressive Strength, psi (MPa) Temp Pressure Number o o f ( C) psi(kPa) 100 Atmos 250 200 300 300 300 (38) Atmos (1.7) (1.4) (2.1) (2.1) (2.1) 140 Atmos 1,500 1,500 (60) Atmos (10.3) (10.3) 6S 230 3,000 500 (110) (20,700) (3.5) 8S 290 3,000 500 (143) (20,700) (3.5) 9S 320 3,000 500 (160) (20,700) (3.5) Compressive Strength Test 12-hours Curing time Curing Curing Schedule Minimum Compressive Strength, psi (MPa) Temp Pressure Number o o f ( C) psi(kPa) 8S 290 3,000 (143) (20,700) Compressive Strength Test 24-hours Curing time Curing Curing Schedule Minimum Compressive Strength, psi (MPa) Temp Pressure Number o o f ( C) psi(kPa) 100 Atmos 1,800 1,500 2,000 (38) Atmos (12.4) (10.3) (13.8) 4S 170 3,000 1,000 1,000 (77) (20,700) (6.9) (6.9) 6S 230 3,000 2,000 1,000 (110) (20,700) (13.8) (6.9) 8S 290 3,000 2,000 (143) (20,700) (13.8) 9S 320 3,000 1,000 (160) (20,700) (6.9) 10S 350 3,000 (177) (20,700) Pressure Temperature Thickening Time Test Specification Test Maximum Consistency 15 to Minimum Thickening Time (min***) Schedule Number 30 min Straining Period B + 1 30 90 90 90 4 30 90 90 90 90 5 30 90 90 5 30 120 max ++ 120 max ++ 6 30 100 100 100 8 30 154 9 30 190 -
Table 7.C - Physical Requirements for API Portland Cements
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Concentration of Additives The concentrations of most solid cement additives are expressed as percentage by weight of cement (BWOC). This method is also used for water. For example, if 30% silica sand is used in a blend, the amount for each sack of cement is 94lbs x 0.30 = 28.2lbs of silica sand. This results in 94 + 28.2 = 122.2lbs total mix. The true percentage silica sand in the mix is 28.2/122.2 = 23.07%. Salt is an exception and is added by weight of mix water (BWOW). Weighting materials are often added on a lbs/sk basis for convenience as it eliminates the need to convert from percentage BWOC to lbs in the bulk plant. Liquid additive concentrations are most commonly expressed in gal/sk of cement. For example, according to table 7.d, liquid sodium silicate has an absolute volume of 0.0859gal/lbs. If a concentration of 0.4lbs/sk is prescribed, the weight of the material is 0.4/0.0859 = 4.66lbs/sk. Material
Absolute Volume
SG 3
(gal/lbs)
(m /t)
Barite
0.0278
0.231
4.33
Bentonite
0.0454
0.377
2.65
Coal (ground)
0.0925
0.769
1.30
Gilsonite
0.1123
0.935
1.06
Hematite
0.0244
0.202
4.95
Limenite
0.0270
0.225
4.44
Silica Sand
0.0454
0.377
2.65
NaCl saturated
0.0556
0.463
2.15
Fresh Water
0.1202
1.000
1.00
Table 7.D - Absolute Values of Common Cementing Materials 7.1.2.
Slurry Density and Weight The slurry density is calculated by adding the masses of the components and dividing it by the total of the absolute volumes occupied, i.e. divide the total weight in lbs/volume in gals.
Pslurry(lbs / gal) =
lbcement + lbwater + lbadditives galcement + galwater + galadditives
The yield of a cement is the volume occupied by a unit plus all the additives and mix water. Cement is measured is sacks therefore the yield is expressed in cubic feet per sack (ft3/sk). This is now used to calculate the number of 94lbs sacks required to achieve the required annulus volume. As there are 31.51 cubic feet per cubic metre, divide the cubic feet by 31.51 to obtain the amount of cement in cubic metres.
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Example calculation: A slurry is composed of G class cement and 50% water, 94 x 0.50 = 47.0lbs water. Component
Weight (lbs)
Absolute Volume (gal/lbs)
Volume (gal)
94
0.0382
3.59
47.0
0.1202
5.65
Cement Water Total
141.0
9.24
141.0 9.24 = 15.26lbs / gal
Pslurry(lbs / gal) =
The yield is: Slurry Yield =
9.24gal / sk 7.48gal / sk
= 1.235ft 3 / sk The total volume of mix water required is the gals calculated above, 5.65 multiplied by the number of sacks of cement to be mixed. Additives are treated in the same manner as above, however if any have a volume less than 1% then they are generally ignored. An example calculation with additives is as follows: A slurry is composed of class G cement + 35% silica flour + 1% solid cellulosic loss additive + 0.2gal/sk liquid PNS dispersant + 44% water.
Weight (lbs)
Absolute Volume (gal/lbs)
Volume (gal)
94
0.0382
3.59
Silica flour
32.9
0.0454
1.49
Cellulosic Fluid Loss Additive
0.94
0.0932
0.088
Liquid PNS Dispersant
1.97
0.1014
0.20
Water
41.36
0.1202
4.97
Component Cement
Total
171.17 171.17 10.34 = 16.55lbs / gal
Pslurry(lbs / gal) =
10.34
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The yield is: Slurry Yield =
10.34gal / sk 7.48gal / sk
= 1.38ft 3 / sk 7.2.
CEMENT ADDITIVES In well cementing, Portland cement systems are designed for temperatures ranges from below freezing to 700oF (350oC) in thermal recovery and geothermal wells. They also encounter pressures ranging from ambient to 30,000psi (200Mpa) in deep wells. Accommodation of such variations in conditions was only possible through the development of cement additives. They modify the properties of the cement system allowing successful placement of the slurry between the casing and the formation, rapid compressive strength development and adequate zonal isolation for the life of the well. It is not possible to detail all of the 100 or more additives in use today but the categorisation of these additives and some of those used by Eni-Agip are described below. There are eight recognised categories: • • • • • • • •
Accelerators Retarders Extenders Weighting Agents Dispersants Fluid Loss Control Agents Loss Circulation Control Agents Speciality Additives
Details of all of these additives are given in the ‘Drilling Fluids Manual’. 7.2.1.
Accelerators Added to cements to shorten the setting time and/or accelerate the hardening process. They are also required to counter the effect of other additives added to the slurry such as dispersants and fluid loss control agents. Calcium Chloride is undoubtedly the most efficient and economical accelerator. It is generally added in concentrations of 2-4% BWOC (Refer to table 7.e) but over 6% its performance becomes unpredictable and premature setting may occur.
CaCl2 %BWOC
91oF
103oF
113oF
0
4:00
3:30
2:32
2
1:17
1:11
1:01
4
1:15
1:02
0:59
Table 7.E – Calcium Chloride Thickening Time on Portland Cement
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80oF
100oF
6hr
12hr
24hr
6hr
12hr
24hr
6hr
12hr
24hr
0
Not Set
60
415
45
370
1,260
370
840
1,780
2
125
480
1,510
410
1,020
2,510
1,110
2,370
3,950
4
125
650
1,570
545
1,245
2,890
1,320
2,560
4,450
Table 7.F– Calcium Chloride Compressive Strength Vs Temperature and Time of Portland Cement NaCl can also be used as an accelerator. Seawater is extensively used offshore as it has a 25g/l NaCl but the concentration of magnesium of about 1.5g/l must be taken into account. 7.2.2.
Retarders The retardation process is not completely understood but there are a number of additives available. The chemical nature of the retarder to be used is dependent on the cement phase (silicate or aluminate). Common retarders are lignosulphonates, hydroxycarboxylic acids, saccharide compounds, cellulose derivatives, organophosphonates and inorganic compounds.
7.2.3.
Extenders Extenders are used for the following uses: • • • • •
Reduce slurry density Increase slurry yield Water extenders Low-density aggregates Gaseous extenders
A list with general information on the most common extenders is given in table 7.g Extender
Range of Slurry Densities Obtainable (lbs/gal)
Performance Feature and Other Benefits
Bentonite
11.5-15.0
Assists fluid loss control.
Fly Ash
13.0-14.1
Resists corrosive fluids.
Sodium Silicates
11.1-14.5
Only low percentages required. Ideal for seawater mixing.
Microspheres
8.5- 15.0
Good compressive strength, thermal stability and insulating properties.
Foamed Cement
6.0-15.0
Excellent strength and low permeability.
Table 7.G- Summary of Extenders
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The most frequently used clay-based extender is bentonite which contains 85% of the clay mineral smectite (or montmorillonite). It is added in concentrations of up to 20% BWOC. Concentrations above 6% requires the addition of a dispersant to reduce the slurry viscosity and gel strength. API recommends that 5.3% water BWOW be added for each 1% bentonite but testing with a particular cement is necessary to determine the optimum water content. table 7.h shows the slurry density decreases and the yield increases quickly with bentonite concentration, however compressive strength correspondingly decreases. Bentonite Concentration %
Class G - 44% Water Water (gal/sk)
0 2 4 6 8 10 12 16 20
4.97 6.17 7.36 8.56 9.76 10.95 12.15 14.55 16.94
Slurry Density (lbs/gal) 15.8 15.0 14.4 13.9 13.5 13.1 12.7 12.3 11.9
Yield (ft3/sk) 1.14 1.31 1.48 1.65 1.82 1.99 2.16 2.51 2.85
Table 7.H- Bentonite Effects on Slurry Properties High concentrations of bentonite tend to improve fluid loss and is also effective at elevated temperatures. 7.2.4.
Weighting Agents When high pore pressures, unstable well bores, and deformable/plastic formations are encountered, high weight muds of over 18ppg may be used are correspondingly cement slurries of equal weight must be used. One method of achieving high weight slurries is to simply reduce the amount of mix water, however dispersants would be required to maintain pumpability. When weights higher than this are required, materials with high SGs are added. The most common weighting agents and there properties are shown in table 7.i.
Material
Specific Gravity
Limenite Hematite Barite
4.45 4.95 4.33
Absolute Volume (gal/lbs) 0.027 0.024 0.028
Colour Black Red White
Table 7.I- Common Weighting Material Properties
Additional Water (gal/lbs) 0.00 0.0023 0.024
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SALT CEMENT Salt cements have applications where freshwater cement will not bond properly. This is usually in wells which have salt formations where water will dissolve the formation or leach away the salt at the interface producing no bond at all. A good bond can be achieved if salt slurries are used. Salt slurries found another use to protect shale formations which are sensitive to fresh water and tend to slough when in contact. This problem causes: • • •
Excessive washouts and channelling behind the pipe. Lost circulation into the weakened shale structure. Annular bridging which may prevent slurry circulation.
The cement used in salt slurries is usually NaCl but there is no reason that KCl cannot be used. Previously, the benefits of using salt cements was known but was unpopular due to the inconvenience of premixing salt with water prior to adding cement. Today the technique of blending dry granulated salt with cement at the bulk plant greatly simplifies its use. The mix water requires a minimum 3.1lbs of dry salt for every gallon of water (0.3714kg/l) or 37.2 BWOW. If the concentration is less then the slurry will not be saturated and may cause the problems previously outlined. If more salt is added then there is no detrimental effects except changes in density and pumping ability. table 7.j shows the BWOW for various concentrations of salt in water including saturated: Concentration %BWOW 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 37.2 saturated
Absolute Volume (gal/lbs) 0.0771 0.0378 0.0384 0.0390 0.0394 0.0399 0.0403 0.0407 0.0412 0.0416 0.0420 0.0424 0.0428 0.0430 0.0433 0.0436 0.0439 0.0442
(m3/t) 0.310 0.316 0.321 0.326 0.329 0.333 0.336 0.340 0.344 0.347 0.351 0.354 0.357 0.359 0.361 0.363 0.366 0.369
Table 7.J - BWOW for Various Concentrations of Salt in Water
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An example calculation of a salt slurry using the previous fresh water slurry is as follows: 94lbs cement x 50% = 47lbs 47lbs of water x .372 = 17.48lbs NaCl Weight (lbs)
Absolute Volume (gal/lbs)
Volume (gal)
94
0.0382
3.59
NaCl
17.48
0.0442
0.77
Water
47.00
0.1202
5.65
Component Cement
Total
158.48
10.01
158.48 10.01 = 15.26lbs / gal
Pslurry(lbs / gal) =
The yield is: Slurry Yield =
10.01gal / sk 7.48gal / sk
= 1.338ft 3 / sk 7.4.
SPACERS AND WASHES When the fluids are incompatible, to ensure all the mud is displaced, it is common practice to pump one or more intermediate fluid or preflushes which are compatible with both the mud and the slurry. This will buffer the two fluids and prepares the casing and formation walls leaving them receptive to bonding. To accomplish all of the above, the rheological and chemical properties must be carefully designed. The rheology and density of washes are close to that of water or oil. They act be thinning and dispersing the mud and, because of their very low viscosity, they are ideal for use in turbulent flow. The simplest form of wash is fresh water although surfactants and dispersents are often added. Spacers are also used which are preflushes with a much higher solids content. the particles are thought to scrub the walls and provide a better preparation. the most common spacer is a scavenger slurry which is a cement slurry with a low density and low fluid loss rate good for turbulent flow. The best spacer is a spacer that has a density higher than the mud but less than the cement slurry. This is achieved by adding weighting agents (usually insoluble minerals with high density) with a viscofier for efficient suspension.
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There are two classes of viscofiers: a)
Water soluble polymers • • • •
b)
Polycrylamides Guar and guar derivatives Cellulose derivatives, CMC, HEC, HMC, HPC Xantham gum and other biopolymers
Inorganic clays •
Bentonite, attapulgite, kaolinite, sepiolite
Eni-Agip recommends that, unless an effective mud density is required to control the formation pressure, a water spacer be used on all cement jobs which shall have sufficient volume to provide a contact time of three mins. 7.5.
SLURRY SELECTION The selection of a slurry design depends on many factors other than simply pore and fracture pressures. • • •
• •
Cements are sometimes mixed at high density to achieve specific strengths within a short time interval or it may be designed on an economic basis where high yield per sack is achieved at the expense of strength. Temperature as previously explained has a large impact on the class of cement that can be used. Fluid loss additives are necessary where the cement is in contact with production zones or in small annular gaps to prevent the loss of the aqueous phase. As fluid loss additives are viscofiers they require dispersants to be added to preserve mixability. Dispersants are used for the previous reason but also to reduce viscosity and reduce pump pressures and improve placement efficiency. caution should be taken when using dispersants as they can change thickening time. Additives such as accelerators and retarders are required to hasten or slow down the setting times.
In the main, the compressive strength of the cement is secondary to the properties of the liquid slurry as cement systems generally provide strengths which exceed those actually required in most cases. The ADIS programme should help the engineer to obtain the ideal slurry for a specific well application.
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CEMENT PLACEMENT Good mud removal is the essence of obtaining a successful primary cement job and therefore the use of an effective preflush and/or spacer is pumped between the mud and the slurry. Freshwater spacers are normally used when water based mud is in the hole and salt tolerant spacers for salt saturated muds. Oil based mud is generally removed with spacers dosed with surfactants and/or organic solvents. In every case laboratory testing should be carried out beforehand to ensure that no unforeseen interactions can occur, hence affecting the performance of the spacer.
7.7.
WELL CONTROL Every well has a band of pressures in which the engineer must remain to execute a successful cementing operation. The limiting pressure boundaries are determined by formation pore and fracture pressures and casing strength limits. Unless a software package is used, the engineer would find it impractical to calculate the pressures at point in the well throughout the entire job, therefore, if it is necessary to conduct manual calculations, the usual approach is to select the worst case scenario analysis technique where the key points will be identified and examined. These are normally at the weakest formations which will experience their highest pressure at the end of the displacement just before the plug bumps and conversely the at high pressure zones at the time the low density preflush or spacer passes. A good rule of thumb under such circumstances, is to select the shallowest active zone which poses a risk to security and concentrate on the worst cases at this point using hydrostatic pressure without the friction component. An important impact on well control is the amount of excess cement calculated which can cause higher than expected hydrostatic pressure is the hole is close to gauge causing losses therefore compromising the success of the job and well security. Similarly, if using low density flushes or spacers, better than expected hole gauge will raise the column of the fluid to higher than expected height therefore exerting reduced hydrostatic pressure. If pressure band over long sections to be cemented is narrow, it may be necessary to vary the density of the cement slurry and pump two slurries, a lead and tail with different densities. See example figure 7.a
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Figure 7.A- Downhole Pressure Density Plot
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JOB DESIGN The selection of a slurry for a job design is dependent upon conducting a problem analysis into: • • •
Depth/configuration data Wellbore environment Temperature data
These data will directly affect the basic cement properties and displacement regime. The annular configuration will determine which flow regime is practical and required rheological properties. Wellbore conditions will indicate whether special materials are required due to the presence of gas, salt, etc., need to be incorporated. The mud density indicates the minimum acceptable cement slurry density. These factors, together with the temperature data, guide the selection of the additives for the control of the slurry flow properties and thickening time. 7.8.1.
Depth/Configuration The hole depth and configuration will make a considerable impact on the temperature and fluid volume, hydrostatic pressure and friction pressure. this could even lead to the design of a special system. In open hole sections the volume of slurry depends upon the shape of the hole which is rarely ‘gauge’ and some formations are liable to become eroded or washed out. For open hole sections the volume should have an increment added to cater for such problems. If there is a reason to have doubts over the size of the hole, a caliper survey should be run to estimate the hole size. It should be noted that the amount of pads on the caliper will affect the accuracy of the calculation if the hole is not round. The increments to be applied in absence of a caliper survey are: • • •
Surface Casing - 100% Intermediate Casing - 50% Production Casing - 30%
If a log is available the increment will be the hole volume calculation plus 10%. The trapped volume between the cement collar and cement shoe must be added to total volume.
