Manual
Practical Well Planning
Steve Devereux
[ ]
Manual
Practical Well Planning
Copyright © 1998 by PennWell Corporation 1421 South Sheridan Road Tulsa, Oklahoma 74112-6600 USA 800.752.9764
+1.918.831.9421 sales@pennwell.com www.pennwellbooks.com www.pennwell.com
Marketing Manager: Julie Simmons
National Account Executive: Barbara McGee Director: Mary McGee
Managing Editor: Marla Patterson
Operations/Production Manager: Traci Huntsman
Library of Congress Cataloging-in-Publication Data Available on Request Devereux, Steve
Practical Well Planning and Drilling Manual ISBN 0-87814-696-2
ISBN13 978-0-87814-696-3
All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording,
without the prior written permission of the publisher. Printed in the United States of America
Preface
xi
Acknowledgments
xiii
Introduction
xv
List of Acronyms
xix
Section 1: Well Design
1
1.1. Preliminary Work for the Well Design 3
1.1.1. Planning Process Overview 3
1.1.2. Data Acquisition and Analysis 4
1.2. Well Design: General 17
1.3. Precompletion and Completion Design 21 1.3.1. How the Completion Relates to the Well Design 22
1.3.2. Monobore Completions 25
1.3.3. Multiple String Completions 28
1.3.4. Completion Fluids 29
1.3.5. Brines 30
1.3.6. Points to Check on the Completion Design 34
1.4. Casing Design 37
1.4.1. General Points and Definitions 38 1.4.2. Hole and Casing Sizes: Considerations 41 1.4.3. Hole and Casing Sizes: Selection 42 1.4.4. Pore Pressures and Fracture Gradients 43 1.4.5. Casing Shoe Depth Determination: 51
General Points
1.4.6. Individual Casing Points 54
1.4.7. Mechanical Properties of Steel 57
1.4.8. Safety Factors 60
1.4.9. Factors Affecting Pipe Yield Strengths 63 1.4.10. Methods of Applying Buoyancy Effects 65 1.4.11. Casing Design Criteria: Definitions and 71
Methods of Calculation
1.4.12. Calculating Burst and Collapse Loads, 71 Including Biaxial Effects
1.4.13. Calculating Axial Loads 73
Contents
[ ]
1.4.14. Calculating for Buckling (Nb) 81
1.4.15. Calculating Torsional Loads 84
1.4.16. Triaxial Stress Analysis 85
1.4.17. Design for Casing off Massive Salt Formations 86 1.4.18. Casing Properties and Other Considerations 87
1.4.19. Material Grades 87
1.4.20. Casing Connections 90
1.4.21. Casing and Liner Accessories 91
1.4.22. Wellheads: General Descriptions 96
1.4.23. Casing Design Criteria 98
1.4.24. References for Casing Design 98
1.5. Directional Design 107
1.5.1. Planning the Wellpath 108
1.5.2. Dogleg Severity Limits—Combined 110 Buildup and Turn Rate
1.5.3. BHA Performance Considerations 115 1.5.4. Horizontal Well Design Considerations 116
1.5.5. Multilateral Wellbores 118
1.5.6. Slant Rig Drilling 118
1.5.7. Targets and Wellpath 119
SECTION 2: WELL PROGRAMMING
121
2.1. Preliminary Work for the Drilling Program 123
2.1.1. Drilling Program Checklist 123
2.1.2. Technical Justification 130
2.1.3. Formatting the Drilling Program 132
2.1.4. Time Estimates 133
2.1.5. Cost Estimates 133
2.2. Well Control 145
2.2.1. Shallow Gas 145
2.2.2. Drilling with a BOP Stack 151
2.2.3. High Pressure, High Temperature Wells (HPHT) 153 2.2.4. Well Control in High-Angle and 155
Horizontal Wells
2.2.5. References for Well Control—Shallow Gas 156
2.3. Directional Planning 157
2.3.1. Downhole Tools Affecting Directional Control 157 2.3.2. Directional Measurement and Surveying 163
2.3.3. Kicking Off the Well 173
2.3.4. Drilling the Tangent Section 177
2.4.2. Evaluating Offset Well Drilling Data 183
2.4.3. Drilling Hydraulics 187
2.4.4. Using Log Data to Aid in Bit Selection 190
2.4.5 Types of Drillbits 192
2.4.6. Defining Recommended Bits 194
2.4.7. BHA Considerations Related to Bits 200 2.4.8. Drilling Program: Bit Selection and 201
Drilling Parameters
2.4.9. References for Drillbit Selection 201
2.5. Drilling Fluids Program 203
2.5.1. Reaction of Clays to Water: General Principles 204 2.5.2. Dispersion and Flocculation of Clays in Water 205
2.5.3. Mud Types Available 206
2.5.4. Dispersed Water-Based Muds 206
2.5.5. Nondispersed or Polymer Water-Based Muds 210 2.5.6. Formation Damage with Water-Based Muds 226
(and Cements)
2.5.7. Oil Muds 232
2.5.8. Components of Invert Oil Emulsion Muds 233 2.5.9. Environmental aspects of Oil Muds 240
2.5.10. Oil Mud Additives 240
2.5.11. Formation Damage with Oil Muds 244 2.5.12. Air, Foamed, and Aerated Systems 246
2.5.13. Tendering for Mud Services 248