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Environment Pore pressure in the formations are important from a security standpoint and, in conjunction with leak-off test results, to prevent formation damage through fracturing or leak-off of cement into producing zones. The engineer must not look solely at target zones but also the risk from other non-producing zones. The presence of gas, salt and other formations will also affect the job design. Mud physical and chemical properties must also be considered, with regard to compatibility with chemical washes, spacers or other fluids. The displacement of oil based mud from formations may invariable require the use of surfactants to improve compatibility, remove oil film from the formations and leave the surfaces water wet. If 100% mud removal is not possible, the slurry properties can be altered to ensure it is not adversely affected by the mud. Data on compatibility can be obtained by laboratory testing.
7.8.3.
Temperature Circulating bottom hole and static temperatures need to be considered as well as the temperature differential between the bottom and top of the cement column. The circulating temperature is the temperature it will be exposed to as it is placed in the well and for which the thickening time tests for high-temperature and high-pressure is carried out. Circulating temperatures by calculation in accordance with temperature schedules published in API 10 Specification. However, actual temperature is often preferred and these can be obtained by running a temperature measurement device. One rule of thumb which should apply to the slurry design, is to ensure that the static temperature at the top of the cement exceeds the circulating bottom hole temperature. If this is not the case then stage cementing should be employed. This rule of thumb also provides a means of determining the depth for the location of the cementing stage collar.
7.8.4.
Slurry Preparation Mixing is one of the most important practical cementing problems. The goal of the mixing process is to obtain the correct proportioning of solids and carrier fluid with the properties similar to those of the expected from pre-job lab testing. If this is not achieved, the careful pre-planning calculations to determine the displacement rate, friction pressure, etc., will be erroneous and thickening time and fluid loss parameters may change dramatically.
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8.
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WELLHEADS This section provides design criteria for wellheads which have been standardised by EniAgip Division and Affiliates. With regard to modular type surface wellheads, the most commonly used wellhead in EniAgip’s activities is the National/Breda wellhead system which is covered later in this section. However, there is no commonality in the selection of compact surface wellheads or subsea wellheads. Each project must be assessed to ascertain the most economic type of wellhead to be used for the location or type of completion..
8.1.
DEFINITIONS The following are a list of definitions and their abbreviations specific to wellhead equipment.
8.2.
MSCL
Modular Single Completion Land
DCSFSL
Dual Completion Seal Flange solid-block Land
SCSO
Single Completion Seal Flange Offshore
DCSO
Dual Completion Solid-block Offshore
DESIGN CRITERIA Eni-Agip divide wellhead equipment into two classifications: Class A
Equipment designed to operate up to 5,000psi WP
Class B
Equipment designed to operate up to 10,000psi WP
The selection of the wellhead system pressure rating will be based upon the max anticipated surface pressure. 8.2.1.
Material Specification The material selection will meet with either ‘General Service’ or ‘Sour Service’ conditions. General service conditions are defined as: Operating Temperature Range:
o
o
-29 C to 82 C as per API 6A
The steels which meet with this criteria are material standard (no sour service), class Dd as per API 6A as defined by NACE MR-01-75
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Sour service conditions are when the CO2 or H2S concentrations exceed 7psi and 0.05psi respectively. In this case the material will be selected in accordance whether an inhibition programme is implemented which may decide if chrome or carbon steel is applicable. However if the event of any H2S being present above the limit, a steel with a hardness less than 22Rc will be selected to comply with NACE MR-0175 specification. Refer to section 4.13 on corrosion. In offshore environments, the wellhead and Xmas tree equipment should be protected against the corrosive effects of salt spray by application of an appropriate coating. Modern compact wellheads, described below, may offer enhanced safety due to the increased fire resistance by the use of all metal-to-metal seals. 8.3.
SURFACE WELLHEADS Compact wellheads have many advantages over composite types in that they are shorter, have less connections, less outlets and are therefore have fewer potential leak paths. The compact wellhead was developed from subsea systems which require the stacking of a number of casing mandrel hangers in a single body. The advantages of the traditional composite type wellhead with its modular construction are: its ability to be altered during drilling operations (due to enforced changes in the casing programme), and low cost. The compact wellhead, also sometimes referred to as speed, fast or unitised head, comes in various configurations but usually consists of a body that is mounted onto the surface casing and into which each subsequent casing hanger is run and landed. The sealing of these hangers is via a seal assembly run above each hanger with metal-to-metal seals. The main advantages of the compact head is the reduced height, saving of rig time due to being able to run the hangers without removing the BOPs and enhanced safety for the same reason.
8.3.1.
Standard Wellhead Components Refer to ‘Specification for Surface Wellhead and Xmas Tree Standard Equipment Manual’. table 8.a shows the standard equipment for the various classifications and well options. From this table, the sizes and pressure rating of equipment available for the various applications can be determined.
8.3.2.
National/Breda Wellhead Systems National/Breda wellhead systems are, up to now, the most commonly used systems by EniAgip Division and Affiliate companies. It is of traditional modular construction and covers pressure ranges between 3,000 and 15,000 psi for both standard and non-standard casing profiles. table 8.a shows the standard range of National/Breda wellhead configurations and an example wellhead. Other wellhead and equipment details can be obtained from the manufacturer’s catalogue.
CASING HEAD SPOOL
CASING HEAD Top flange (in)
Max. W.P. (psi)
Btm (CSG) (in)
Ref. nr
Btm Flange (in)
MSCL 1
1.3
13 5/8
5000
13 3/8 & 9 5/8
2.1
13 5/8
5000
13 5/8
MSCL 2
1.3
13 5/8
5000 13 3/8 & 9 5/8
2.1
13 5/8
5000
MSCL 3
1.3
13 5/8
5000 13 3/8 & 9 5/8
2.1
13 5/8
DCSFSL 1
1.2
21 1/4
5000
2.4
DCSFSL 2
1.2
21 1/4
5000
20 & 18 5/8
DCSFSL 3
1.2
21 1/4
5000
SCSO 1
1.2
21 1/4
DCSO 1
1.2
DCSO 2 DCSO3 (*)
CASING HEAD SPOOL
Top flange (in)
Max. W.P. (psi)
Ref. nr
Btm flange (in)
Max. W.P. (psi)
Top flange (in)
TUBING SPOOL Ref. nr
Btm Flange (in)
Max. W.P. (psi)
Top flange (in)
Max. W.P. (psi)
Ref. nr
Diam (in)
5000
5.1
13 5/8
5000
9
5000
6.1
9
5000
2 7/8
13 5/8
5000
5.1
13 5/8
5000
9
5000
6.2
9
5000
3 1/2
5000
13 5/8
5000
5.1
13 5/8
5000
9
5000
6.3
9
5000
5
21 1/4
5000
13 5/8
5000
2.1
13 5/8
5000
13 5/8
5000
5.1
13 5/8
5000
9
5000
6.6
9
5000
2 x 2 3/8
2.4
21 1/4
5000
13 5/8
5000
2.2
13 5/8
5000
13 5/8
10000
5.2
13 5/8
10000
9
10000
6.8
9
10000
2 x 2 3/8
20 & 18 5/8
2.4
21 1/4
5000
13 5/8
5000
2.1
13 5/8
5000
13 5/8
5000
5.3
13 5/8
5000
11
5000
6.5
11
5000
2 x 3 1/2
5000
20 & 18 5/8
2.4
21 1/4
5000
13 5/8
5000
2.1
13 5/8
5000
13 5/8
5000
5.4
13 5/8
5000
7 1/16
5000
6.4
7 1/16
5000
3 1/2
21 1/4
5000
20 & 18 5/8
2.4
21 1/4
5000
13 5/8
5000
2.1
13 5/8
5000
13 5/8
5000
5.4
13 5/8
5000
7 1/16
5000
6.9
7 1/16
5000
2 x 2 3/8
1.2
21 1/4
5000
20 & 18 5/8
2.4
21 1/4
5000
13 5/8
5000
2.2
13 5/8
5000
13 5/8
10000
5.5
13 5/8
10000
7 1/16
10000
6.7
7 1/16
10000
2 x 2 3/8
1.2
21 1/4
5000
20 & 18 5/8
2.4
21 1/4
5000
13 5/8
5000
2.2
13 5/8
5000
13 5/8
10000
5.2
13 5/8
10000
9
10000
6.8
9
10000
2 x 2 3/8
1.2
21 1/4
5000
20 & 18 5/8
2.5
21 1/4
5000
13 5/8
10000
2.3
13 5/8
10000
13 5/8
10000
1.1
26 3/4
3000
24 1/2
2.6
26 3/4
3000
21 1/4
5000
2.5
21 1/4
5000
13 5/8
10000
2.3
13 5/8
20 & 18 5/8
Max. W.P. (psi)
TUBING HANGER Max. W.P. (psi)
Diam tbg (in)
IDENTIFICATION CODE
Ref.nr
Max. W.P. (psi)
STAP-P-1-M-6100
3째 CASING HEAD SPOOL 10000
13 5/8
10000
0 PAGE
(*) Typical wellhead configuration for deep wells (po Valley)
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Table 8.A- Eni-Agip Standard Wellhead Equipment Chart
AGIP CODE
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Typical outlines for on-shore, off-shore single and dual completion class -A and class -B (STAP -M-1-SS-5701E)
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4
3
2
1
20" 13 3/8" 9 5/8" 7"
WP (psi) Section 1 Section 2 Section 3 Section 4 Section 5
3K (A) 470 620 472 -
3K (B) 470 620 472 -
5K (C) 470 625 472 -
5K (D) 470 690 670 581 -
10K (E) 470 690 660 700 -
10K (F) 510 850 700 700 --
Figure 8.A - Wellhead Dimensions (mm)
15K (G) 510 850 700 750
15K (H) 510 850 700 750
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8.4.
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COMPACT WELLHEAD Modern offshore drilling has uncovered a need for specially designed wellheads requiring less space with shorter installation times, thus offering a greater degree of safety. The solution to this need was met by the introduction of the unitised or compact wellhead which incorporates a casing flange, casing spools and possibly a tubing spool in a single offshore composite wellhead body. Eni-Agip Division and Affiliates generally use the compact wellhead system in development drilling operations. The concept is quite different from that already described in section 8.3 and similar to subsea wellhead systems from which the compact head was developed. Each manufacturer has its own particular product which differs from other manufacturers. Considering the number of different varieties available, it is not possible to provide a unique assembling procedure for all the existing unitised or compact wellhead types in this manual. figure 8.b and figure 8.c show two typical examples of compact wellhead systems. For specific running procedures reference should always be made to the well specific Drilling Programme and manufacturer's instructions. Technical advantages of the compact wellhead are: • • • • •
Elimination of the rig time lost in nippling-up or down the BOPs, which is normally associated with conventional wellhead spools. Once the pack-off is set, the BOP can be tested. No crossover adapters are required. The stack-up height is greatly reduced by the elimination of the casing and tubing spools. The Well is under BOP control from the time the 13 3/8” BOP stack is installed on the Compact Wellhead to the time the Xmas tree is installed.
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Figure 8.B - Wellhead ‘Unitised 3,000psi WP
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5
0
Figure 8.C - Wellhead SMS 13 /8 10,000psi WP Assembly
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8.5.
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MUDLINE SUSPENSION The Mudline Suspension system is a method for supporting the weight of casing at the seabed (mudline) while drilling from a jack-up (Refer to figure 8.d and figure 8.e) It offers a method of disconnection for all casing strings, allowing the temporary abandonment of the well in the minimum of time and without having to cut the casings. The casing strings extend from the mudline back to the drilling unit. Conventional land type wellhead and BOPs are installed for well control during drilling operations. The system utilises simple fluted landing rings or expanding collets in which the hangers are landed. Each casing string is supported at the mudline by a mudline casing hanger. The running tools or the tieback tools connect the mudline casing hangers with the casing string above (landing string). Running tools used in the mudline system, include a square bottom thread, to install it into the hangers and seal, to maintain the pressure integrity of the running tool mudline hangers. The connection of the running tools is the casing thread as per the user’s requirement. Washout ports, located in the mudline hanger or in the running tool, ensure thorough flushing of the annulus. The washout ports are exposed by a partial rotation of the running tool. When the washout ports are closed the pressure integrity of the casing is provided by the seals of the running tool. When temporarily abandoning a well, the casing landing string is retrieved by disconnecting the running tools. Corrosion caps used in temporary well abandonment may be installed at this time. Any, or all, of the casing strings can be re-installed back to a conventional land type production tree, installed on a production platform wellhead deck, by means of tie-back tools. Metal to metal seals between the tieback tool a 133/8” or smaller mudline casing hangers provide a permanent pressure seal for the producing life of the well. Eni-Agip have used a ‘mudline completion system’ enabling a well to be drilled using a Jack-up drilling equipment and afterwards completing it with a subsea production system. Each mudline suspension manufacturer produces its own product different from those of competitors. Considering the great number of different features, it is not possible to describe all the existing mudline suspension system in this manual. For the installation procedure, refer to the well specific ‘Drilling Programme’ and the manufacturer’s ‘operating procedures’.
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Figure 8.D - MLL Mudline Casing Suspension System
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Figure 8.E - The MLC Mudline Suspension System
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PRESSURE RATING OF BOP EQUIPMENT The prime considerations, when selecting and procuring pressure control equipment, are the safety of the personnel, rig and the wellbore. In order to assure this safety requirement, several factor need to be considered. It should be noted that each drilling area may have regulations unique to that particular area which may exceed the general requirements covered within this manual. In addition, different operating companies and contractors may vary from these general requirements if dictated by individual company policy and philosophy. The anticipated formation pressure is the governing parameter which dictates the casing depth, casing selection, BOP selection and pressure rating of the BOP equipment. The weakest element within any pressure control system determines the maximum pressure that can be safely contained. Individual elements of the pressure control system may exceed the assembly WP, but under no circumstances should components be used which are less than the designated assembly WP. For instance, a 10,000psi choke may be rigged up with a 2,000psi BOP stack in anticipation of its later use when a 10,000psi BOP stack is nippled up for a subsequent string of casing. The equipment in the well control system with the lowest pressure rating will set the rating for entire system e.g. 2,000psi stack and 10,000psi choke manifold would be rated to only 2,000psi. Since the well control system must be able to contain any anticipated formation pressures that may be encountered, the maximum anticipated surface pressures must first be calculated. Many different methods are available to determine the maximum casing pressures which may be encountered during a kick.
9.1.
BOP SELECTION CRITERIA Blow-out preventer equipment shall consist of an annular preventer and the specified number of ram type preventers. The working pressure of any blow-out preventer shall exceed the maximum anticipated surface pressure to which it may be subjected, except that the WP of the annular preventer. The graph illustrated in the attached figure 9.a has been prepared to enable the first approximation of the BOP rating necessary for use in drilling an exploration well. To use the graph, the setting depths of the various casings and the relative pore pressure gradients must be found or determined during the design phase. The co-ordinates in the graph are ‘depth’ and ‘pressure’ and comprises of two groups of lines respectively, are representing the BOP’s to be used while drilling, and the other the BOPs to be used during well testing. Each group outlines the different solutions available to the various pore pressure gradients.
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Example: The casing program assumes that a well test will be carried out at the shoe of 7” casing. From the diagram shown in table 9.a the maximum test, drilling pressure values and the size of BOP to be used should be obtained which is given in table 9.a. Casing (ins)
Shoe Depth (m)
Overburden Gradient (kg/cm2/10m)
Pore Press. Gradient (kg/cm2/10m)
Fracture Gradient (kg/cm2/10m)
BOP Drilling (psi)
Size Production Test (psi)
20
750
2.23
1.03
1.83
2,000
-
13 /8
2.620
2.36
1.30
2.01
5,000
-
5
9 /8
4.200
2.42
1.70
2.18
10,000
-
7
4.830
2.43
2.00
2.29
-
15,000
3
Table 9.A - BOP Selection Example Data The maximum theoretical stress possible at the casing head (Pmax) occurs when the well is full of gas and the fracture pressure has been reached at the shoe of the last casing run. This pressure is:
Pmax =
H (GF - Dg) (Kg/cm 2 ) 10
where: H
=
Casing shoe depth (m)
Gf
=
Fracture gradient of the casing shoe (kg/cm2/10m)
Dg
=
Gas density, assumed = 0.3 (kg/dm3)
In the case of a well test, this pressure roughly corresponds to the limit value required for pumping gas into the formation and is thus actually attainable in practice. This hypothesis however is completely unrealistic in the drilling design, for which 60% of the pressure Pmax will be used as limit value according to company policy in burst design criteria of the ‘Casing Design Manual’.
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Figure 9.A - BOP Selection Example
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10.
BHA DESIGN AND STABILISATION
10.1.
STRAIGHT HOLE DRILLING
0
Drilling a perfectly straight hole is certainly an impossibility. A well designed bottom hole assembly only controls veering off-line to be maintained within acceptable pre-planned limits. The exact cause of holes becoming crooked is not well known but some logical theories have been presented based on appearance. It has been confirmed that the drilling bit will attempt to up dip in laminar formations with dips up to 40o. Another factor for consideration is the bending characteristics of the drill stem. With no weight on the bit, the only force acting on the bit is the result of the weight of the string portion between the bit and the tangency point. This force tends to bring the hole back towards the vertical. When weight is applied, there is another force on the bit which tends to direct the hole away from vertical. The results of these two forces may be in such a direction as to increase angle, decrease angle, or to maintain a constant angle. This theory is based on the assumption that the drill string will lie on the low side of an inclined hole. In general, drilling in soft formations makes the problem of drilling a straight or nearly vertical hole much easier than in very hard formations. In particular the effects of the drill string bending and encountering dips may be much less when drilling soft formations while in hard formations which have high dip angles require high bit weight which are the factors against drilling a straight or vertical hole. 10.2.