2.5.14. References for Drilling Fluids Program 251
2.6 Casing Running Program 253
2.6.1. Normal Drilling Program Requirements 253 for Running Casing
2.6.2. Addressing Potential Casing Problems in 254 the Drilling Program
2.7. Cementing Program 257
2.7.1. Slurry Properties 258
2.7.2. Chemical Washes and Spacers 263
2.7.3. Factors for Ensuring a Good Cement Job 264 2.7.4. Cementing Design for Casings and Liners 267 2.7.5. Cementing Design for Cement Plugs 274
and Squeezes
2.7.6. Special Purpose Cementing 278
2.8. Formation Evaluation 281 2.8.1. Electric Logging and Sampling 281
2.8.2. Coring 284
2.8.3. Mud Logging 290
2.9. Drilling Problems—Avoidance Planning 293
2.9.1. Wellbore Stability 293
2.9.2. Stuck Pipe 302
2.9.3. Lost Circulation 307
SECTION 3: PRACTICAL WELLSITE OPERATIONS
311
3.1. Well Control 313
3.1.1. Kick Prevention 313
3.1.2. Kick Detection and Response 315
3.1.3. Drilling Below Normal Kick Tolerance Levels 319 3.1.4. Well Killing in a High-Angle Well 320 3.1.5. General Considerations for BOP Equipment 323 3.1.6. Surface BOP Stack Configurations 328 3.1.7. Surface Stack Control System Specifications 327 3.1.8. Surface BOP Stack and Accumulator Testing 328 3.1.9. Well Control: Other Equipment Requirement 333 3.1.10. Suggested Rig Takeover Checklist 334 3.1.11. Minimum Mud Chemical Stock Levels 334
Held on Rig 3.2. Drilling Fluid 337 3.2.1. Solids Control 337 3.2.2. Quality Control 345 3.3. Drilling Problems 347 3.3.1. Stuck Pipe 347 3.3.2. Lost Circulation 359
3.3.3. Washout Detection Procedure 364
3.3.4. Backing Off 365
3.3.5. Fishing Operations 368
3.3.6. Using Cement to Stabilize the Wellbore 373 3.3.7. Making Connections to Minimize Wellbore 374
Instability and Losses
3.3.8. Preplanned Wipertripping 375
3.3.9. Baryte Plugs 376
3.3.10. Diesel Oil Bentonite Plugs (“Gunk Plug”) 379
3.4.2. Equipment Preparation for Casing 385
3.4.3. Job Preparation for Casing 386
3.4.4. Casing Running Procedures 388
3.5. Cementing 397
3.5.1. Mud Conditioning for Maximum Displacement 398
3.5.2. Slurry Mixing Options 398
3.5.3. Preparation for Cementing 399
3.5.4. Cement Displacement 400
3.5.5. Post-Job Evaluation 402
3.5.6. Field Cementing Quality Control Procedures 403
3.6. Drillbits 407
3.6.1. Alternative Bit Choices 407
3.6.2. Drilling Parameters 409
3.6.3. Mud Motors, Steerable Systems, and Turbines 413 3.6.4. Monitoring Bit Progress while Drilling 413
3.6.5. When to Pull the Bit 414
3.6.6. Post-Drilling Bit Analysis 415
3.7. Directional Drilling 421
3.7.1. Rotary Bottom Hole Assemblies— 421 General Points
3.7.2. Preventing Keyseating 423
3.7.3. Directional Jetting—Practical Considerations 424 3.7.4. Single Shot Surveys—General Points 425 3.7.5. Magnetic Single Shot Survey Tool 426 3.7.6. Totco Single Shot Survey Tool 428
3.7.7. Gyro Multishot Surveys 428
3.8. Writing the Final Well Report 429
3.8.1. Suggested Final Well Report Structure 430 Appendix 1: Calculating Kick Tolerances 435 Appendix 2: Formation Integrity Test Recommended Procedure 441
Appendix 3: Information Sources 445
Appendix 4: Drilling Equipment Lists by Operation 447 Appendix 5: Conductor Setting Depth for Taking Returns to 457
the Flowline
Glossary 459
There are many excellent books dealing with drilling engineering, well planning, and drilling practices. Readers will note that the approach I adopt here differs from the “standard” books in three sig-nificant respects:
1. I have separated the office aspects from the rig aspects. Thus, the drilling engineer who needs to design the well and write the drilling program will find the relevant information together in the first two major sections. The wellsite drilling engineer/supervi-sor/toolpusher will refer more to the third major section, which deals with the practical rig site aspects of drilling the well. I hope this makes it easier for the reader to focus on his or her current area of interest. For instance, casing design information is in Section 1, notes on writing the casing part of the drilling program are in Section 2, and notes on running casing are in Section 3. For the wellsite drilling engineer, toolpusher, or drilling supervisor, much of the information given in Section 2 (Well Programming) is also relevant to the practical aspects of the work. I have tried to include extensive indexing and cross-referencing to help find all the rele-vant pages.