DOG-LEG AND KEY SEAT PROBLEMS
10.2.1. Drill Pipe Fatigue If a programme is designed in such a way that drill pipe damage is avoided while drilling the hole, then the hole will be acceptable for conventional casing, designs, tubing and production string as far as dog-leg severity is concerned. A classical example of the severe dog-leg condition which produces fatigue failures in drill pipe can be seen in figure 10.a. The stress at point B is greater than the stress at point A; but as the pipe is rotated, point A moves from the inside of the bend to the outside and back to the inside again, so that every fibre of the pipe under goes both minimum tension and maximum tension every rotation. Cyclic stress reversals of this nature cause fatigue failures in drill pipe, usually within the first two feet (0.6m) of the body adjacent to the tool joint due to the abrupt change of section. To avoid rapid fatigue failure of pipe, the rate of change of the hole angle must be controlled. Suggested limits are given in figure 10.b. This graph is a plot of the tension in 1 the pipe versus change in hole angle in degrees per 100ft. This curve is designed for a 4 /2" 16.60lbs/ft Grade â&#x20AC;&#x2DC;Eâ&#x20AC;&#x2122; drill pipe and represents the stress endurance limits of the drill pipe under various tensile loads and in various rates of change in hole angle. If conditions fall to the left of this curve, fatigue damage is avoided, but to the right, fatigue damage will build up rapidly and failure of the pipe is likely. It can be seen from this plot that with a dog-leg high WP in the hole with high tension in the pipe, only a small change in angle can be tolerated. Conversely, if the dog-leg is close to total depth, tension in the pipe will be low and a larger change in angle can be tolerated.
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Refer to figure 10.c for the maximum safe dog-leg limits when using Grade â&#x20AC;&#x2DC;Eâ&#x20AC;&#x2122; drill pipe. If the stress endurance limit of the drill pipe is exceeded, an expensive fishing job or a junked hole could occur.
10.2.2. Stuck Pipe Sticking can occur by sloughing, heaving of the hole or also by extra large OD drill collars contacting a key seat while tripping the drill string out of the hole. 10.2.3. Logging Logging tools and wire line can become stuck in key seats. The wall of the hole can also be damaged, causing future hole problems. 10.2.4. Running casing Running casing through a dog-leg can cause serious problems. If the casing becomes stuck in the dog-leg, it will not extend through the productive zone. This would make it necessary to drill out the shoe and set a smaller size casing through the productive interval. Even if running the casing to bottom through the dog-leg is successful, the casing could be severely damaged, thereby preventing the running of production equipment inside the casing. 10.2.5. Cementing Dog-legs will force casing tightly against the wall of the hole, preventing a good cement bond as no cement can circulate between the wall of the hole and the casing at this point. 10.2.6. Casing Wear While Drilling The lateral force of the drill pipe rotating against the casing in the dog-leg or dragging through it while tripping, can cause substantial wear to the casing. This could cause drilling problems and/or a possible serious blow-out. 10.2.7. Production Problems In rod pump completions rod wear and tubing leaks associated with dog-legs can cause expensive remedial costs. It may be difficult to run packers and tools in and out of the well without getting stuck because of distorted or collapsed casing. It is obviously preferred to produce through straight tubing to avoid friction losses and prevent turbulence.
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Figure 10.A - Dog Leg and Key Seating
Figure 10.B - Endurance Limit For 16.60# Grade E Drill Pipe
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Figure 10.C -Maximum Safe Dog leg Limits 10.3.
HOLE ANGLE CONTROL In order to reduce the possible causes of bit deviation and the problems associated with crooked holes, There are two possible solutions, one using the pendulum and the other the packed BHA concepts.
10.3.1. Packed Hole Theory A packed hole assembly is used to overcome crooked hole problems and the pendulum is used only as a corrective measure to reduce angle when the maximum permissible deviation has been reached. The packed hole assembly is sometimes referred to as the â&#x20AC;&#x2DC;gun barrelâ&#x20AC;&#x2122; approach because a series of stabilisers is used in the hole already drilled to guide the bit straight ahead. The object is to select a bottom hole assembly to be run above the bit with the necessary stiffness and wall contact tools to force the bit to drill in the general direction of the hole already drilled. If the proper selection of drill collars and bottom hole tools is made, only gradual changes in hole angle can develop. This should create a useful hole with a fullgauge, smooth bore free from dog-leg, key seats, offsets, spirals and ledges, thereby making it possible to complete the well.
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10.3.2. Pendulum Theory The forces which act upon the bit can be resolved into: 1) 2)
3)
10.4.
The axial load supplied by the weight of the drill collars. The lateral force, the weight of the drill collar between the bit and the first point of contact with the wall of the hole by the drill collar i.e. Pendulum force. This force is the tendency of the unsupported length of drill collar to swing over against the low side of the hole due to gravity. It is the only force that tends to bring the hole back towards vertical. The reaction of the formation to these loads may be resolved into two forces, one parallel to the axis of the hole and one perpendicular to the axis of the hole.
DESIGNING A PACKED HOLE ASSEMBLY The following factors need to be considered when designing a packed hole assembly.
10.4.1. Length Of Tool Assembly It is important that wall contact assemblies provide sufficient length of contact to assure alignment with the hole already drilled. Experience confirms that a single stabiliser just above the bit generally acts as fulcrum or pivot point and will build angle because the lateral force of the unstabilised collars above will cause the bit to push to one side as weight is applied. Another stabilising point, for example, at 30ft (10m) above the bit will nullify some of the fulcrum effect. With these two points, this assembly will stabilise the bit and remove some of the hole angle-building tendency, but it would still not be considered a good packed hole assembly. As shown in figure 10.d, two points will contact and follow a curved line, but the addition of one more point makes it impossible to follow a curve. Therefore, three or more stabilising points are needed to form a packed hole assembly. 10.4.2. Stiffness Stiffness is probably the most misunderstood of all the issues to be considered about drill collars. Realisation of diameter and its proportion to stiffness is an important factor. If a bar diameter is doubled its stiffness is increased 16 fold. table 10.a shows moments of inertia (I), which is proportional to stiffness which is given for the most popular drill collars in various diameters. Large diameter drill collars are the ultimate in stiffness, so it is important to select the maximum diameter collars that can be safely run.
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Three or more stabilising points make a packed bottom hole assembly.
3
2
2
2
1
1
1
Figure 10.D - Packed Hole Assembly Stabilising Points OD (ins)
ID (ins)
I (ins4)
5"
2 /4"
29
1
6 /4" 1
6 /2" 3
6 /4" 7" 8"
1
74
1
86
1
100
13
115
13
198
13
2 /4" 2 /4" 2 /4" 2 /16" 2 /16"
9"
2 /16"
318
10"
3"
486
11"
3"
713
Table 10.A - Drill Collar Stiffness
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10.4.3. Clearance The closer the stabiliser is to the bit, the more exacting the clearance requirements are. If, for example, a 1/16" undergauge from hole diameter is satisfactory just above the bit, then 60ft above the bit, 1/8" clearance can be critical factor for a packed hole assembly. 10.4.4. Wall Support and Length of Contact Tool Bottom assembly must adequately contact the wall of the hole to stabilise the bit and centralise the drill collars. The length of contact needed between the tool and the wall of the hole will be determined by the formation. The surface area in contact must be sufficient to prevent the stabilising tool from digging into the wall of the hole. If this should happen, stabilisation would be lost and the hole would drift. If the formation is strong, hard and uniform, a short narrow contact surface is adequate and will insure proper stabilisation. On the other hand, if the formation is soft and unconsolidated, a long blade stabiliser may be required. Hole enlargement in formations that erode quickly tends to reduce affective alignment of the bottom hole assembly. This problem can be reduced by controlling the annular velocity and mud properties. 10.5.
PACKED BOTTOM HOLE ASSEMBLIES Proper design of a packed bottom hole assembly requires a knowledge of crooked hole tendencies and the degree of drillability of the formations to be drilled in each particular area. For basic design practices the following are considered pertinent parameters and are defined: Crooked Hole Drilling Tendencies • • •
Mild crooked hole Medium crooked hole Severe crooked hole.
Formation Firmness • • • •
Hard to medium hard formations Abrasive Non abrasive Medium hard to soft formations.
figure 10.e shows three basic assemblies required to provide the necessary stiffness and stabilisation for a packed hole assembly. A short drill collar is used between Zone 1 and Zone 2 to reduce the amount of deflection that might be caused by the drill collar weight. As a general rule of thumb, the short drill collar length in feet is approximately equal to the hole size in inches, plus or minus two feet. For example a short drill collar length of 6 to 10ft (23m) would be satisfactory in an 8 “ hole.
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* The short drill collar length is determined by the hole size Hole size (inches) = Short DC (ft) +/- 2ft Figure 10.E - Basic Packed BHAs
0
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10.6.
PAGE
0
PENDULUM BOTTOM HOLE ASSEMBLIES Because all packed assemblies will bend to some extent, however small the amount of deflection drilling, a perfectly vertical hole is not possible. The rate of hole angle change may be kept to a minimum but occasionally conditions will arise where the total hole deviation must be reduced. When this condition occurs the pendulum technique is employed. If it is anticipated that the packed hole assembly will be required after reduction of the hole angle, the packed pendulum technique is recommended. The pendulum assembly is based on the principle that the only force available to straighten a deviated hole is the weight of the drill collars between the point of tangency (stabiliser) and the bit. In the packed pendulum technique, the pendulum length of collars are slung below the regular packed hole assembly. When hole deviation has been dropped to an acceptable limit, the pendulum collars are removed and the packed hole assembly again is run above the bit. It is only necessary to ream the length of the pendulum collars prior to resuming normal drilling. If a vibration dampening device is used in the packed pendulum assembly, it should remain in its original pick-up position during the pendulum operations. (Refer to figure 10.f).
Figure 10.F - Pendulum BHA
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10.7.
PAGE
0
REDUCED BIT WEIGHT By reducing the weight on the bit, the bending tendency of the drill string are changed and the hole will be straighter. One of the earliest techniques for straightening the hole was to reduce the weight on the bit and speed up the rotary table. In recent years it has been found that this is not always the best procedure because reducing the bit weight sacrifices considerable penetration rate. Worse than this, it frequently causes dog-legs as illustrated in. Therefore as a point of caution, the straightening of a hole by reducing bit weight should be done very gradually so that the hole will tend to return to vertical without sharp bends and be much safer for future drilling. A reduction of bit weight is usually required when changing from a packed hole assembly to a pendulum or packed pendulum drilling operation.
Figure 10.G - Reduced Bit Weight
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10.8.
PAGE
0
DRILL STRING DESIGN The normal drill string design practice aim is to avoid abrupt changes in component cross sectional areas. Abrupt changes can lead to concentrations in bending stresses which in turn can lead to a twist off (Refer to figure 10.h). The ratio I/C between the moment of inertia (I) and radius (C) of the pipe is directly related to the resistance to bending. The following are used to determine the section modulus I/C: I
C
=
Moment of inertia
=
Ď&#x20AC;/64 x (OD4- ID4)
=
Radius of the tube
=
OD/2
At a crossover from one tubular size to another size, the ratio (I/C large pipe)/(I/C small pipe) should be less than 5.5 for soft formations and less than 3.5 for hard formations. table 10.b shows the ratio (I/C) for the most common sizes of drill pipes, HW drill pipes and drill collars. table 10.c illustrates some possible drill strings and their acceptability.
Figure 10.H - Bending Moment
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OD (ins) 31/2 41/8 43/4 53/4 53/4 6 6 61/4 61/4 61/2 61/2 3 6 /4 63/4 7 71/4 73/4 73/4 8 8 81/4 81/4 81/2 9 91/2 10 111/4 12
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REVISION
Drill Collar ID (ins) 11/2 2 21/4 21/4 213/16 21/4 23/16 21/4 23/16 21/4 23/16 21/4 23/16 23/16 23/16 23/16 3 3 2 /16 3 23/16 3 3 3 3 3 3 3
STAP-P-1-M-6100
0
OD (ins) 23/8 23/8 27/8 27/8 31/2 31/2 31/2 4 4 41/2 41/2 41/2 5 5 5 51/2 51/2 51/2 65/8
Drill Pipe ID (ins) WT 2 4.85 1.815 6.65 2.441 6.85 2.151 10.40 3 9.50 2.764 13.30 2.602 15.50 3.476 11.85 3.340 14.00 3.958 13.75 3.826 16.60 3.640 20.00 4.408 16.25 4.276 19.50 4.000 25.60 4.892 19.20 4.778 21.90 4.670 24.70 5.965 25.20
I/C 4.1 6.6 9.8 18.3 17.6 20.8 20.2 23.3 22.7 26.7 26.2 30.1 29.6 32.7 37.5 44.6 44.4 49.5 49.3 55.9 54.2 59.2 71.0 83.8 97.2 138.8 154.5
I/C 0.7 0.9 1.1 1.6 2.0 2.6 2.9 2.7 3.2 3.6 4.3 5.1 4.9 5.7 7.3 6.1 7.1 7.8 9.8
Extra Weight Pipe OD (ins) 41/2 5
ID (ins) 213/16 3 1
l
=(Moment of Inertia)
C
= Radius of the Tube in inches
Ratio =
4
WT 32.0 42.6 4
= ( /64) x (OD â&#x20AC;&#x201C; ID ) x 3.142
I / C Drill Collars I / C Drill Pipes Table 10.B - I/C Ratios for standard Tubulars
I/C 7.7 10.7
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REVISION STAP-P-1-M-6100
Hole Size (ins)
Drill Collar/Drill Pipe (ins)
I/C Ratio
83.8
1.5
DC 8 /4 x 21 /16
55.9
9.8
DP 5 x 19.5lbs/ft
5.7
-
Not
83.8
1.5
Recommended
55.9
7.1
DP 5 /2 x 19.5lbs/ft
7.8
1.4
DP 5x 19.5lbs/ft
5.7
-
83.8
1.5
OK for
DC 8 /4” x 2 /16
55.9
5.2
SOFT
HWDP 5” x 42.6lbs/ft
10.7
1.9
Formations
DP 5” x 19.5lbs/ft
5.7
-
1
3
1
DC 9 /2 x 3 1
13
DC 8 /4 x 2 /16 1
17 /2
0
I/C
DC 91/2 x 3
1
137 OF 230
1
DC 9 /2 x 3 1
13
1
DC 9 /2 x 3
Remarks
83.8
1.5
/16”
55.9
2.5
OK For HARD
13
DC 6 /4 x 2 /16”
22.7
1.9
Formations
DP 5” x 19.5lbs/ft
5.7
-
81
DC /4 2 1
13
Note: For every hard formations, add HWDP 91
DC /2” x 3” 1
12 /4”
83.8
1.5
1
13
55.9
2.5
OK For HARD
1
13
DC 6 /4 x 2 /16
22.7
3.9
Formations
DP 5” x 19.5lbs/ft
5.7
-
DC 8 /4 x 2 /16”
Note: For every hard formations, add HWDP 91
DC /2” x 3” 1
12 /4”
83.8
1.5
DC 8 /4 x 2 /16”
55.9
5.2
OK For SOFT
HWDP 5” x 42.6lbs/ft
10.7
1.9
Formations
DP 5” x 19.5 lbs/ft
5.7
-
1
1
5
8 /8
13
13
DC 6 /4 x 2 /16”
22.7
DP 5” x 19.5lbs/ft
5.7
1
13
DC 6 /4 x 2 /16”
22.7
HWDP 5” x 42.6lbs/ft
10.7
DP 5” x 19.5lbs/ft
5.7
Not 3.9
Table 10.C - Drill String Acceptability
Recommended Recommended
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10.9.
PAGE
0
BOTTOM HOLE ASSEMBLY BUCKLING Without weight on the bit, a drill string is straight if the hole is straight. With a sufficient small weight applied on the bit, the string will remain straight. As the weight is increased, a critical value of weight is reached and the drill string will buckle and contact the wall of the hole. If the weight on the bit is further increased, a new critical value is reached at which the drill string buckles a second time. This is designated as ‘buckling of the second order’. With still higher weights on the bit, buckling of the third and higher orders occur. When a buckled string is rotated, stresses in the outside fibres of tubular are developed. These stresses increase with the diameter of the hole and results in fatigue failure of the string. As soon as a drill string buckles in a straight hole, the bit is no longer vertical and a perfectly vertical hole can not be maintained. Therefore, in the design of BHAs, it is important to determine the critical values of weight on bit at which buckling occurs. The critical weight on bit of the first order (W cr1) and second order (W cr2) are given by the following equations: W cr1 = 1.94 x m x p W cr2 = 3.75 x m x p where: m
=
Length of one dimensionless unit, in meters
p
=
Weight in mud per unit of length of the pipe, in kg/m
The dimensionless unit ‘m’ is a function of Young's modulus for steel, moment of inertia of the pipe cross section and weight in mud per unit of length of the pipe. The values of ‘m’ for various sizes of drill collar are plotted in figure 10.i. Under normal conditions, some buckling of the drill string is inevitable, therefore stiffer collars and stabiliser should be used for control of the hole angle.