2. I have not included reference information that should be readily available in the office or on the rig. You will not find reproductions of casing design data, drillstring strength tables, cement formula-tions, etc. Space is limited in any paper-based media, and I would rather use that limited space for information that may not be so readily available to you.
Preface
[ ]
3. I have not gone far into the deep theoretical aspects behind the work. While it is valuable to intimately understand the theoretical background, it is not strictly necessary for practical application during your everyday work. I have included references where applicable. Also, a few of the topics are covered to give some back-ground and to show how they impact the well design and drilling program, but are not in themselves meant to be an authoritative text on the subject. For instance, completions are not usually designed by drilling engineers, but the completion requirements impact the whole well design because the completion dictates the hole sizes. Therefore, the design needs to be understood, questions need to be asked, and parts of it should be checked. Cementing is a huge topic and a nonspecialist book like this cannot cover it com-prehensively; reference can be made to one of the excellent spe-cialist books on cementing (recommended in the relevant section).
During my drilling career, I was lucky to have the guidance of many good drilling people, and the examples of many good (and a few not-so-good) people to learn from. Shell gave me my start as a trainee driller, and the time I spent with them was invaluable. I was taught how to do things properly and safely under the “old” training scheme whereby you earned your spurs on the drillfloor. My experience as a driller has been important throughout my career, even as a drilling manager. It is a great pity, and I believe detrimental for our industry, that few companies train people all the way through the ranks any more.
Stuart Smith, drilling fluids consultant, taught me a great deal when we worked together in Egypt. He contributed a lot of material for this book and continues to contribute to my CD Drilling Manual, enhancing the value of both.
Mark Hillman, drilling fluids consultant, contributed material on brines. Mark worked on developing potassium formate brines. He has also contributed to my CD Drilling Manual.
Dr. Eric van Oort of Shell and Dr. Fersheed Mody of Baroid taught me much about wellbore stability and mud design during interesting discussions and E-mail sessions. Some of the lessons I learned from these are included in this book. Fersheed has also contributed to my
CD Drilling Manual.
Baroid Drilling Fluids, Milpark, and Tetra Technologies (UK) Ltd. allowed me to use their technical literature on muds and brines, including copying illustrations. I’d specifically like to thank Ray Grant of Baroid, Martin Ellins of Baker Hughes Inteq (Milpark), and Ian (Chalky) White of Tetra for their help.
Acknowledgments
[ ]
Among my mentors I count and thank Ken Fraser. Ken was a Shell toolpusher on one of my first rigs as a trainee in Holland, and I later worked for him in Brunei as a driller. I learned a lot from him.
Another good friend and teacher is Frank Verlinden, who spent more years in Brunei than any other Shell employee. Frank talked of things forgotten in today’s industry and knew from many years of expe-rience how to handle any situation you could throw at him. Given a glass of wine and a small prompt, he could recount endless stories, which were fascinating as well as educational.
I hope my other friends and colleagues, too numerous to thank individually, will forgive me for not compiling a huge list here.
The drilling industry is changing rapidly in the areas of technolo-gy, safety, environment, management, contractual relationships, train-ing, etc. The driving forces are largely economic; there are probably few giant fields left undiscovered (especially in mature areas) and therefore the search moves to frontier areas and to exploiting smaller fields. Increased government regulations also play a large part. All of these factors increase the cost to discover and produce hydrocarbons. Add to this the pressure of low oil prices, and we are expected to continually reduce costs while improving drilling and production performance. We have to become more efficient by improving our skills and by develop-ing new technologies and ways of workdevelop-ing.
Computers have also caused dramatic changes for us. The comput-ing power now available means that, if properly used, computers can help us to make better decisions. We can store, access, analyze, and summarize huge volumes of data and make complex calculations easy, even for the nonmathematically inclined. The downside is that some engineers use their PCs as a senior partner to make decisions for them rather than as a tool to help them make better-informed decisions them-selves. This trend is increasing for reasons that I will come to shortly.
Early in the 1990s, operators and drilling contractors slowed down or stopped their ongoing training programs. This was largely due to low oil prices and high drilling costs. With less activity, many skilled people left the industry. The accountants decided that funds spent on training should be assigned elsewhere (perhaps on recruiting more accountants?) and so the major sources of highly trained, well-round-ed drilling people driwell-round-ed up. To continue operating, new contracting schemes transferred responsibility from the operators to the contrac-tors. This led to an exodus of people from the operators to the con-tractors and into the consulting market, depleting those skills within
Introduction
[ ]
the operators much faster than by natural attrition and without replac-ing them, except by employreplac-ing consultants. Some operators may end up with no one to properly supervise the core business of drilling. This will expose them to risks associated with major incidents such as blowouts without being able to manage that risk. Even on a turnkey well, the operator still has risks.