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0
Dimensionless Unit (m) for Various m 28
11" * 9 1/2" * 8 1/4" *
26
8 1/4" * 2 8" * 8" * 2
24
7 1/2" * 2 22
20
18
1,0
1,2
1,4
1,6 Mud Weight
1,8
2,0
2,2
m 21
6 3/4" * 2
20
6 3/4" * 2 6 1/2" * 2 6 1/2" * 2
19
6" * 2 6" * 2
18
4 3/4" * 2
17 16 15 14
1,
1,
1,
1, Mud Weight
1,
2,
2,
Figure 10.I - Dimensionless Unit (m) for Various Sizes of DC
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10.10.
PAGE
0
SUMMARY RECOMMENDATIONS FOR STABILISATION 1)
2) 3) 4) 5)
6)
7) 8) 9) 10)
11)
For the vertical section of the hole the purpose of stabilisation, more than any other factor, is to maintain the drift angle as low as possible to zero and, if applicable, to prevent wall sticking. For deviated holes, the stabiliser positions in the BHA depend entirely on directional drilling requirements and as a rule determined by the Directional Engineer. All stabilisers shall be the ‘integral type’ and machined from a single block of material or the ‘integral sleeve type’ fitted by head or hydraulic pressure (not threaded). The spiral profile of blades, for both string and near bit type stabiliser, shall be the ‘right hand type’. All stabilisers for hole size up to 121/4” must be the tight type in order to assure a complete (360°) contact with the borehole. All stabilisers for hole size over 121/4" must be open type but not less than 210°. All stabilisers should have a fishing neck with the same OD as the drill collars and a length not shorter than 20” for stabilisers up to 6” hole size and 26” for larger hole size stabilisers. All stabilisers smaller than 15" OD shall have three blades. Stabilisers larger than 15" shall have four blades as standard. Stabilisers (and subs, etc.) should be demagnetised after a magnetic particle inspection. The maximum allowable reduction value on outside diameter of stabilisers should be according to the attached tables . Tungsten carbide smooth surface solid body integral blade stabilisers are preferred. Integral sleeve stabilisers may also be used in large hole sizes above 121/4", mainly as the near bit stabiliser, in order to position the stabilisation point right on top of the bit. The maximum allowable wear of the stabiliser blades should be in accordance with the previous point. If such a limit is reached at any point, the stabiliser has to be replaced.
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Body OD
53/4 57/8 6 83/8 81/2 121/4 121/4 16 16 171/2 171/2 23 23 26 26 28
421/32 421/32 421/32 63/8 63/8 77/8 93/8 93/8 107/8 93/8 107/8 93/8 107/8 93/8 107/8 107/8
Rotary Conns
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REVISION STAP-P-1-M-6100
Hole Size
PAGE
Blade OD String Type
Blade OD Near Bit Type
Length of Fishing Neck
0
Length of Pin End
Length of Min Width Box of Blades Bit
NC 38 519/32 519/32 20 12 23 23 NC 38 5 /32 5 /32 20 12 23 27 NC 38 5 /32 5 /32 20 12 3 13 NC 46 8 /16 8 /64 26 12 5 21 NC 46 8 /16 8 /64 26 12 6 5/8 R 12 123/64 26 12 7 5/8 R 12 123/64 26 12 5 3 3 7 /8 R 15 /4 15 /4 26 12 5 3 3 8 /8 R 15 /4 15 /4 26 12 5 3 1 7 /8 R 17 /4 17 /4 26 12 5 3 1 8 /8 R 17 /16 17 /4 26 12 5 11 3 7 /8 R 22 /16 22 /4 26 12 5 11 3 8 /8 R 22 /16 22 /4 26 12 5 11 3 7 /8 R 25 /16 25 /4 26 12 5 11 3 8 /8 R 25 /16 25 /4 26 12 8 5/8 R 2711/16 273/4 26 12 Main dimensions of string and near bit type stabilisers in ins.
10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10
2 2 2 21/2 21/2 3 3 4 4 4 4 4 4 4 4 4
Table 10.D - Acceptable Dimensions For Used String And Near Bit Stabilisers The maximum overall length, for string type stabilisers only, must be as follows: • • • Hole Size
75" for 53/4" to 6" hole size stabilisers 85" for 83/8" to 121/4" hole size stabilisers 100" for 16" to 28" hole size stabilisers.
Body OD
Rotary Blade OD Length of Length Conn. String Type Fishing Neck Pin End 421/32 NC 38 527/32 20 12 3 5 6 /8 NC 46 8 /16 26 12 7 5 7 /8 6 /8 R 12 26 12 93/8 7 5/8 R 12 26 12 3 5 3 9 /8 7 /8 R 15 /4 26 12 3 5 3 9 /8 7 /8 R 17 /16 26 12 Main dimensions of string and near bit type stabilisers in ins.
6 81/2 121/4 121/4 16 171/2
Minimum Width of Blades 2 1 2 /2 3 3 4 4
Table 10.E - Acceptable Dimensions For Used String And Near Bit Stabilisers The maximum overall length must be as follows: • • •
75" for 6" hole size stabilisers 85" for 81/2" to 121/4" hole size stabilisers 100" for 16" to 171/2" hole size stabilisers.
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10.11.
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0
OPERATING LIMITS OF DRILL PIPE The design of the drill string for static tensile loads requires sufficient strength in drill pipe to support the submerged weight of drill pipe and drill collar below. The submerged load (P) hanging below any section of drill pipe can be calculated as follow:
[(
P = L dp x W dp
) + (L c
]
x Wc ) x K b
where: Ldp
=
Length of drill pipe in feet
Lc
=
Length of drill collar in feet
W dp
=
Weight per foot of drill pipe in air
Wc
=
Weight per foot of drill collar in air
Kb
=
Buoyancy factor
The difference between the maximum allowable tension and the calculated load represents the Margin of Over Pull (MOP): MOP = (Pt x 0.9) - P where: Pt 0.9
=
Theoretical tension load from table =
Design factor
The minimum recommended value of MOP is 60,000lbs (27t) and it shall be calculated for the topmost joint of each size, weight, grade and classification of drill pipe. The anticipated total depth with next string run and expected mud weight should be considered when calculating the MOP. The overall drilling conditions (directional well, hole drag, likelihood of becoming stuck, etc.) may require higher values of MOP. When the depth is reached where the MOP approaches the minimum recommended value, stronger drill pipe shall be added to the string. 10.12.
GENERAL GUIDELINES 1) 2) 3) 4) 5)
Packed hole assemblies shall generally be used unless otherwise dictated by hole conditions. Standard packed hole assembly should be: Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K Monel DC + String Stab + 2 DC + String Stab. A stabilised string can be used to drill out shoe-tracks after casing setting unless there is so much cement left inside the casing to discourage such a procedure. If the bottom hole assembly is different from the one previously used, run in the hole with maximum care, monitoring the weight indicator closely. Any indication of string dragging must be promptly detected. Tight zones must be reamed free before proceeding with the trip. Any change in the stabilisation from that specified in the drilling programme must be authorised by the Company Drilling Office
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11.
PAGE
0
BIT SELECTION This section is a guide to engineers in the selection of bits and bit optimisation.
11.1.
PLANNING Selection of the proper bits for a well programme is an important decision that has a big impact on well costs. Many factors need to considered and evaluated: • • • • •
Bit cost Method of drilling (turbine, rotary, air) Formation type and properties Mud system Rig cost
With emerging improvements in technology on bit design, it is necessary to optimise drilling operations by evaluating all of the above parameters. Drilling optimisation can be considered to having three phases: a)
Selection of the proper bit for drilling conditions
b)
Monitoring the drilling performance and conditions on the prospect well so that the performance is equal to or above the average in the area.
c)
Implementing a bit weight-rotary speed programme based on theoretical calculations that will improve the performance above the existing best performances in the area.
The last phase is difficult to implement in a one or two well drilling programme but is valuable in development drilling. However, often the first two phases are not given the importance they deserve 11.2.
IADC ROLLER BIT CLASSIFICATION The array of bit names and nomenclature in earlier years gave rise for the need of a standard classification system. In 1972 the IADC adopted a three digit classification system for roller bit nomenclature. Most bit manufacturers adopted the system followed by the API and the system now appears as API Recommended Practice 7G The original system uses a three digit code for classification constructed as follows: A, B, C where: A:
Is a number from 1-8, which is the major class
B:
Is a number from 1-4, which is the subgroup
C:
Is a number from 1-9, which is the speciality feature
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11.2.1. Major Group Classification The major classification number denotes the formation types in which the rollers bit should be used as per table 11.a below: Group Number
Formations
Mill Tooth Bits 1
Soft formations of low compressive strength and high drillability
2
Medium to medium-hard formations with high compressive strength
3
Hard semi-abrasive or abrasive formations
Insert Bits 4
Very soft formations
5
Soft to medium formations with low compressive strength
6
Medium-hard formations with high compressive strength
7
Hard semi-abrasive or abrasive formations
8
Extremely hard and abrasive formations Table 11.A â&#x20AC;&#x201C; Roller Bit Major Group Classification
Sub-Group Classification The subgroup classification is simply four progressive steps of compressive strength from 1 being low up to 4 for the highest within that major group. For example a 1-2 bit is a mill tooth bit designed to drill formations of a slightly greater compressive strength than required for a 1-1 bit, etc. Speciality Feature The code numbers and relative speciality features are shown in table 11.b below: Code Number
Feature
1
Standard
2
Air
3
Gauge insert
4
Roller seal bearing
5
Seal bearing and gauge protection
6
Friction seal bearing
7
Friction bearing and gauge protection
8
Directional
9
Other Table 11.Bâ&#x20AC;&#x201C; Special Feature Codes
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11.2.2. Bit Cones The range of bits listed in the major classification primarily has two types of cone. The original cutter bits had cone teeth machined out of the cone material by a mill, hence they were termed ‘Mill Tooth’ bits. These bits, however, were found to wear quickly when hard abrasive rocks were encountered. This resulted in the introduction of cones which had teeth inserted into the cone made of more wear resistant materials such as tungsten carbide. The inserts are of varying shapes to suit the best penetration in a particular rock. The mill tooth bit cone teeth can be heat treated to provide better wear resistance but only are good up to classification 3. Insert bits are used for range 4 through 8, see table 11.c below: Cone offset also has a significant effect on the penetration rate due to the shear mechanism which best suits the formation types. Type Mill Tooth Bits
Insert Bits
Class 1-1, 1-2, 1-3, 1-4 2-1, 2-2 2-3 3 4 5-2 5-3 6-1 6-2 7-1 7-2 8
Formation Type Very soft Soft Medium Medium hard Hard Very soft Soft Medium-soft Medium shales Medium limes Medium hard Medium Hard chert
Tooth Description
Offset
Hard-faced tip Hard-faced side Hard-faced side Case hardened Case hardened
3-4o 2-3 o 1-2o 1-2o 0o
Long blunt chisel Long sharp chisel Medium chisel Medium projectile Short chisel Short projectile Conical or hemispherical
2-3o 2-3o 1-2o 1-2o 0 0 0
Table 11.C– Roller Bit Type and Classification
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11.3.
PAGE
0
DIAMOND BIT CLASSIFICATION Two types of diamond bits are used for special applications where their cutting action is most efficient. These are natural diamond and the PDC (Poly-crystalline Compact).
11.3.1. Natural Diamond Bits Natural diamond bits are constructed with diamonds embedded into a matrix and are used in conventional rotary, turbine, and coring operations. Diamond bits can provide improved drilling rates over roller bits in some particular formations and all the diamond bit suppliers provide comparison tables between roller bit and diamond bit performance to aid users in bit selection based on economic evaluation. Some of the most important benefits of diamond bits over roller bits are: • • • •
Bit failure potential is reduced due to there being no moving parts. Less drilling effort is required by the shearing cutting action compared to the cracking and grinding action of the roller bit. Bit weight is reduced, therefore deviation control is improved. The low weight and lack of moving parts make them well suited for turbine drilling.
11.3.2. PDC Bits PDC or Stratapax bits were introduced in the 1970s and features the greater abrasion resistance of the diamond complimented by the strength and impact resistance of cemented tungsten carbide. The advancement in technology in PDC design and performance in recent years has been significant and there is now many manufacturers with wide ranges of bits now available. Due to the diversity of bits and bit features available, there is no IADC classification system similar to roller bits but simply a code to provide a means of characterising the general physical of fixed cutter drill bits. 11.3.3. IADC Fixed Cutter Classification To cater for the wide range of fixed cutter bits including natural diamond and PDC, IADC introduced the following classification system. The classification system consists of a four character code Code 1 - Cutter Type and Body Material (D, M, T, S, O) Code 2 - Bit Profile (1-9) Code 3 - Hydraulic Design (1-9) Code 4 - Cutter Size and Density (1-9) Code 1
Code 2
Code 3
Code 4
Cutter Type & Body Material
Bit Profile
Hydraulic Design
Cutter Size and Density
Table 11.D - IADC Fixed Cutter Classification Code
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Code 1 The subgroup classification is simply a five letter designation categorising the type of cutter and body material. Group Letter
Cutter Type and Body Material
D
Natural Diamond Matrix Body
M
PDC Matrix Body
T
TSP Matrix Body
S
PDC Steel Body
O
Other Table 11.E – Code 1 Cutter Type and Body Material
Code 2 The code numbers (1-9) categorise the bit profile by shape. Code 2
Bit Profile
1
Long Taper
Deep Cone
2
Long Taper
Medium Cone
3
Long Taper
Shallow Cone (parabolic)
4
Medium Taper
Deep Cone
5
Medium Taper
Medium Cone
6
Medium Taper
Shallow Cone (rounded)
7
Short Taper
Deep Cone (inverted)
8
Short Taper
Medium Cone
9
Short Taper
Shallow Cone (flat face)
Table 11.F– Code 2 Bit Profile Code 3 The code numbers (1-9) describe the hydraulic features. Changeable Sets
Fixed Ports
Open Throat
Bladed
1
2
3
Ribbed
4
5
6
Open Faced
7
8
9
Table 11.G - Code 3 Hydraulic Design
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Code 4 The code numbers (1-9) categorise the cutter size and cutter material. Light
Medium
Heavy
Large
1
2
3
Medium
4
5
6
Small
7
8
9
Table 11.H - Code 4 Cutter Size and Density An example bit code would then be M442 equates to a PDC bit with matrix body, medium taper-deep cone, changeable jets-ribbed design with large size cutter of medium density. 11.4.
BIT SELECTION Selecting the correct bit for the anticipated drilling conditions requires an evaluation of numerous parameters. Since the variety of bits available, outlined in the previous sections, is much wider with the introduction of innovative bit designs and the improvement in existing designs, the bit selection process is now much more complicated than it was previously. However there is still a simple guidelines that can be used to increase drill rates and, hence reduce drilling costs. The parameters involved in the selection of drill bits are: • • • • • •
Formation hardness Mud types Directional control Rotary system Coring Bit size
11.4.1. Formation Hardness/Abrasiveness As can be seen from the previous IADC bits are generally categorised by the hardness of the formation they can drill, however these classifications are vague but unfortunately no superior classification method exists. Some formations such as ‘medium to hard’ are sometimes wrongly defined because they had previously experienced low drilling rates although this was actually due to wrong bit selection or operating parameters used. Where a number of bits can be used, say to drill a soft formations, the bit selected will depend on other conditions such as mud type and hole size. Therefore, bit selection in soft formations becomes a matter of defining the conditions that produce the lowest drilling costs. Bit action in hard and abrasive formations is by failure in the compressive mode and as a result bits which use shear action are not very successful. In this case, roller bits in IADC code range 6-1-7 or higher are usually more successful as they have been designed for abrasive wear which may be very damaging to shear failure action bits.
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Formations with sticky characteristics, often resulting from clay rocks that are hydratable, the cuttings stick to the teeth or bit structure and impede drilling efficiency. Bits designed for sticky formations have a high degree of teeth inter-fit and hydraulics such as centre jetting capabilities. PDC, diamond and short tooth roller cone bits have been particularly unsuccessful unless when PDCs are used with oil based mud. In general, PDC bits drill faster than mill tooth or diamond bits in soft to medium-soft rocks unless they are sticky. This is substantiated by numerous results test reports. 11.4.2. Mud Types Oil based muds often reduce the drilling rates with roller cone bits whereas PDC and diamond bits are not effected. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness. Air drilling almost certainly requires the use of roller cone bits as air cannot provide sufficient cooling as liquids do, therefore causing bit failure. Cone bits are available with internal porting to the roller bearings keeping them cool enough and, although PDC and diamond bits do not have ant moving parts, the matrix and blade structures becomes weak and break. Diamonds themselves will fail around 750oC for polycrystallines and 1,200oC for natural. 11.4.3. Directional Control Directional control is affected by a number of factors including these relating to drill bits. The factors affecting directional control are: • • • • •
Method of drilling BHA design Type of bit Rotary bit cone offset, number of cones, cutting structure on the cone Bit weight
Rotary drilling operations are inclined to right-hand walk. This tendency is increased when using roller bits are used as cone offset from the bit centre increases. The advantage of increased drilling rate when using cones with higher offsets must be balanced with the difficulty in maintaining directional control. Turbine drilling may have a tendency to left-hand walk. This is controlled by the turbine used, bit gauge length, and BHA stabilisation. Some bit manufacturers have developed two and four coned roller bits purely for directional cone purposes. These are include in the IADC codes under special feature #8, e.g. 1-2-8 is a soft bit for directional control. Roller bits are also available with a special cutting structure that are caused by formation dip which normally induces movement towards the dip. The special feature is outside teeth that dig into a dipping formation thus preventing the movement towards the dip. High bit weights tend to increase directional control problems and, vice versa, low bit weights help maintain straight hole at a penalty in reduced drilling rate. Due to this PDC bits with their relatively lower bit weights and no cones, hence cone offset problems are favoured.
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11.4.4. Drilling Method The means of turning the bit with either the rig’s rotary system or downhole motor does not place any restriction on bit selection. However, in general in deep wells, PDC bits are preferred when using surface rotary systems as reduced weight on bit reduces torque due to bit and wall friction which can be significant. Due to turbine drilling efficiency, bits with long life expectancies should be used such as PDC, diamond and journal bearing insert bits. 11.4.5. Coring Bits used for coring must be designed so that it minimises flushing of the formation fluids from core by the mud. PDC or diamond bits are both used for coring operations and are selected by using the previous parameters outlined. 11.4.6. Bit Size 3 Roller bits are available off-the-shelf for almost all sizes between the range of 3 /8” – 26” in almost every type, cutting structure and jetting system. PDC and diamond bits are not available off-the-shelf as rotary bits in sizes over 15”.
In deep wells with small holes, i.e. 4” or 5”, the PDC bits have much better performance as they have no moving parts as rotary bits which have high failure rates due their small bearing areas. 11.5.
CRITICAL ROTARY SPEEDS The effect of rotary drilling speeds on the rate of penetration of toothed rotary bits is difficult to evaluate and has less impact than drilling weight. Apparent inconsistencies sometimes appear in the data which may be due to vibration originating at the bit which helps in the rock failure and so aids the drilling process. Vibration on the other hand is undesirable as it causes drill string material failures such as bearings and bit teeth or failures in drill string collars and drill pipe. It has often been proven that slower bit speeds and greater bit weight obtain faster rates of penetration. It might be thought that drilling rate should be proportional to rotary speed since the drilling occurs due to contact of between the bit teeth and the rock formations and that these are proportional to rotary speed. However this only holds true if the contact was equally effective at both slow and high rotational speeds. This linear assumption is not substantiated by any data and in fact penetration rates are less than linear. The following figure 11.a shows example drilling rates versus rotary speeds with differing bit weights and it is seen that the penetration rates are not linear to rotational speed. When drilling in a particular area, the bit records for previous holes drilled in the area or other offset data obtained should be analysed to determine the initial best bit programme then new technology or individual well requirements evaluated to perfect the programme. This will include rotary speeds. Most bit suppliers will provide data on optimum bit weight and rotary drilling speeds for specific areas of operation and most operating companies will also have built up a significant data base on the types of bits they have used on previous drilling projects with respective drilling parameters. These data from all of the sources should be evaluated to obtain the optimum drilling parameters.
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In practice the rotary speed should start slowly and increased until an optimum penetration rate is achieved without vibration. In general, if weight on a bit is increased, the RPM should be decreased and vice versa. Note:
Eni-Agipâ&#x20AC;&#x2122;s recommended weight on bit is 2ton/inch of hole diameter.
Critical rotary speed can be calculated by: Critical Rotary speed =
(
4760000 DP 2 + ID 2
)
1
/2
LP 2
where: DP
=
Diameter of drill pipe, ins
ID
=
Internal diameter, ins
LP
=
Length of pipe joint, ins
Figure 11.A - Rotary Speed Effect on Drilling Rate
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DRILLING OPTIMISATION In past years many attempts have been made to optimise drilling operations. Some of the efforts have been directed in: • • •
Developing drilling fluids to that yield high rates of penetration Improving solids control equipment to improve mud properties Designing bits to improve penetration rates, bit life or both
Nowadays, the primary criteria is economic resulting in optimisation based on the correct selection of bit weight, rotary drilling speed and bit types which produce the lowest cost per foot or metre, i.e. minimum cost drilling or MCD. The cost of the depth drilled during a single bit run is the sum of three costs, bit cost, trip costs and rig operating costs for the time required for the depth drilled. Dividing the bit run cost by the footage drilled, results in the cost per foot. The trip costs and rig operating costs are variable whereas the bit cost is fixed and generally less significant (Refer to figure 11.b). With MCD it should be noted that selection of proper bit weights and drilling speeds does not always yield the maximum ROP nor the longest bit runs.
Figure 11.B - Drilling Cost Per foot
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DIRECTIONAL DRILLING Controlled Directional Drilling can be defined as the technique of intentionally deviating a well bore so that, the bottom hole location or any intermediate portion of the hole, is positioned in a predetermined target(s) area, that is located at a given horizontal and vertical distance from the surface location of the well. Many new tools and techniques have been developed in recent years to enhance the accuracy of this technique.
12.1.
TERMINOLOGY AND CONVENTIONS True North:
The direction from any point on the earth's surface to the geographic north pole which is fixed.
Geographic North:
The direction from any point on the earth’s surface.
Magnetic North:
The direction from any point on the earth's surface to the magnetic north pole.
Magnetic Declination:
The angle between True North and the direction shown by the north pointer of a compass needle at the location being considered, measured from True North. Magnetic declination for a given location changes gradually with time, An annual rate of change is applied to give the present declination. The magnetic declination and rates of change are obtained from detailed charts or computer program. To obtain the geographic direction, the direction obtained from magnetic surveys shall be corrected simply by adding or subtracting the appropriate declination.
Direction:
Directions can be measured and given in three ways: •
Azimuth, where the angle is measured from north in a clockwise direction from 0 to 360° (for example: 252° AZ). • Quadrant Format (called ‘Field Co-ordinate’ or ‘Oil Field Format’), the direction is expressed as an angle E or W of N or S (the 252 AZ becomes S72° W). • Bearing Angle, the angle is measured from 0 to 180° East (positive) or West (negative) of North (108° W or – 108°). The correction due to magnetic declination is the same for any of the three formats. Inclination (Inc) also termed Drift:
The angle the centre line of the well bore makes with a vertical axis below the well. By definition, straight holes have zero angle of inclination. All inclination angles are positive.
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Target:
A predetermined area of interest whose position is defined by its horizontal and vertical distance from the surface location of the well.
Well Path:
The path of the bore hole drilled by the bit.
Projected Well Path:
The path expected of the bit to follow beyond the end of the well bore.
Station:
A survey data point. A station length is the measured footage between stations. The well path is described by all of the data points therefore a well path survey is all the data points surveyed.
Survey Data
The inclination angle, the direction of the well bore is pointing and the measured depth of the surveying instrument.
Build Up Rate (BUR):
The build-up should be kept as close as possible to the designated well trajectory ensuring that the rate of build-up neither lags behind nor exceed the projected well path. Large rates of build-up result in increased torque and wear on drill pipe and casing and in the problems associated with accidentally side tracking or formation of key seats. Insufficient build-up rate will result in an increased final angle required to achieve the objective; generally build-up rates of 1.5 to 3.0o/100ft are normally used.
Dog Leg Severity (DLS):
The rate of change of the combination of both inclination and direction of a well path between data points. It is usually expressed in degrees per 100ft or 30m interval drilled.
Tangent Section:
The section of the well starting from the end of build up and where direction and inclination are maintained constant.
Horizontal Displacement (or Horizontal Departure):
The distance projected onto a horizontal plane from the origin to the point under consideration.
Vertical Section:
The projection of the horizontal displacement onto a vertical plane usually along the target direction.
Lead Angle:
When drilling with rotary drilling assemblies there is a tendency for the hole to ‘walk to the right’. Turbine drilling assemblies have the opposite tendency, that is ‘walk to the left’. The lead is the angle to be applied to the project direction at kick-off to correct the walking tendency of the drilling assemblies.
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CO-ORDINATE SYSTEMS
12.2.1. Universal Transverse Of Mercator (UTM) In the Transverse Mercator Projection the surface of the spheroid chosen to represent the Earth is wrapped in a cylinder which touches the spheroid along a chosen meridian. From the centre of the globe (Refer to figure 12.a), shapes on the surface of the spheroid are transferred to the surface of the cylinder (A becomes A1 and B becomes B1). The cylinder is then unwrapped giving a correct scale representation along the central meridian and an increased scale away from it.
NORTH POLE (AXIS)
CIRCLE OF CONTACT A1
A
B1
B
Figure 12.A - Universal Transfer Of Mercator As a Mercator projection becomes increasingly inaccurate as one moves away from the chosen meridian, a series of reference meridians is used so that it is always possible to use a map with the reference meridian close to the place of work. The reference meridians used are 6 degrees apart providing 60 maps, called zones, to cover the whole world. The zones are numbered 0 to 60 (from west to east) with zone 31 having the 0o meridian (Greenwich) on the left and 6o E on the right. o
Each zone is further sub-divided into grid sectors each one covering 8 latitude starting from the equator. Grid sectors are identified by the zone number and by a letter ranging from C to X (excluding I and O) from 80o South to 80o North. Identification of the sector is simply the number and letter of the relevant area, i.e. 31U being the Southern North Sea (Refer to figure 12.b). The co-ordinates for each UTM grid sector are given in meters with the origins (i.e. the zero value) at a line 500,000m West of the centre meridian to avoid negative values and at the equator. The co-ordinates are given as Eastings and Northings.
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Example UTM co-ordinates of the rig: 410,261.0 E 6,833,184.2 N The rig is 500,000 - 410,261m west of the central meridian and 6,833,184.2m north of the equator. The bearing between any two points in the same grid sector is referenced to Grid North which is the direction of a straight line running from top to bottom of the map. Convergence is the angle ‘a’ (Refer to figure 12.b) between the Geographic North and the Grid North for the location being considered measured from Geographic North. In the northern hemisphere the convergence is positive for locations east of central meridian and negative for locations west of central meridian. The opposite applies for the southern hemisphere.
NORD (CENTRALMERIDIAN) G
G
G
N G True North
G
G
-
+
a EST EQUATOR LINE
WEST
+ CENTRAL MERIDIAN
SOUTH
Figure 12.B - Convergence Angle 12.2.2. Geographical Co-ordinates Generally rig and target co-ordinates are given in either UTM and/or geographical coordinates. Geographical co-ordinates are expressed in degrees, minutes and seconds for Latitude and Longitude. Each degree is subdivided into 60 minutes and each minute further subdivided into 60 seconds (Refer to figure 12.c). Example Rig location: 3°
36'
01.0"
E Longitude
40°
43'
06.5"
N Latitude
For the purpose of calculations degrees, minutes and seconds are often converted into decimal degrees. This is done by dividing the minutes by 60 and the seconds by 3,600 so that 3° 36' 01" becomes: 3 + 36/60 + 1/3600 = 3,600.278°
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N
° 80
N
0
80 °
60
0 5
10
15
S
20
25
30
35
80 °
40
45
S
50
55
° 80
THE METHOD OF ZONE NUMBERING ACCORDING TO THE UTM SYSTEM ESCH ZONE IS 6° LONGITUDE IN WIDTH AND EXTENDS FROM 80° NORTH TO 80° SOUTH 27
28 29
30 31
32 33
34 35
36
37 38 39
40 41
42
64 V
56 U
31 U
48 T
40 S
32 R
24 Q
16 P
8 N
0
DEGREE
-8 -24 -18 -12 -6
0
6
12 18 24 30 36 42 48 54 60 66 72
Figure 12.C - Grid Sectors
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RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT The first step in planning a well, starts with the data defining the rig and target locations, generally in UTM or geographical co-ordinates. With these data the horizontal displacement and direction to the target can be calculated. If the data supplied for the rig and target location are in geographical co-ordinates these must first be converted to UTM data.
12.3.1. Horizontal Displacement Using UTM co-ordinates (Refer to figure 12.d), displacement and direction can be determined with trigonometry as shown in the following example. UTM co-ordinates of rig:
410,261.0 E 6,833,184.2 N
UTM co-ordinates of target:
412,165.0 E 6,834,846.0 N
Absolute difference in Eastings:
1,904.0m
Absolute difference in Northings:
1,661.8m
1904,0 m
TARGET
48,9° 1661,8 m
H D 2527,21 m
RIG Figure 12.D - Example Calculation Of Horizontal Displacement The origin used may correspond to wellhead or slot in a template. The horizontal displacement (HD) to the target is thus: HD = (1661.82 + 1904.02)½ = 2527.21m
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12.3.2. Target Direction The bearing to the target is: φ
= tan1 (1,904.0 : 1,661.8) = 48.90° or N 48.90° E
12.3.3. Convergence The target co-ordinates and bearing, as calculated above , are relative to the Grid North. Since survey data make reference to the Geographic North (also called True North), the convergence must be applied to the target co-ordinates and bearing to present them relative to the Geographic North. Taking convergence as being 1.45° in this example (Refer to figure 12.e), it is necessary to rotate the target location about the origin of the well by -1.45° to place it in its relative position to True North.
True North
GRID NORTH NEW TARGET
Target Grid North
-1,45° Grid Convergence
RIG
Est EST
Fig. (a)
Fig. (b)
Figure 12.E - Example Grid Convergence In the previous example the bearing of the target with respect to Grid North was 48,90° or N 48.90° E. Then the target bearing relative to the True North is: 48.90 - 1.45 = 47.45° or N 47.45° E The horizontal displacement remains the same but its co-ordinates change. The True North co-ordinates of the target are calculated with trigonometry as follow: Eastings = 2,527.21 sin 47.45 = 1,861.76 Northings = 2,527.21 cos 47.45 = 1,708.98
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HIGH SIDE OF THE HOLE AND TOOL FACE The high side is the top of the hole viewed along the bore hole axis. Assuming the hole has an inclination, the low side is the path, that a small, heavy ball would follow if it is rolled slowly down the well (Refer to figure 12.f).
a
HIGH SIDE
HIGH SIDE
ROLLING BALL LEFT
RIGHT
a ROLLING BALL
LOW SIDE
LOW SIDE
VERTICAL
Figure 12.F - Definitions of Inclined Hole During a kick off or correction run, the measurement of greatest value is tool facing since it indicates the orientation of the bent sub. When a MWD or steering tool is used to control the deviation, tool face is referred to the high side of the hole when sufficient inclination exists (over 5o) or to magnetic North for low inclinations (up to 5o). The gravity tool face angle (GTF) is the projection onto a plane perpendicular to the hole axis of the angle between high side of the hole and tool face. The magnetic tool face angle (MTF) is the projection onto horizontal plane of the angle between magnetic North and tool face(Refer to figure 12.g) MAGNETIC NORTH
HIGH SIDE
45째 TOOL FACE
TOOLFACE
LEFT
RIGHT
LOW SIDE
Steering the mud motor by means of magnetic Steering the mud motor by means of toolface Bit and mud motor trying to kick off in gravity toolface Bit and mud motor trying to the direction of 45째 magnetic azimuth build angle and turn well to the right Figure 12.G - Magnetic Tool Face
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12.4.1. Magnetic Surveys Length Of Non Magnetic Drill Collar Magnetic instruments must be run inside a sufficient length of non-magnetic drill collars (NMDC or Monel Collar) made of special nickel alloy to allow the instrument to respond to the earth's magnetic field, by isolating it from the magnetic influence of the drill string. The required length of NMDC is determined by taking into account the following factors: â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘
The geographical area of operations. Since the earth's horizontal magnetic intensity varies geographically, a zone selection map is used to determine which set of empirical data should be used for a given area. The proportion of steel drilling tools below the NMDC. The direction and inclination of the well.
The Directional Drilling Contractor shall provide updated indication of magnetic intensity related to the area of operation. Compass spacing is generally recommended to be at or below the centre of the nonmagnetic collars. Magnetic Single Shot Surveys Prior to use, the instrument should be thoroughly checked out and tested to ensure it is in good working condition. After loading, the timer is set and synchronised with a watch on the surface. The time required for the instrument to fall is approximately 1,000ft per minute for inclinations up to 40o and 800ft per minute for inclinations over 40o. A safety margin of 5 mins shall be added to the calculated running time. Mud weight and viscosity are important factors to be considered, as are drill string restricted internal diameters. For high inclinations (over 60) sinker bars should be used and the survey barrel may need to be pumped down. The mud pump rate should be very low, giving just sufficient pressure to break circulation. The drill string may be rotated slowly (not however, if running the survey on wireline) and reciprocated to prevent sticking and assist the survey tool in reaching bottom. Drill pipe movement and pumping (if used) should be continued until a minute or so before the timer is due to operate.. If run on wireline, it should be taken into account the time the instrument generally takes longer to assemble and to run. Sandlines are quicker to run but can cause higher wear on drill pipe protective linings. Whichever wireline is used, thread protectors should be installed on the tool joint.
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Magnetic Multishot Surveys Magnetic multishot surveys are generally run prior to running casing as a check on the single shot surveys taken while drilling. This survey may be run either as an in run or running outrun survey, although it is generally run on the outrun wiper trip before casing. This gives an opportunity for the instrument to be retrieved at the casing shoe and checked whilst the trip back to bottom is being made. A second opportunity is then available if necessary. As the name implies, the magnetic multishot provides a series of single shot surveys. The camera of the instrument, instead of carrying one single shot disc, contains a length of photographic film. The film is exposed and advanced continuously, at a set time interval, from the time the instrument is started until stopped. The interval between exposure is generally 20secs but it is altered on some instruments. The survey is normally made by dropping the instrument into the drill string and allowing it to get to bottom before pumping the slug and commencing the trip out of the hole. As the drill string becomes stationary in the slips after each stand is broken off, the time since starting the instrument is recorded together with the number of stands out of hole. This enables the survey picture to be correlated to instrument depth. With an instrument set on a twenty second sample rate, good practice is to ensure there are a minimum of two surveys taken at each depth by remaining stationary. Steering Tool (with mud motor) Steering tools use a system of magnetometers and accelerometers to measure the Earth's magnetic field and gravity in order to determine inclination and direction. The tool is run on a conductor wireline which provides power for the sensors and returns the signal to the surface computer where it is decoded and relayed to the rig floor read out. The tool may be operated on one of two modes displaying tool face with respect to North (Magnetic Tool Face) or relative to the high side of the hole (Gravity Tool Face). The magnetic tool face mode is used in vertical or near vertical wells for kick off in the desired direction. As the inclination is increased above about 5o the tool is switched to gravity tool face. The advantages of steering tools over single shot orientation are in the continual read-out of the tool face whilst drilling and in saving time in situations where orientation problems may require repeated single shot surveys. One of the drawbacks of the system is the time required to pull the tool out of hole for making pipe connections. The steering tool system is used only in specific situations, i.e. KOP in a high temperature zone. When a motor is used for kick off or correction runs (operations not requiring rotation of the drill string), a side entry sub may be used. This sub prevents the need to pull the tool to make connections. The wireline passes through the entry sub enabling the drill pipe to be added to the string in the normal manner.