Alliancing contracts are becoming common, where a lead contrac-tor is employed to subcontract and manage all the services needed to drill a well, but the operator still stays closely involved. Effectively, the lead contractor provides most of the resources of a drilling department, plus areas of specialist expertise.
There are some positive benefits from these strategies. If a true team spirit emerges where people work cooperatively together for achieving the same goals, costs can possibly be cut on long-term (development) projects. However, one guiding principle should be that
the operator retains the technical ability to plan and supervise the wells.
This means keeping competent drilling people in place.
There are at least three necessary factors for an alliance: commit-ment, communication, and competence. These take time to get in place. An alliance will not swing smoothly into action from the start therefore management also needs the commitment to see it through the initial hiccups.
Another clear trend is that many people planning and supervising wells do not have significant wellsite exposure. You can take the smartest person there is, put them through a degree program, and send them to all possible classroom courses. However, without the practi-cal knowledge—the feel for drilling that comes from years on the rig— they are unlikely to become first class drilling people. They will tend to “use their PCs as a senior partner to make decisions for them rather than as a tool to help them make better-informed decisions them-selves,” and they will be unduly influenced by the people around them. The attention paid to safety, the environment, and quality control has advanced immeasurably. Running an operation that is safe mini-mizes environmental impact and concentrates on all aspects of quality, which is ultimately more cost effective. Even now this is still sometimes a “hard sell”; many people pay lip service to these things but are not committed to them. I remember years ago, working offshore Brunei as a driller, being told to wait until after dark and then dump a reserve tank containing about 50 bbls of oil-based mud into the sea. The line to the pump was plugged, and we had to clean it out. We ran a hose in and used a small pump over several hours to recover this mud back into the
tions, even though we had saved valuable mud and not polluted the South China Sea. This lip-service attitude still exists in some places.
There are two keys to drilling a cost-effective well and your
well-planning efforts should be directed at these two keys. The first key is
avoiding problems, which is chiefly related to the mud properties and to
good drilling practices (but not by being overly cautious!). Do the job properly, avoid unplanned short cuts that often lead to unnecessary problems, and pay that extra bit to get the most suitable mud system. The second key is maximizing progress, which is more related to opti-mum bit/BHA selection, optiopti-mum drilling parameters, good forward planning, and good drilling practices.
The success of a well is determined first by the effort devoted to producing the best possible well plan, and second by the competence of the supervision while drilling, bearing in mind the two keys. This book is about those things—effective well planning and managing/ supervising the drilling operation. I hope that this book will be a use-ful tool to drill safer, fit for purpose, cost-effective wells, and I look for-ward to your feedback on how well I have achieved this.
Steve Devereux, CEng, MIMinE, MIMgt http://www.drillers.com
[ ]
List of
Acronyms
A Area
Ac Constant of proportionality
ADEPT Adaptive Electromagnetic Propagation
AFE Authority for Expenditure
AIT Array Induction Imager Tool
AMS Auxiliary Measurements Service
AS Array Sonic
ASI Array Seismic Imager
ASP Anticipated Surface Pressure
assy Assembly
AV Annular Velocity
bar Unit of barometric pressure.
bbl(s) Barrel(s)
bent Bentonite
BHA Bottom hole assembly
BHF Braden head flange
BOP Blowout preventer
BP Bridge plug
bpm Barrels per minute
BSW Bottom sediment and water
BTC Buttress threaded and coupled
btm Bottom
Butt Buttress (threads)
Ca Calcium
CBT Cement Bond Tool
CBU Circulate bottoms up
CCM Circulate & condition mud
CDN Compensated Density Neutron Tool
CDR Compensated Dual Resistivity Tool
CEC Cation Exchange Capacity
CERT Correlated Electromagnetic Retrieval Tool
CET Cement Evaluation Tool
cent Centralizer
chk Choke
circ Circulate, circulation
Cl Chloride
CNL Compensated Neutron Log
co Change out
COOH Chain out of hole
cp Centipoise
cmt Cement
csg Casing
Dexp D exponent
dia Diameter