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Measurement While Drilling (MWD) Measurement While Drilling is a technique which takes various downhole measurements and transmitting these data to the surface for decoding and display. The most common transmission media is mud pulse telemetry in which the flowing column of drilling mud is modulated periodically by some mechanical means within the downhole assembly. The intermittent pressure pulses are transmitted from downhole to the surface where they are detected by a pressure transducer mounted in the standpipe. The transducer converts the mud pulses into electrical signal that is then transmitted to the surface computer. The computer decodes and displays this transmitted information. There are three distinct types of MWD transmission systems currently available, all using mud column as their transmission medium: â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘
The positive system uses a plunger type valve that momentarily obstructs mud flow thus creating a positive, transient pressure pulse. The negative pulse system utilises a valve that momentarily vents a portion of the mud flow to the borehole annulus, resulting in a negative, transient pressure pulse. The continuous wave system utilises a spinning, slotted rotor and slotted stator that repeatedly obstructs mud flow. This operation generates a continuous low frequency fluctuation in standpipe pressure of approximately 50psi.
One of the most common applications for a directional MWD system is to orient downhole motor/bent sub assemblies when changing the course of the well path. Sensors located immediately above the bent sub, taking measurements while the bit is drilling on bottom, provide immediate data (inclination, azimuth and tool face) to the Directional Driller. As already discussed in the description of steering tool systems, tool face may be referred to magnetic North or high side of the hole, depending on hole inclination. 12.4.2. Gyroscopic Surveys Gyro instruments are used when the proximity of casings or other magnetic interference precludes the use of magnetic tools.
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Gyro Single Shot Surveys Gyro single shot surveys are run on wireline. Since gyroscopes are delicate instruments, running speeds should be within that recommended and the tool stopped and started off gently. The gyro instrument has the same mule shoe feature as the magnetic single shot used for orientation and, although it uses a different system, the data obtained is the same, (i.e. hole direction, inclination and tool face). The maximum depth to which they can be effectively run is approx. 1,300ft about 400m. This is a limitation imposed by the time taken between orienting the gyro on surface, running into hole, taking the survey, pulling out of hole and checking the orientation. The difference in azimuth between the initial orientation and final check on return to surface is the amount the gyro has drifted or wandered off its true north orientation. The drift is assumed to be constant for the time interval between initial and final orientation. The correction is calculated by simply determining the proportion of drift occurring in the time from the initial orientation to the survey picture being taken. Gyro drift is approx. 4o per hour o in static conditions and 8 per hour in dynamic conditions. Gyro Multishot Surveys The gyroscopic multishot is the survey tool for surveying extended intervals inside casing or drill pipe without a non-magnetic drill collar. The tool comes in two sizes. The smaller one can be run in completed wells or through drill pipe. The larger one is a more rugged tool and is used to run surveys inside casing. Depending on the length of survey run, it will be a number of hours before the calculated survey data are available. Gyro multishot drifts are the same as that of the single shot gyro. Surface Read-out Gyroscopes Surface read-out gyroscopes are used for the same purposes in single shot and multishot data collection. The instrumentation is more sophisticated and requires a conducting wireline to power the tool and transmit the information back to the surface for decoding by computer. With a surface read-out multishot gyro, the drift can be constantly monitored to ensure the tool is performing well and the calculated survey is produced shortly after completing the log run. Gyrocompass (North Seeking Gyroscope) These instruments use the principle of earth rate gyro compassing to define true azimuth and inclination in near vertical parts of the borehole. Then, as the hole builds angle to above 15째 it switches to a continuous integrating mode. This dual mode makes the tool accurate in either vertical and deviated borehole where it eliminates the inaccuracies that gyrocompass based instruments have at high latitude, high inclination or in the East/West axis. The rugged construction makes these tools capable of steering and surveying while drilling (Gyro While Drilling).
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12.4.3. Survey Calculation Methods When drilling on a cluster, the co-ordinates of the centre of the 30" conductor shall be used on the rig for computations of each individual well. The centre of the cluster may be used by the Company Drilling Office for mapping, planning and reporting. There are a number of methods of calculating the wellbore trajectory from the survey data. The most common are: •
•
•
Average angle method: It assumes the borehole is parallel to the simple average of both the drift and bearing angles between two survey stations. It is fairly accurate and calculation is simple enough for field use with a non programmable scientific calculator. Radius of curvature: Using sets of angles measured at the upper and lower ends of sections along the surveyed course length, it generates a space curve representing the wellbore path. For each survey interval, it assumes that the vertical and horizontal projections of the curve have constant curvature. Minimum curvature method: shall be used on the rig, in Company Drilling office and Directional Drilling Contractor office for survey computations. It assumes the borehole is a spherical arc with minimum curvature (maximum radius of curvature) between survey stations. It is the most accurate for most boreholes, however it requires very complex calculations using a programmable calculator or computer.
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Average Angle method
(
)
∆ North = ∆MD x sin(l1 + L 2 ) / 2 x cos A1 + A 2 / 2
∆ East = ∆MD x sin(l1 + l 2 )2 x sin(A 1 + A 2 ) / 2
A1
∆ Vertical = ∆MD x cos(l1 + l 2 ) / 2
A2 I1
N W
I2 E
S
Radius Of Curvature Method
∆ North = ∆ East =
∆MD x (cos l1 − cos l2 ) x (sin A 2 − sin A1) (l2 − l1) x (A 2 − A1)
∆MD x (cos l1 − cos l1) x (cos A1 − cos A 2 ) (l2 − l1) x (A 2 − A 2 )
A1
I1 A2
I2
N
Minimum Curvature Method
(
E
W
)
S
∆ North = (∆MD) / 2 x sin l1 x cos A1 + sin l2 x cos A 2 x RF ∆ East = (∆MD ) / 2 x (sin l1 x sin A 1 + sin l2 x sin A 2 ) x RF
∆Vertical = (∆MD ) / 2 x (cos l1 + cos l 2 ) x RF
DL 2
RF = 2 / DL x tan (DL / 2)
DL 2
A1
cos(DL ) = cos(l − l) − sin l x sin x [1 − cos (A − a )]
I1 DL
N
A2 I2
E
W S
F i gure 12.H - Survey Calculation Methods
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12.4.4. Drilling Directional Wells Kicking Off The Well Jetting is the term used to describe the deviation of a well using bit hydraulics to erode the formation in a particular direction. A special jetting bit may be used or a conventional tricone bit run with two undersized and one oversized (or blanked) jet nozzles. Usually the bit is run on a typical build up assembly (bit, full gauge near bit stabiliser, orienting sub, non-magnetic and steel-drill collars as required) and once on bottom the blind nozzle, representing the â&#x20AC;&#x2DC;tool faceâ&#x20AC;&#x2122;, is oriented in the desired direction. Maximum circulation is then established and the washing action begun. Some of string weight is slackened on the bit and the weight indicator will give an indication of drilling off if the formation is soft enough to be washed out. In formations where the degree of compaction makes jetting ineffective, deviation is started with a downhole motor. This has become the most commonly adopted method of kick off. With downhole motors, bent and orienting subs (or combined bent/orienting sub) are required. With the deflection assembly in the hole, there is a correction to apply to the desired tool face setting or proposal direction. This correction is due to the reactive torque developed by downhole motors. Reactive torque is dependent on motor power, weight on bit, formation, hole inclination and drilling assembly design and length. The actual value of reactive torque must be assessed as drilling proceeds as it is unique to the conditions prevailing. During the kick off, the advantages and/or disadvantages of the different methods of orientation are highlighted. With single shot orientation, reactive torque can only be estimated based on the experience of the Directional Driller in the area of operation. Since the survey tool is at least one joint above the bit, the first assessment of actual reactive torque can be made only after the second joint has been drilled. Steering tools provide the most accurate measurement of tool face position. A continuous read-out on surface enables adjustment of the weight on bit/rate of penetration in order to maintain a constant tool face. MWD tools provide the same information with the advantage of not require a wireline and the consequent rigging up and trip time. On the other hand, steering tools provide extremely high data rates that may be of critical importance when drilling with very high rates of penetration. Build Up Section After the desired direction has been reached, the kick off assembly may be replaced with a rotary build up assembly. However, if jetting has been the method of initial control, drilling can continue with the same BHA in the rotary mode without requiring a trip. Selection of the appropriate build up assembly is dependent upon the angle achieved during initial kick off and maximum angle required. The decision of when and if to replace the kick off assembly depends on several factors such as hole size, weight on bit and rate of penetration, response of the kick off assembly, residual bit life and final planned inclination. Controlling the BUR is imperative if fatigue to drill pipe and drill collars is to be avoided.
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This can be accomplished by varying the drilling parameters (weight on bit, rotary speed and pump pressure) or changing the BHA. In this case careful assessment must be made to consider whether the amount of time lost in tripping out of hole to change the assembly, would be gained later with a better rate of penetration or by preventing difficulties. The alternative is to accept the current performance and make adjustments at the next bit trip. Tangent Section (Hold On Section) When the desired inclination has been reached, the kick off or build up assembly is replaced with a stiff bottom hole assembly that will maintain the inclination and direction. Small variation in behaviour of a BHA can be obtained by adjusting the weight on bit and rotary speed. Providing it is necessary, the earlier a correction to inclination or direction can be made the better it is. As the bit get closer to the target, longer corrections are required to get the well back on the target. Advanced planning should be continuously done during operations to ensure that, should a trip become necessary at short notice, any change to the BHA may be made at the same time. Drop Off Section Drilling a directional well it may be necessary to allow the drift angle to straighten back to vertical or near vertical. Drop off assemblies should be used starting with the least successful. The reason being that the higher the inclination, the greater the pendulum effect and the same rate of drop might be achieved with the least successful assembly at 50° and the most successful assembly at 30°. Therefore, as the inclination is reduced, stronger dropping tendency assemblies may be run to maintain the rate of drop required. Only where the maximum negative side force is required, at low inclinations and in hard formations, should pendulum assemblies be run (i.e. assemblies without a near bit). Care Of Stabilisers The bottom 120 (40m) of a drilling assembly is the critical portion for controlling a directional well. The stabilisers used in this area should be full gauge to 1/16" under unless undergauge stabilisers are required to hold or drop angle. Stabilisers shall be gauged each trip: undersized tools should be moved up higher in drill collar assembly or replaced with full gauge tools. All stabilisers shall be magnafluxed at the end of each well phase. As a general rule, do not drill out casing shoe with a ‘packed hole assembly’. However, the decision whether or not to use stabilisers to drill casing shoe shall be evaluated case by case.
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String Stabilizer Drill Collars
60' Drill Collars
Maximum Angle Building Assemblies
30' Drill Collars
Near Bit Stabilizer
Near Bit Stabilizer
Bit
Bit
String Stabilizer
String Stabilizer
30' Drill Collar 30' Non Mag. Drill Collar 30' Non Mag. Drill Collar Near Bit Stabilizer
Near Bit Stabilizer
Bit
Bit
Maximum Angle Building Assemblies
String Stabilizers String Stabilizer 30' Non Mag. Drill Collar
String Stabilizer 30' Non Mag. Drill Collar
30' Non Mag. Drill Collar
String Stabilizers
String Stabilizers
10' Drill Collar
10' Drill Collar
Near Bit Stabilizers
Near Bit Stabilizers
Bit
Bit
String Stabilizer
10' Drill Collar
Near Bit Stabilizer Bit
Figure 12.I - Build up Assembles
Packed Hole Assemblies
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Bottom Hole Assembly Response Assembly
Response
No.
Relative * response stenght
Bit
Near bit stabilizer (Approx. 3-5' from bit face to leading edge of stabilizer) 90'
1
Build
10
2
Build
8
3
Build
7
4
Build
7-3
5
Build
7-5
6
Build
5-3
7
Build
4-2
60'
30'
60'
30'
30'
45'
15'
8
Build (drops under certain circumstances)
30'
30'
30'
15'
30'
30'
15'
30'
30'
15'
30'
5-10'
30'
45'
3-2 30'
9
Hold
1
10
Hold
10
11
Hold
9
12
Hold
8
13
Hold
5-8
14
Hold
1-3
15a
Drop
10
15b
Drop
10
16
Drop
5 - 10 **
17
Drop & Build
30'
30'
30'
30'
60 - 70'
60 - 70'
30'
45'
18 19
170 OF 230
30'
drop (at highter incl.) and/or Build (at lower incl.) Drop or Build (highly dependent on collar OD)
* 10 is the highest and 1 is the lowest
30'
= Undergauge
** (smaller holes con be better than 15)
Figure 12.J - Bottom Hole Assembly Response
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Figure 12.K - Common Holding Assembly
Figure 12.L - Drop Off Assembly
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12.4.5. Dog Leg Severity Changes in hole curvature are often referred to as dog-legs The severity of a dog-leg is determined by the average changes in angle and/or direction calculated on the distance this change occurs. For example, if there is a 3° change in angle (no direction change) over 100ft of hole, the dog-leg severity is 3° per 100ft. Until a dog-leg reaches some threshold value, no drill stem fatigue damage occurs. This threshold value is called Critical Dog-leg. The critical dog-leg is dependent upon the dimension (size) and metallurgy of the drill pipe and drill pipe tension (pull) in the dog-leg. The planning of directional wells should include a ‘Dog-leg control programme’. Critical dog leg limits should also considered for drill collars. Dog-leg limits are established to prevent drill pipe fatigue, but when those limits are maintained, there is also a reduction in associated hole problems. Excessive dog-legs cause key seats, casing wear, rotating torque, trip drag, etc. Overall drilling rate can be greatly improved by a carefully planned and executed dog-leg control programme
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13.
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0
DRILLING PROBLEM PREVENTION MEASURES It is necessary to for drilling engineers to anticipate potential drilling problems which may occur during a well programme in order that he can make suitable arrangements in the planning and preparation stage of a project. Anticipation of problems may result in having suitable equipment and stocks of materials available on site or in the warehouse, ultimately leading to a saving in rig time and cost. Descriptions of some of the problems are given below with possible causes, preventative measures or solutions. Refer to the ‘Drilling Procedures Manual’
13.1.
STUCK PIPE The following is a list of the different types of pipe sticking which can occur due to: • • • •
Differential sticking. Hole restriction. Caved in hole. Hole irregularities and/or change in BHA.
It is impossible to lay down hard rules which will successfully cover all the case, however, for each situation, indications about the possible causes of the problem, preventive measures and remedial actions are listed in the following subsections. Detailed procedures should be based on each particular case, evaluating every aspect of the problem and applying any past experience gained in the area concerned.
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13.1.1. Differential Sticking Causes This phenomenon can occur, where there is case of high differential pressure between the mud hydrostatic pressure and the formation pore pressure. Some indications of pipe becoming differentially stuck may be: • • • •
The string becomes stuck in front of a porous formation. Pipe has not been moved for a period of time before getting stuck i.e. during a pipe connection. Circulation is free with no pressure variation. A normal amount of cuttings is observed at the shaker.
Preventive Measures When conditions for a potential differential sticking are encountered, the risk can be minimised by applying the following procedure: a)
Reduce the mud weight as much as possible, maintaining the minimum differential pressure necessary for a safe trip margin.
b)
Reduce the contact surface by using spiral type drill collars also called NWS( No Wall Stick) and using properly a stabilised bottom hole assembly. A shorter BHA with a greater number of HWDPs could be considered.
c)
Use mud with minimum solids content and low filtrate in order to obtain a thinner wall cake.
d)
Reduce the friction factor by adding lubricants to the mud.
e)
Keep the pipe moving and in rotate as much as possible.
f)
Consider the use of a drilling jar/bumper.
Methods of Freeing Pipe 1) 2) 3) 4) 5) Note:
Work the pipe applying cyclic slack-off and overpull combined with torque Always check the reduction in the pipe yield stress due to the application of the torque. Spot oil-base mud or oil containing a surfactant around the drill collars. Reduce the mud weight, if possible. Use a drilling jar/bumper. Conduct a DST procedure. Quick reactions are fundamental in freeing the wall of stuck drill pipe, since the problem becomes worse through time.
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13.1.2. Sticking Due To Hole Restrictions Causes The most common causes of hole restriction: • • •
Too thick a wall cake due to the use of high solids/high filtrate mud across porous and permeable formations. Swelling of formations containing clay. Extrusion of gumbo shale into the wellbore in underbalance situations.
Preventive Measures Problems are usually suspected by incurring increase drag during connections. Once the cause is recognised to be any of the three causes previously listed above, the following actions should be undertaken: a)
Reduce mud filtrate, cake and solids content.
b)
Use inhibited mud.
c)
Increase mud weight.
d)
Increase mud clearing capacity.
e)
Increase flow rate.