DC Drill collar
DHT Dry hole tree
DIL Dual Induction Resistivity Log
DLL Dual Laterolog tool
DLS Dog leg severity
DP Drill pipe
DPT Deep Propagation Tool
DSI Dipole Shear Sonic Imager tool
DST Drill stem test
dwks Drawworks
EU External upset
F or Fin Finish
FC Float collar
FCTA First crystal to appear
FG Fracture gradient
FL Flow line or fluid level
FMI Formation Micro Imager tool
FMS Formation MicroScanner tool
fph Feet per hour
FPIT Free Point Indicator Tool
fpm Feet per minute
fps Feet per second
FS Float shoe
FTP Flowing tubing pressure
GIH Go in hole
GLT Geochemical Logging Tool
GOR Gas/oil ratio
GPM Gallons per minute
GS Guide shoe
GST Gamma Ray Spectrometry Tool
Hgr Hanger
hd Head
HLDT Hostile Environment Litho Density Tool
HP Horsepower, high pressure
HHP Hydraulic horsepower
HW Heavyweight
IBOP Inside blowout preventer
ID Inside diameter
IEU Internal-external upset
IOEM Invert oil emulsion mud
ISIP Initial shut-in pressure
IU Internal upset
JB Junk basket
jt Joint
KB Kelly bushing
KOP Kickoff point
LCM Lost circulation material
LCTD Last crystal to dissolve
LD Lay down
LDL Litho Density Log
Lig Lignosulphonate
LIH Left in hole
LP Low pressure
LTC Long thread and coupling
LWD Logging while drilling
MD Measured depth
MDT Modular Formation Dynamics Tester
ML Mudline
MSCT Mechanical Sidewall Coring Tool
mu Makeup
MUT Make up torque
mw Mud weight
ND Nipple down
NGS Natural Gamma Ray Spectrometry Log
NML Nuclear Magnetism Log
NPLT Nuclear Porosity Lithology Tool
NU Nipple up
NV Nozzle velocity
OBDT Oil Base Dipmeter Tool
OBM Oil based mud
OD Outside diameter
OS Overshot
P&A Plug and abandon
PAC Poly anionic cellulose
PBR Polished bore receptacle
PBTD Plug back total depth
PHPA Partially hydrolysed polyacrylamide
PI-SFL Phasor Induction - Spherically Focused Log
pkr Packer
PM Alkalinity of mud
POB People on board
POOH Pull out of hole
ppg Pounds per gallon
PPM Parts per million
psi Pounds per square inch
psia Pounds per square inch (absolute)
psig Pounds per square inch (gauge)
PTD Proposed total depth
PU Pick up
PV Plastic viscosity
Rt True formation resistivity.
RAB Resistivity At the Bit
RFT Repeat Formation Tester
RIH Run in hole
RKB Rotary kelly bushing
RM Ream
RST Reservoir Saturation Tool
RU/RD Rig up/rig down
SFJ Super flush joint
SHRDT Stratigraphic High Resolution Dipmeter Tool
SITP Shut-in tubing pressure
sk/sx Sack/sacks
SLM Steel line measurement
SO Slack off weight
sow Slip-on weld
SP Spontaneous potential
SPM Strokes per minute
sssv Subsurface safety valve
sscsv Subsurface control safety valve
St Stand
TA Temporarily abandoned
TCT True crystallization temperature
TD Total depth
TDT Thermal Decay Time log
TIH Trip in hole
TOF Top of fish
TP Toolpusher
TTBP Through tubing bridge plug
TVD True vertical depth
USI Ultrasonic Imager
VBR Variable bore rams
VSP Vertical seismic profile
vis Viscosity
w/o Without
wo Workover
WL Wireline, water loss
WOB Weight on bit
WOC Wait on cement
WOE Wait on equipment
WOO Wait on orders
WOW Wait on weather
wt Weight
YP Yield point
Section 1:
[ ]
Well Design
This section covers topics related to analyzing offset data and applying it with other relevant information to duce a well design and a drilling pro-gram. The major subjects that need to be covered for planning the well are described in some detail. References are made to other sources for users who may need higher levels of detail.
1.1.1. Planning Process Overview
Preliminary Work for the Well Design
1.1
[ ]
Analyze Data
■ Prepare hole section
summaries
■ Question/follow-up
Design the Well
Final status of the well, including:
■ Hardware, casing, wellhead,
Xmas tree, sand control, completion design
■ Directional requirements
■ Document the major
decisions made Well Design Meeting
Assemble team:
■ Discuss all aspects of the
design
■ Agree on who does what
Acquire and Review Data
■ Well proposal
■ Offset data
■ Area experience
■ Area reference data
[ ]
1.1.2. Data Acquisition and Analysis
The success or failure of a well, from a drilling viewpoint, is heav-ily dependent on the quality of well planning prior to spud. The qual-ity of the well planning in turn is heavily dependent on the qualqual-ity and completeness of the data used in planning. The successful drilling engineer is a natural detective, snooping around for every snippet of useful data to analyze.
The starting point in your data analysis trail is the well proposal. Usually the need for drilling a well starts as a request from the explo-ration or production department. They will put together a package of information for drilling that will define what the well should achieve and where it should be.
Well proposal checklist. The proposal should contain the follow-ing elements as relevant to the particular well:
1. Well objectives (exploration, appraisal, development, or workover)
2. Envisaged timescale (earliest/latest spud date desired)
1.1.1 Well Design
Write the Drilling Program
■ Methods by which the well
design will be safely and efficiently implemented
■ Show the assumptions and
decisions made while writing the program (technical justification)
Circulate the Design for Comment Distribute for comment, including:
■ Requesting department
■ Drilling department
■ Other qualified reviewers
Pre-spud Meeting
■ Onshore briefing
■ Distribute the program
■ Offshore briefing
■ Distribute the program to
each person in supervisory position (drillers, geolo-gists, T/P, mud loggers, etc.) Circulate the Program for Comment
Distribute for comment, including:
■ Requesting department
■ Drilling department
■ Other qualified reviewers
■ Approval once finalized
3. Essential well design data:
■ Precompletion and completion requirements with conceptual
completion design
■ Preparation work required in advance of running the
comple-tion, including permanent packers, gravel packs, completion fluid specifications, etc.
■ Perforation intervals; perforation type (if known)
■ Completion or logging sump required below the bottom perf
depth (e.g., bottom perf to liner wiper plug and/or bottom of zone of interest to total depth)
■ Completion profile fully defining all elements of the
comple-tion hardware with depths; tubing, packers, subsurface safety valves (SSSVs), nipples, electric submersible pumps (ESPs), etc.
■ Completion pressure testing requirements
■ Future stimulation work envisaged, including fluids pumped,
pressures used during stimulations, possible gas lift, etc.
■ Temperatures and pressures anticipated during the production
life of the well
■ Likely reservoir fluid composition; any H2S or CO2possible? ■ Options envisaged for future well interventions, including
wireline/coiled tubing work, workovers, or recompletions (e.g., on another zone once primary zone is depleted)
■ Xmas tree and completion status on handover from drilling
(e.g., plugged and depressured, killed, valve configuration, etc.)
■ Type of abandonment envisaged at the end of the well’s
pro-duction life
■ Any other relevant information on the completion not covered
above
■ Pore pressure and fracture gradients vs. depth plot (it is useful
to ask for the PPFG plot to show “best” and “worst” cases)
■ Shallow gas information (e.g., from shallow seismic surveys
and offset wells)
■ Geological/seismic correlation, including all possible faults that
may be encountered
■ Lithology/petrophysical correlation
■ Well directional targets (show downhole constraints to justify
targets)
■ Surface location including site survey and bathymetry map, if
applicable
■ Required zonal isolation of reservoirs ■ Likely temperature profile with depth
[ ]
■ Any known restrictions on the mud systems to be used (e.g.,
for logging or reservoir damage)
■ Any other constraints on the well design or drilling program
from the well objectives
■ Any options that should be built into the well design, such as
later sidetracks to different reservoirs, etc.
■ A list of relevant offset wells
4. Specialist functions should specify:
■ Wireline logging program ■ Coring program
■ Geological surveying/mud logging requirements
■ Other evaluation requirements (e.g., paleontologist services, etc.) ■ Production test requirements
■ Final desired status of well; handover to production;
suspend-ed or pluggsuspend-ed and abandonsuspend-ed (P&A)
5. Approval signature of the head of the sponsoring department—this is to ensure accountability. It may also be necessary for the depart-ment head to give you an account code to write the time against. First, review the proposal and ensure that all necessary elements are present as per the above checklist. Then try to identify any surface or subsurface hazards arising out of the proposal and discuss these with the sponsoring department to see if their proposal can be modi-fied to eliminate or reduce the hazards. Review each element of the proposal in detail. Is there any clarification required? Look in particu-lar at the directional targets; these should be as particu-large as possible and ideally will indicate what defines the target boundaries (faults, prox-imity to other wells, etc.). If “hard” target boundaries are given then you know that if the well heads outside of that target, you may have to sidetrack to get back into the target. This also gives you the largest pos-sible target so you can later design your well to achieve the target at the lowest cost. This becomes more important if multiple targets or inter-mediate constraints on the wellpath are given. Often what happens is that the target is a circle of stated radius around a defined location and no indication is given as to where you can stray out of, which direction is most critical, etc.
Explorationists rarely appreciate the effect on well cost that an unnecessarily tight target can give. They know that if necessary you can drill very accurately to a target and therefore that is what they
ify. In reality, if you are given the maximum area to go for, you may aim not at the center but at a place that gives you the most leeway for direc-tional performance that does not go quite as planned.
For an offshore well (except for a platform), a seabed survey is required to check for bathymetry, seabed obstructions, seabed com-position, likely leg penetration (if applicable), and shallow gas indi-cations. Generally, this would cover a 2 km x 2 km square, centered on the proposed well location. Local currents should be checked (his-torical data may be available in mature areas) both at surface and at seabed level. Surface currents will affect rig positioning and marine operations; seabed currents may cause scour. Apart from the seabed survey, shallow seismic may be required to spot shallow gas anom-alies and estimate leg penetration. In an area of soft seabed, the drilling contractor may require a soil boring analysis to ensure that the rig can be jacked up with minimal risk of punching through a hard crust during preloading.