In all situations, frequent wiper trips can reduce the problem and provide information on the severity. Methods of Freeing Pipe 1) 2) 3) 4)
Work the pipe applying slack-off if the string has become stuck pulling out, and overpull if it stuck while running in. Spot a cushion to break and remove the mud cake around the drill collars. Increase the mud weight, if possible. Use a drilling jar/bumper.
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13.1.3. Sticking Due To Caving Hole Causes This problem is mainly experienced in shale sections. The most common causes are: • • •
Hydration and swelling of clay minerals when in contact with fresh mud filtrate. Insufficient supporting action of the mud hydrostatic column. Mechanical action of the drill string.
Preventive Measures Depending on the various causes, there are different prevention possibilities, to reduce the severity of the problem and to avoid the consequences of sticking the string. Possible mud changes are: a)
Reduce water losses.
b)
Lower pH value to 8.5 to 9 (if needed).
c)
Use inhibited mud.
d)
Add mud stabilising compounds (mainly sodium asphalt sulphonate).
e)
Increase the mud weight.
f)
Increase the YP/PV ratio to create laminar flow on the wall after pipe.
g)
Increase the gel value to obtain a good cutting suspension when circulation is stopped.
Note:
It is not always drilling with underbalance which results in a caving hole.
Possible BHA changes are: a)
Use bits without nozzles, particularly when reaming, to avoid scouring the well.
b)
Use the minimum acceptable number of stabilisers.
Possible changes in parameters are: a)
Reduce rotary speed, if possible, to 80rpm or less.
b)
Reduce the mud flow rate to obtain laminar flow in the annulus between hole and drill collars.
c)
Avoid long circulation times across unstable sections.
d)
Do not rotate pipe when tripping. Use a spinner or chain out.
e)
Trip out with care to avoid swabbing. If any swabbing occurs, pull out with the kelly on.
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Methods of Freeing Pipe 1) 2) 3)
4)
Note:
If circulation is possible, keep circulating trying to expel the caving. If the string becomes stuck across a carbonate formation, spot an acid pill. If circulation is blocked, try to regain it by applying pressure shocks and working the pipe at the same time. Special care is required to avoid breaking the formation i.e. overcoming fracture gradient below the stuck point. Use a drilling jar/bumper.
The problem of pipe sticking due to cuttings dropping out is not necessarily related to a caving hole. The origin of such problems can also be an excessive rate of penetration in large holes and inadequate carrying capacity of the mud. In this case, change the mud properties and flow rate and, if necessary, limit the rate of penetration.
It is good practice to spot high viscosity pills from time to time to keep the hole clean. The methods of getting pipe free in this situation are the same as listed above.
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13.1.4. Sticking Due To Hole Irregularities And/Or Change In BHA Causes The causes for sticking, related to, hole conditions and change in BHA, are: • • • • • •
Dog legs. Key seats. New bit is run following a dulled bit which was undersize. New stabilisers run to replace previous worn stabilisers.. String is stiffer than the previous one.. Rock bit run after a diamond or a core bit.
Preventive Measures a)
The formation of dog legs can be prevented by the use of packed bottom hole assemblies.
b)
Dog legs can be eliminated by using very stiff BHA's and reamers.
c)
A key seat can be eliminated by reaming it with a key seat wiper or an undergauge stabiliser installed on the top of the drill collars.
d)
Always ream a whole interval drilled with the previous bit.
e)
Ream always the cored section, even if a full gauge core bit was used.
Methods of Freeing Pipe 1)
2) 3)
Work the pipe applying slack-off if dog leg or key seat (the string becomes stuck pulling out) and overpull if running a new BHA (the string becomes stuck while running in the hole). Spot on oil-based mud or oil containing a surfactant around the stuck point. If the stuck point is in a calcareous section, spot an acid pill.
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13.2.
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OIL PILLS Depending on the specific gravity of the mud in the hole, two different types of oil pill can be used to help free pipe.
13.2.1. Light Oil Pills To be used for mud specific gravity up to 1,350g/l (11.3 PPG). The standard pill will be obtained adding 10 to 30l/m3 of surfactant to oil (diesel oil, crude oil or used engine oil). The procedure for the use of pill is the following: 1) 2) 3) 4) 5) 6)
The pill volume shall be at least twice the volume of DC-open hole annulus (take into account excess for compensating hole enlargement). Pump at the maximum practical rate. Displace in order to have a pill volume in the annulus 1.3 times the volume of the DCopen hole. At 30 to 60mins intervals, circulate out of the string batches as a balanced plug. Work the string at the same time. Repeat the procedure if the pill does not succeed (the pill may be active for 4 to 16 hours).
13.2.2. Heavy Oil Pills To be used for mud of a specific gravity greater than 1,350g/l (11.3 PPG). For pill preparation clean a mud pit and mix (the ratios among the various components varies depending on the required density): • • • • • •
Fresh water Calcium chloride Diesel oil (maximum 200l/minute) Emulsifier (maximum 1 sack/minute) to be added at the same time as the diesel Viscosifier (heavy stirring for at least 15 mins is required) Barite.
While mixing, continuous agitation is compulsory .
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The procedure for the use of the pill will be the following: 1) 2) 3) 4) 5) 6) 7)
The pill volume will be at least twice the volume between the drill collars and the open hole (take into account excess for compensating hole enlargement). Pump a cushion of diesel oil with 5% Free Pipe, or similar, ahead and behind of pill. Pump at the maximum practical rate. Displace in order to have a pill volume in the annulus 1.3 times the volume of DCopen hole. At 2 to 3hr intervals, circulate out of the string batches of 300 to 600ltrs. Work the string at the same time. Repeat the procedure if the pill results ineffective (the pill may be active for 20 to 48hrs).
Note:
When the oil pill is circulated out of the hole it shall be recovered and stored separately.
Note:
Take into account the influence of the pill on the hydrostatic pressure.
13.2.3. Acid Pills The use of acid pills can be successful if the string gets stuck across of a carbonate formation. Considering the risks related to this operation, this should be carried out only if other methods prove to be ineffective. a)
Decisions concerning pill's characteristics (volume, compositions, strength, displacement schedule, etc.) shall be taken, on a case by case situation, after consultation with the Company Drilling Office.
b)
Whichever recipe is adopted, consideration has to be given to the corrosion problem. The proper amount of corrosion inhibitor shall be used and the acid pill will be spaced with oil or water ahead and behind.
c)
Due to the acid reaction, gaseous products develop in the well and special care is required when circulating out the pill. It may be necessary to circulate through on the choke and line up the surface equipment to safely dispose of the gas.
d)
While displacing the acid in front of the formation, the gaseous product will cool off the drill string. To avoid breaking, do not work the string but only apply an overpull or slack off.
e)
As a result of the acid action, the permeability of the formation will increase, thus creating the conditions for possible mud losses.
Whenever acid is handled, the appropriate safety measures shall be adopted: • • •
Wear gloves and protective clothing and have eyes protected with goggles. Ensure there are safety showers available for any personnel who come into contact with acid. Have water sprays ready to wash spilled acid. Ensure proper ventilation if the pill is mixed in a closed area.
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13.3.
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FREE POINT LOCATION If it is confirmed that it is not possible to free the string by working the pipe and spotting oil or acid pills, the string shall be backed-off in order to allow proceeding with a different method, such as running jars or wash pipes, or abandon the hole and side-track. There are two methods for estimating the depth at which a string is stuck: • •
Applying tension and measuring the pipe stretch. Locating the tow point with a free-point indicating tool.
13.3.1. Measuring The Pipe Stretch A reasonable estimate of the depth at which the pipe is stuck can be obtained by calculation using Hooke's Law. Applying two different tensile loads (T1 < T2) to the drilling string, two magnitudes of stretch (S1 < S2) are measured. Calculating: the differential stretch (E = S2 - S1), differential pull (P = T2 - T1) and applying Hooke’s Law, it is possible to determine the depth of free point (L) using the following formula. SI UNITS
L=
API UNITS
26.374 x Wdp x E P
where:
L=
735,294 x Wdp x E P
where:
L
=
Length of free pipe in m
L
=
Length of free pipe in ft
Wdp
=
Plain end pipe weight in kg/m
Wdp
=
Plain end pipe weight in lbs/ft
E
=
Differential stretch in mm
E
=
Differential stretch in ins
Differential pull in kN
P
=
Differential pull in lbs
P
=
The value obtained is less reliable as deviation increases due to down hole friction. Another minor inaccuracy is introduced by neglecting the changing cross section of the string at the tool joints.
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13.3.2. Location By Free Point Indicating Tool A Free Point survey shall be run to select the back-off point. Free Point Indicators are essentially accurate strain gauges which measure molecular rearrangement between drag springs, setting dogs or electromagnets. The tool is run on a logging cable through which measurements of torque and stretch are sent to surface read-out instruments. The Free Point Indicator is lowered to various depths and, at each depth, tension and torque are applied to the string at the surface. The strain gauge indicates whether the pipe reacts at that depth to the applied tension and applied torque. The read-out of the instrument is given in percentage i.e. 100% represents entirely free pipe. Pipe which appears to be free in tension does not always react to applied torque. There is a greater chance of succeeding with the back-off if the pipe is free under both tension and torque. Separate slim acoustic logs are designed to indicate intervals of stuck, partially stuck or free pipe, which may exist below the upper stuck point. Interpretation of free point data is very subjective and susceptible to operator skill, hole condition, etc. 13.3.3. Back-Off Procedure Drill pipe or drill collars can be unscrewed downhole by exploding a charge inside a selected tool joint connection, close to the stuck point. Requisites for a successful back-off are the following: • • • • •
There must be sufficient minimum inside diameter. The charge must be accurately placed across the connection There must be sufficient string shot strength. Neutral or slightly positive tension is applied at the back-off point. Sufficient left hand torque must be applied at the back off point.
As a general rule, the first attempt to back-off should be made at the first connection above the free point. If there is a failure, the second attempt should be performed on the first stand above the free point. Subsequent attempts should be made moving upward one stand at a time.
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13.4.
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FISHING
13.4.1. Inventory Of Fishing Tools The following tools shall be always available on the rig for the various hole sizes drilled: • • • • • • • • • • • • •
Fishing jars to match the drill collars in use. Bumper subs to match the drill collars in use. Overshot and oversize guides with grapples, baskets and extension subs, to catch all diameters of tools in hole. Taper taps for drill pipe body and tool joints. Junk baskets or Globe-type baskets. Reverse circulation junk baskets. Junk subs. Fishing magnets. Milling tools. Re-dressing tools for 5" and 31/2" sheared DP. Impression blocks. Fishing tools to catch electrical log tools (supplied by electrical log contractor) and relevant crossover. Safety joints.
13.4.2. Preparation Before fishing operations the following preparations shall be carried out: 1) 2) 3) 4) 5) 6)
Apply the greatest accuracy to all measurements. Draw a complete sketch of the equipment to be run, specifying lengths, inside and outside diameters and a description of each tool. Make sure that the Contractor's personnel directly involved in operations is fully acquainted and familiar with equipment to be used and its limitations. The fishing equipment should arrive to the rig fully inspected. Further inspection and maintenance shall be carried out on the rig if in prolonged use. Keep mud properties in good conditions at all times. Keep rig the equipment in good working conditions at all times.
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13.4.3. Fishing Assembly The standard fishing assembly consists of the following: • • • • • •
13.5.
Fishing tool + Jar and Bumper Sub + Drill Collars + Heavy Weight Drill Pipe + Drill Pipe. Use as many drill collars as is in the fish. If the required number of drill collars is not available on the rig, use a jar accelerator. A Safety Joint should not be run. Since the Safety Joint will not transmit left hand torque, it would not be possible to back-off below it using a string shot. However, a Safety Joint could be run between the catching tool and the jar when a non releasing tool such as taper tap is being employed. Avoid any restrictions in the bore of tools, run above the catching tool, which would prevent the use of a cutting tool or the back-off shot within the fish. Where losses are expected the use of a Circulation Sub in the fishing assembly should be considered.
FISHING PROCEDURES
13.5.1. Overshot Plan the operation taking into account the following factors: • • • • • •
The catching action of the tool will stress the fish neck in words. A regular, smooth shape of the fish neck is necessary for a successful operation. Jarring is only possible only using type SFS, FS and XFS overshots. If the fish diameter is near the maximum catch or size, a spiral grapple is recommended. On the other hand, if the fish diameter is considerably below the maximum catch size, a basket grapple is preferable. If the hole is enlarged, use an oversize guide or run a bent drill pipe just above the overshot. When the fish has been milled over, if possible, run an overshot extension to avoid catching the fish by the milled part.
13.5.2. Releasing Spear Plan this operation taking into account the following factors: • • • • •
The fish will be stressed outwards due to the catching action of the tool. A regular, smooth shape of the fish is essential for a successful operation. To allow unlatching of the spear, if it is not possible to run an adequate number of drill collars above the releasing spear, the use of a bumper sub is recommended. Install a pack-off on the tool, if circulation is required after latching the fish. Use the fishing jar If jarring is required. In this case the use of a spear stop is required. Check the Spear Stop OD when it is used in open hole and use the stop only if hole condition permits.
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13.5.3. Taper Taps Plan this operation taking into account the following factors: • • • •
The size of the taper tool should be selected in order to engage the fish with the middle of the tapered point. The taper taps do not allow free passage to the back-off tool. Excessive torque can damage the tapered thread and swell the top of the fish. It is nigh impossible to release the tool once engaged. For this reason its use has to be considered the last resort and only used after consultation with the Eni-Agip Shore Base (Drilling Manager/Superintendent).
13.5.4. Junk basket This procedure is more successful in soft formations. A reverse circulation type junk basket is preferred to a forward circulation type. Plan the operation to use the following parameters: • • •
WOB = 2 to 4t Rotary = 45rpms Low Pump Rate (1/2 pump rate while drilling).
13.5.5. Fishing Magnet Magnets can be successfully used but only in hard formations to retrieve small steel objects such as bit cones, bearings, slips, tong pins and milling cuttings. To avoid sticking the fish in the hole, weight must not be applied. Fishing magnets may be run on wireline or on pipe. Wireline operations have the advantage of speed and economy. Pipe operations has the great advantage of utilising the circulation holes in the magnet to remove settling above the fish.
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13.6.
PAGE
0
MILLING PROCEDURE There is a wide variety of mills specifically designed for various applications. Mills are available in two basic categories: ‘hydraulically activated mills’ and ‘fixed milling tools’. A Section Mill is a hydraulically actuated tool and is used to mill out a complete section of casing. Downhole section milling of casing, is generally done for the following reasons: • •
To mill a section of casing that permits side-tracking in any direction. To mill the perforated zone in a production casing string or to expose cased off formations. The formations may be then underreamed and gravel packed past the original completion.
The most commonly used Fixed Mills are: Junk Mills
Used to mill all type of junk, including rock bit cones, reamers cutters, items dropped through the rotary, drill pipe cemented inside and outside, etc.
Pilot Mills
Designed to mill drill pipe, casing, tubing, wash pipe, safety joint, swaged casing, etc.
Taper Mills
Generally used to eliminate restrictions or to mill through collapsed casing.
Washover Shoes
Designed to mill away formation or tool obstructions such as stabiliser blades, reamer cutters, expanded packers and bit bodies which may be holding the drill or tubing string in the hole
Special Mills (Window mills, Watermelon mills, etc.)
For casing side-tracking systems.
The following are general guidelines for the use of milling tools: a)
Milled cuttings are much heavier than drilling cuttings. Therefore, mud viscosity should be increased or high viscosity pills should be pumped to help in carrying the steel cuttings out of the hole.
b)
Oil based mud has poor carrying capabilities and should be avoided whenever possible. Polymer muds are most suitable for milling.
c)
Never mill faster than it is possible to remove the cuttings.
d)
Magnets placed in the flow line will help in removing metal particles from drilling mud. Removal of mill cuttings and debris reduces the wear on mud pumps and other equipment.
e)
A junk sub placed in the string above the mill can aid in catching the larger cuttings.
f)
Whenever possible, a stabiliser should be run within 60 or 90ft (20-30m) above the mill to prevent it from moving eccentrically.
g)
The stabiliser OD should not exceed the dressed OD of the mill.
h)
Always start rotating, with low rpm about 3ft (1m) above the fish. Lower onto the fish and adjust the weight and the rotary speed to obtain satisfactory penetration.
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a)
Generally the most efficient milling rates are obtained by running the rotary at 80 to 100rpm. Milling with washover shoes is an exception and are usually more efficient at speeds of 60 to 80rpm. Continuously monitor the torque indicator during milling operations.
b)
‘Reading the cuttings’ is essential to evaluate the performance of the mill. The ideal cuttings are usually 1/32" to 1/16" thick and 1" to 2" long. If cuttings are thin long stringers, penetration rates are probably too low and weight on the mill should be increased. If fish-scale type cuttings are being returned, penetration rate will improve by decreasing weight and increasing rpm.
c)
The type and stability of the fish (cemented or not) together with the hardness of the fish and/or cement are factors that affect milling rates.
JARRING PROCEDURE a)
Jarring should be done with a Kelly or Top Drive. If the use of a Kelly is not possible, secure the elevator latch by using a piece of rope or chain.
b)
Prior to jarring check the drill line sensor. Ensure the weight indicator readings are accurate and that the dead line anchor is secure and free of debris. Check the derrick and all equipment for any loose items.
c)
When jarring, the drill floor must be cleared of all non -essential personnel.
d)
Prior to jarring, mark the drill string at the rotary table.
e)
Check the drill line usage, slip and cut if necessary. When sustained jarring is carried out, the drill line should be slipped at regular intervals, depending on the particular situation. Also check the derrick, lifting equipment and travelling block attachment bolts.
f)
Always allow the jars to trip within their safe working load. Wait until the jars have tripped before pulling the string further. Never exceed the safe working limit without confirmation that the jars have tripped.
g)
If a top drive system is used, after jarring, check the TDS as per the maintenance and operating specification.