Sources of offset data. Now that the location and target depths/for-mations are known, you can look for relevant offset wells. Except for a rank wildcat well, quite a lot could be available from company sources. This includes final well reports (which, if written properly, will be your best source of information), daily drilling reports, etc. If people who worked on the well are still with the company, make a note of it so you can contact them later if queries arise.
Other data on offset wells may be available from sources outside the company. For instance, if the mud records are missing or incom-plete, ask the mud service company which was on the well if they still have information such as daily reports from that well. Bit records are often available from bit vendors. Wireline logs are usually archived for at least ten years prior to disposal by the logging contractor. IADC and geolograph reports can be more useful than daily drilling telexes because they will often hold more detailed information and are usual-ly more accurate than the daiusual-ly report telex to the drilling office. The drilling contractor may still have these somewhere.
Other outside data may include maps showing structures, surface features (for planning access to the site, locating water sources, and avoiding sensitive areas), and offset wells. In addition, government records are an important source of information. In many if not most areas worldwide, regulations demand that well information be filed
[ ]
with a regulatory body. It may also be possible to talk to the people responsible for wells in the area. They often have detailed personal knowledge of the wells drilled.
Hole section summaries. There is a good method of summarizing large quantities of offset data in a way that is meaningful “at a glance.” These documents can be updated as further wells are drilled. They are invaluable later on for those 2 a.m. calls from the rig when problems are encountered, as well as for updating the programs of subsequent wells. The wellsite drilling supervisor can use them for reference if attached to the well plan. They are also useful to include in end of well reports. They are called hole section summaries because each sheet sum-marizes one hole section for all wells drilled at that time.
A hole section summary is created for each hole section. Information from each offset well is shown side by side in columns, which are divided in rows by formation. Comparisons can be quickly made in the same formations between several wells. On the left-hand side the formation is described to show lithologies and problem areas, with notes on compressive strengths (derived from sonic logs) and other relevant information.
For each well there are three adjacent columns. The left column shows depths of formation tops and thicknesses. The center column shows a representation of each bit run, including BHAs used, bit gradings, etc. An arrow shows each bit run and information regard-ing the run is written in. The right-hand column shows data on para-meters, rate of penetration (ROP), mud properties, and short notes where needed.
Below each well section is a box to include comments on casing/cement jobs, overgauge hole from logs, and any problems log-ging or other worthwhile comments.
It is very easy to use these summaries to refer to while planning. It is recommended that you make these from the information avail-able to you before you do anything else on the well plan. These sum-maries should not be swamped with too much detail or they lose their utility. You can easily use them to identify areas needing further study. (See Fig. 1—1.)
W ell 1 W ell 2 For mation Depth Bitrun Data Parameters, Depth Bitrun Data Parameters, Details BR T Comments B R T Comments Guitar 1010 A TM05, 20-13-13 KCl Polymer mud 1084 A TM05, 18-13-13 KCl Polymer mud LSt, Sh interbeds Locked BHA 0.49 psi/ft Locked BHA 0.49 psi/ft Lst: RPM sensitive | | | | T
ight hole on conns
Sh: WOB sensitive | | | | 1171–1295 | | | | Backr eamed, Compr essive | | T ight hole | | no fur ther str ength | | on conns | | pr oblems | | WOB 30–55 | | 9—12,000 psi with | | | | 7–20 m/hr | | | | Shale str eaks | | RPM 100–150 | | Checktrip @ 1353 to 18,000 | | -| |-no drags \/ | | Cavings @ <.5 psi/ft Bit pulled at 1531 | | 100k o/pull @ 1350 | | POH Losses @ >.5 psi/ft 521 @ 15.8 m/hr , PI Pulled doing 8 m/hr | | WOB 35–55 33.6 | | RPM 120–140 T
ight hole on trips,
1/1/BT/A/E/I/JKD/PR
Hole good on trip
| |
Ream 1 time befor
e can pull thr ough | | conns with car e | | ---\/ A TM22GD, 20-13-13 Star ted drilling at Bit pulled 1843, 759 Pulled doing 7 m/hr 7m/hr @ 11.3 Locked BHA 1/1/BT/M/F/I/ID/PR, | | PI 29.0 | |
[ ]
| | WOB 30–60 A TM11HG, 18-13-13 Star ted drilling at | | 7 m/hr | | RPM 100–150 Locked BHA | | | | (892) \/ | | 7 m/hr | | | | Plectrum 1902 Bit pulled 1964; 433 ROP incr eased to 12 1870 | | 12 m/hr @ 7.3 | | Sst, Lst, Sltst, Sh 2/1/NO/A/E/I/NO/TQ,Hole good on trip
| | PI 16.7 | | ---| ---| T
otal losses possible