Note:
For details on jarring procedures, refer to ‘Drilling Jar Acceptance And Utilisation Procedures’.
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Depth From Surface in feet Pipe OD ins 23/8 7
2 /8 1
Tubing
3 /2 1
4 to 4 /2 3
7
2 /8 to /8 1
3 /2 to 4 Drillpipe
1
9
4 /2 to 6 /16 5
6 /8 1
3 /2 to 4 1
1
4 /8 to 5 /5 Drill Collar
3
5 /4 to 7 1
1
1
3
1
1
7 /4 to 8 /2
0 to 3,000
3,000 to 6,000
6,000 to 9,000
9,000 to 12,000
Over 12,000
1
1
1
2
2
1
1
2
2
3
1
1
2
2
2
2
2
2
3
3
1
2
2-3
3-4
4-6
2
3
3-4
4-6
5-8
2
3-4
4-6
5-9
6-12
3
4-5
5-7
6-10
7-14
2-4
2-5
3-7
3-8
4-9
2-4
3-6
4-8
4-10
5-12
3-6
4-8
5-10
6-12
7-15
4-6
5-9
6-12
7-15
8-18
6-12
8-12
8-15
8-18
7 /4 to 9 /4
Casing
4 /2 to 5 /2
3
3
3
3
3
6 to 7
3
3
3
4
4
5
7 /8
4
4
4
4
5
5
7 /8
5
5
5
5
5
5
9 /8
5
5
5
6
6
3
6
6
6
7
7
10 /4
Table 13.A - Recommended Strands of 80 Gr/ft RDX Primacord for String-Shot
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14.
WELL ABANDONMENT
14.1.
TEMPORARY ABANDONMENT
0
14.1.1. During Drilling Operations Any well drilled which is to be temporarily abandoned shall be cemented with drilling/kill weight mud below. Where there is an open hole below the deepest string of casing a cement plug shall be placed in such manner that extends at least 50m above and below the casing shoe. The top of the cement plug shall be located and verified by mechanical loading. If the condition of the formation makes cementing difficult, a bridge plug may be positioned in the lower part of the casing, but not more than 50m above the shoe and a cement plug at least 20m long shall be placed on top of the mechanical plug. Then, a cement plug shall be set at least 50 - 100m in length into the casing, depending on casing diameter, between 20 - 50m below ground level or the seabed. The top of the cement plug shall be located and verified by mechanical loading. 14.1.2. During Production Operations 1)
Plugging programme before a production well test: Open Hole In the part of borehole where casing has not been installed and where permeable zones containing liquid or gas have been found, cement plugs shall be placed in such a way as to prevent liquid or gas from cross flowing into other zones. For each individual zone the cement plug shall be positioned such that its upper and lower ends are located at least 50m above and below the zone respectively. The top of each cement plug shall be located and verified by mechanical loading. Deepest Casing Shoe Where there is an open hole below the deepest string of casing, a cement plug shall be placed in such a manner that it extends at least 50m above and below the casing shoe. The top of the cement plug shall be located and verified by mechanical loading. If the condition of the formation makes cementing difficult, a mechanical plug may be positioned in the lower part of the casing, but not more than 50m above the shoe and a cement plug at least 20m long shall be placed on top of the mechanical plug. These plugs shall be verified by mechanical loading or pressure tested for sufficient time and with enough differential pressure to detect a possible leak.
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2)
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Plugging programme after a production test: Uninteresting perforated zones These intervals shall be isolated by means of a mechanical plug and shall be squeeze cemented. If the condition of the formation makes cementing difficult a cement plug 50m high will be set on top of the mechanical plug. If this is not possible, a cement plug shall be placed in such a way that the upper and lower ends of the plug are located at least 50m above and below the perforated zone respectively, or down to the nearest plug if the distance is less than 50m. All the plugs shall be described, as seen in the previous subsection. Interesting perforated zones These intervals shall be isolated by means of a mechanical plug. Then, a cement plug shall be set at least 50 - 100m in length into the casing, depending on casing diameter, between 5 - 50m below the sea bottom. The top of the cement plug shall be located and verified by mechanical loading.
14.2.
PERMANENT ABANDONMENT
14.2.1. Plugging A well has to be plugged so as to effectively seal-off all potential hydrocarbon bearing zones from fresh water bearing formations and to protect any zones which may contain other minerals. 14.2.2. Plugging Programme Open Hole All permeable zones in an open hole shall be plugged so that formation fluid is prevented from flowing from one zone to another. Plug(s) shall be set so that the top and the bottom is at least 50m above and below the zone(s). Each plug has to be tested. Deepest Casing Shoe At the top of the open hole a cement plug shall be set so that the upper and lower ends of the plug are located at least 50m above and below the casing shoe. The plug shall be tested by mechanical loading. Perforated Casing Zones Each zone tested through casing perforations shall be squeeze-cemented as soon as the test is finished, should the well be abandoned. A cement retainer will be set 10-15m above the perforated zone (avoid setting it on a casing collar) and an injection test shall be performed using fresh water and recording the pressure/flow rate ratios.
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The cement slurry volume will be calculated in order to have the cement from bottom perforation to the cement retainer and a minimum of 100ltrs slurry per metre of perforated zone into the formation. At the end of the squeeze, a 50m cement plug shall be set above the cement retainer. The length of this plug may be reduced to avoid any interference with upper intervals to be tested or produced. Liner Top At the hanging point of the liner, a cement plug shall be set so that the top and bottom of the plug is at least 50m above and below the hanging point. Intermediate Casing Shoe In case any of the intermediate casings is not cemented up to at least 100m inside the previous casing shoe, the casing shall be cut at least 100m above the shoe of the previous casing string, the casing recovered, and a cement plug shall be placed so that it extends at least 50 - 100m above and below the casing cut point. Surface plug A surface plug (at least 150m long) shall be set so that the top of the plug be 50m or less below ground level or seabed. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below sea bed, using mechanical cutters. 14.2.3. Plugging Procedure 1)
2)
Cement plugs, set when abandoning wells, should be formed from neat slurries whenever possible. If static bottom hole temperature exceeds 110째C use special non degradable cements (i.e. Geotherm). Spacers should be pumped ahead and behind slurry. Special consideration should be given to the composition and volume of the spacers when the mud is oil based, calcium chloride or lignosulphonate treated. The hydrostatic head reduction due to the spacer volume and density should be calculated. The spacers should have a volume corresponding to a length of at least 328ft (100m).
3)
4) 5) 6) 7)
The slurry volume should be calculated using a calliper log, if available. When a calliper log is not available, use a slurry volume excess based on local experience. Plugs exceeding 200m in length should not be set in one stage. If the hole is badly washed out or when potential losses are expected; it is preferable to set two short plugs instead of one long one. All cement plugs shall be placed using a tubing stinger. Displacement should be calculated in order to spot a balanced cement plug (hydrostatic heads inside the string and outside in the annulus shall be the same). An under displacement of 1 or 2bbl is suggested to help draining the slurry off the pipe when pulling out of hole.
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9) 10) 11)
12)
14.3.
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As soon as the plug is set, pull out slowly 30 - 50m above the theoretical top of the plug and direct circulate (reverse circulation can also be considered if conditions allow it). Monitor and record spacer and slurry returns. Never stab the stinger back into the plug to avoid plugging of the stinger. The position and efficiency of all cement plugs shall be verified by locating the top of the plug and by applying bit weight on the plug after cement setting, usually 20,00040,000lbs, but dependent on hole size) . Record shall be kept of all plugs set and the results of tests shall be available for inspection.
CASING CUTTING/RETRIEVING Consideration can be given, if deemed economically profitable, to cut and retrieve sections of uncemented 7" and 95/8" casing. Mechanical cutters are used for this operation. After cutting the casing, a complete circulation shall be made to reduce friction and balance the mud. If the casing is cut and recovered leaving a stub, one of the following methods shall be used to plug the casing stub:
14.3.1. Stub Termination (Inside a Casing String) A stub inside a casing string shall be plugged by: â&#x20AC;˘ â&#x20AC;˘
A cement plug is set so as to extend 50m above and 50m below the stub, A permanent bridge plug set 10-15m above the stub and capped with at least 20m of cement.
14.3.2. Stub Termination (Below a Casing String) If the stub is below the next larger string, plugging shall be accomplished in accordance with the previous section. The plug shall be mechanically tested. After setting a surface plug, each surface casing and conductor pipe shall be cut at least 5m below sea bed using mechanical cutters.
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15.
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WELL NAME/DESIGNATION The original name will be set by the geology or exploration department. There are three categories of well which need to be coded.: 1) 2) 3)
15.1.
Wells With The Same Well Head And The Same Target Wells With The Same Well Head Different Targets Wells With Different Well Heads And The Same Target
WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND TARGET
15.1.1. Vertical Well Is defined as having the same well head and target co-ordinates as defined in the well programme. The well code will be: Prospect/Field name: Amelia Well Number: 1 Therefore the name/number is: Illustration Line 1)
Amelia 1 1
15.1.2. Side Track In A Vertical Well. The term Side Track will only be used when there is a mechanical Side Track due to operational problems. If a new hole is drilled due to a operational problem maintaining the same target co-ordinates, this does not alter the well name. To permit the identification of the various side-tracks each is given a number. 1 is the original hole, 2 is the first side-track, 3 the second, etc. This is shown in the figure and in the following example: Illustration Line 1)
Field name: Amelia 1
Illustration Line 2)
1st Side Track: Amelia 1 (hole No. 2)
Illustration Line 3)
2nd Side Track: Amelia 1 (hole No. 3)
1 2 3
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15.1.3. Directional Well Is defined directional as a well where the target co-ordinates are different from the well head co-ordinates. (see Figure). The well code will be Field name: Amelia Well number : 1 Code: DIR So the final well code will be: Illustration Line 1) Amelia 1 DIR 1
15.1.4. Side Track In Directional Well This is considered the same condition as for a vertical well: Illustration Line 1) Original Well name/number: Amelia 1 DIR Line 2) Side Track: Amelia 1 DIR (hole n. 2)
1
15.1.5. Horizontal Well
2
Is defined as a well that has a final hole path with a inclination of 90째. The name will be: Field name: Amelia Well number: 1 Extension: OR
1
Therefore the final well code will be: Illustration Line 1) Amelia 1 OR Note:
The pilot hole into the reservoir will also be deemed part of the horizontal well.
15.1.6. Side Track In A Horizontal Well This is considered the same condition as for a vertical well: Original well name/number Amelia 1 OR Illustration Line 2) Side Track: Amelia 1 OR (hole n.2) 1 2
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WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND DIFFERENT TARGETS In this category are wells with: The original well head co-ordinates with more than one hole and different target coordinates. Each new hole will be given a new code as will the operations necessary to prepare for the side-track (cement plug, casing window operation, etc.). The name of the first hole will have the original code (AMELIA 1), the following holes will be added to the original code with one of the following two additions: The first one indicates the well type: • • •
DIR, directional well OR, horizontal well APPR, deepened well
The second one indicates the targets new co-ordinates: • •
A, second target B, third target
Example #1 Illustration Line 1) Original well (vertical) Amelia 1 Illustration Line 2) Directional hole: Amelia 1 DIR (A) Illustration Line 3) Horizontal hole: Amelia 1 OR (B) 3 2 1 Example #2 Illustration Line 1) Original Directional Well: Amelia DIR Illustration Line 2) Directional Well with the second target: Amelia 1 DIR (A) 1 2
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Example #3 Illustration Line 1) Original Directional Well: Amelia 1 DIR Illustration Line 2) Vertical well with a second target: Amelia 1 (A) 1
2 Example #4 Illustration Line 1) Original Vertical Well: Amelia 1 Illustration Line 2) Horizontal hole with a second target: Amelia 1 OR (A)
3
Illustration Line 3) Horizontal hole with a third target: 2
Amelia 1 OR (B) 1
Example #5 Illustration Line 1) Original Directional Well: Amelia 1 DIR Illustration Line 2) Directional hole with a second new target: Amelia 1 DIR (A) Illustration Line 3) Horizontal well with a third target: 1
Amelia 1 OR (B)
3 2
Example #6 Illustration Line 1) Original Vertical Well: Amelia 1 Illustration Line 2) Directional hole with a second target:
1
Amelia 1 DIR (A) Illustration Line 3) Deepened well with a third target:
2
Amelia 1 APPR (B) Illustration Line 4) Deepened well with a fourth new target: Amelia 1 DIR APPR (C)
3 4
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0
WELLS WITH DIFFERENT WELL HEAD CO-ORDINATES AND SAME ORIGINAL TARGETS In this category are the wells where the target co-ordinates remain the same while the wellhead location has been moved. This condition can only occur where there has been a drilling problem in the well. There are two different cases: Case 1 When there is one or more strings of casing set, it can be considered that every hole is a single well, so the name of the wells after the first will be the original well plus the code to define the well type (DIR OR) with the added code BIS for the second well, TRIS for the third well, etc. Example #1 Illustration Line 1) Original vertical well: Amelia 1 Illustration Line 2) Second well: Amelia 1 BIS Illustration Line 3) Third well: Amelia 1 TRIS 2 1 3
Case 2 (no casing set) When no casing string has been set, it can be considered that every hole is part of a single well. The code for the following holes is the original well plus (1) for the first hole, (2) for the second hole, etc. Example #2: Illustration Line 1) Original well: Amelia 1 Illustration Line 2) Second hole: Amelia 1 (2°) Illustration Line 3) Third hole: Amelia 1 (3°) Illustration Line 4) Fourth hole: Amelia 1 (4°) Illustration Line 5) Fifth hole: Amelia 1 (5°) Illustration Line 6) Sixth hole: Amelia 1 (6°)
3 1 2
4 5 6
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FURTHER CODING Further codes may be added to give additional information about a well with regard to its location in a field or if it is a marine well, i.e. Location
Code
Example
Field Description
Marine, Mare
M
Belaym 113 M 35
Belaym 113 Mare 35
North, Nord
N
Beniboye N 5-2
Beniboye North 5-2
South, Sud
S
Imbondeiro S 1
Imbondeiro South 1
East, Est
E
Samabri E 1
Samabri East 1
West, Ovest
W
Belaym M N W 2
Belaym Mare North West 2
When the well code/name is written out in full the full code name must be placed in front of the field name. Example : a)
North Darag 1
b)
Est Makerouga 2
c)
South pass 75-2
d)
West Butte 9-34-13-20
Listed in the following table 15.a are the definitions and the parameters to identify other well characteristics.
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DEFINITION
0
PARAMETER Inclination da
ROC (m) 5.8÷ 30.1
SHORT RADIUS
x°
a 90°
INTERMEDIATE RADIUS
x°
90°
43.1 ÷ 12.79
MINIMUM RADIUS
x°
90°
86.8 ÷ 220.4
LONG RADIUS
x°
90°
286 ÷ 573
DEFINITION Curve Characteristic
BUR (°/m) (°/30 m) 9.8 ÷ 1.9 294 ÷ 57 1.33 ÷ 4.48 40 ÷ 70 0.66 ÷ 0.26 20 ÷ 8 0.2 ÷ 0.1 3÷6
Horizontal Section (m) 150 ÷ 250 150 ÷ 250 500 ÷ 900 1000 ÷1600
PARAMETER Displacement ROC (m) (m)
BUR (°/m) (°/30 m)
DRAIN HOLE
Short Radius
150 ÷ 250
5.8 ÷ 30.1
9.8 ÷ 1.9 294 ÷ 57
EXTENDED REACH WELL
Long Radius
1000÷1600
286 ÷ 573
0.2 ÷ 0.1 3÷6
LATERAL WELL
All the Horizontal wells
MULTI LATERAL WELL
As showed in chapter 2 example 5
RE-ENTRY WELL
Well re-entered to put in production, by drilling operations, a old suspended well. See example in chapter 2
BRANCH WELL
Più drain hole con partenza da un unico extended reach
DEFINITION
PARAMETER Depth (m)
Pore Pressure bar/10m
SIWH Pressure (bar)
Temp Res. O/WH (°C)
Water Depth (m)
DEEP WELL
> 4600
---
---
---
---
ULTRA DEEP WELL
> 6000
---
---
---
---
DEEPWATER WELL
---
---
---
---
460
HIGH PRESSURE WELL
---
> 1.81
> 690
---
---
HIGH TEMPERATURE WELL
---
---
---
> 150°c
---
Title
Description
WATER WELL
Producing water well
WATER INJECTION WELL
Well for water injection
GAS INJECTION WELL
Well for gas injection
Table 15.A - Well Definitions and Characteristics
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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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0
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 5â&#x20AC;? DPâ&#x20AC;&#x2122;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 â&#x20AC;&#x2DC;Drilling Programmeâ&#x20AC;&#x2122; 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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17.
PAGE
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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0
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
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0
Bit Record (ARPO 05)
BIT RECORD
District/Affiliate Company DATE:
WELL NAME FIELD NAME ARPO-05
Cost center
Run n째
Bit n째 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
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Waste Disposal Management Report (ARPO 06)
WASTE DISPOSAL
WELL NAME
Management Report
FIELD NAME
District/Affiliate Company DATE:
ARPO-06 Cost center
Report N째
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 N째
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
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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
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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
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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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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