MF27D, 20-16-16 WOB 30–55 | | A verage parameters: Locked BHA RPM 100–150 | | WOB/RPM 30– | | 47/110–130 Compr essive str ength \/ | | GPM/PSI 600/2100 6ñ9000 psi with Bit pulled 2059; 95 | | Mud 0.49 psi/ft shale str eaks to | | 15,000 psi @ 7.6 | | | | | | 0/0/NO/A/E/I/NO/ Existing crack in | | T or que 5000 ft/lbs TW , PI 8.8 DC? No tor que | | indication seen. | | ---WOB 10–50 (TQ) | | 1 0 m/hr average Incr easing Sst with MF27D, 20-15-15 RPM 110–140 | | depth \/ | | Bit pulled 2111; 52 | | @ 4.1 | | 3/2/CT/H/E/I/NO/TQ, Cr ooked hole? | | PI 2.7 | | (244) ---| ---| 10 m/hr 1.1.2 Well Design
Gstring 2146 MF27DL, 20-15-15 Ream fr/ 2059, 24 hrs 2107 | | 4.5 m/hr | | C str th 7500– Locked BHA WOB 10–50 (TQ) | | T
ight hole conn 2115
12,000 psi | | | | Lst w/Sst str eaks (26) | | RPM 100 150 | | 4.5 m/hr | | | | Bridge 2172 \/
High drilling tor
que 2131 | | 7.5 m/hr Sst, Slsts, Sh with Bit pulled 2253; 142 \/ Stab twistof f (ran with Lst str eaks @ 4.5
this bit only)
Sand: 12–20 m/hr
3/3/CT/H/E/I/BT/TQ,
T
ight hole POH
Bit pulled 2220; Shale: 3–6 m/hr PI 8.1 to 2060 377 @ 10.0 Compr essive str ength --- 1/1/BT/H/F/I/CT/TW ,
No o/p POH or drag
7500-12,000 psi PI 20.6 RIH SS84FD, 18/16/16 ---Mud 0.49 psi/ft
Comments: general, problems casing and cementing, etc.
[ ]
With the hole section summaries completed, you now have a detailed overview of all the relevant wells. Now look at each formation and list all the problems seen within that formation: tight hole, enlarged hole, kicks, stuck pipe, etc. For each problem, do a complete analysis and establish:
■ What were the contributing factors that can be seen from the
data?
■ What other factors may have been relevant but were not noted
in the records?
■ How can this problem be eliminated, or at least reduced? ■ What actions can be taken if the problem is seen on the next
well to mitigate the effects of the problem?
If possible, avoid relying on the conclusions of other people who have reported on the problem. It is better to look at the source data yourself and make your own conclusions. Let me give a real case example.
An offshore well was being planned in the Mediterranean. According to prognosis, the pore pressure was to increase from normal pressure (hydrostatic) only 500 m below the seabed. Offset wells, even using oil-based mud, had reported very unstable wellbore conditions in shallow Pliocene shales with large quantities of cavings. A report by the previous concession holder had looked at seismic and sonic data, con-cluding that increased sonic transit times were due to undercompact-ed/overpressured shales. On the surface, this was consistent with the drilling problems that were experienced .
A closer look at the hole section summary revealed some interest-ing facts. Usinterest-ing oil-based mud in the first offset well, bottoms up after wipertrips had brought up large quantities of cavings. Mud density was increased, but the problem got worse, not better. However, they con-tinued to increase the mud density and still the cavings level increased every time they wipertripped, which was often. The third offset well was drilled with a pilot hole through these shales and opened up with seawater with no flow from the well.
Unfortunately, samples from the shakers were not available from this interval on any of the offset wells. However, all the evidence seemed to be consistent with fractured shales, not overpressured shales. The mud used on the new well included additives to plug off
these fractures as they were drilled, mud density was minimized, no wipertrips were done, and the drillers were briefed on good tripping and connection practices to minimize surge and swab pressures. This strategy was successful and the Pliocene shales were drilled and cased quickly using a KCl-PHPA-Glycol mud with only minor cavings. There were no problems tripping or running casing.
Field operational notes. Daily drilling reports often leave a lot of
relevant information unrecorded. Drilling programs rarely give suffi-cient information to the drilling supervisor about the formations he/she is expected to drill through. Both these concerns can be over-come by writing and updating field operational notes.
All the available data relating to each formation should be sum-marized for future reference when planning and drilling. These should be kept up to date. The following example of field operational notes are from an actual operations manual (see Fig. 1-2). It can be seen that there is much useful information to aid in bit selection and use, mud parameters, and drilling practices.
These notes were allowed into the public domain with the kind permission of the Badr Petroleum Company, Egypt (BAPETCO).
Formation Name: Abu Roash Type: Limestone + shale interbeds
Principal Problems: Lost circulation, shale cavings, hydration
swelling, gauge wear, and washouts
The Abu Roash formation presents a delicate problem. Too much density + ECD with KCl polymer muds lead to losses (probably in the limestone) but the mud density needed to minimize losses causes shale cavings. Tight control of mud parameters and drilling practices is needed. Ideally keep the density between 0.48-0.50 (maximum), PV as low as possible (10-15), YP in the range 17-21, and gels 3/5 to 5/8. Avoid surging on trips or after connections and minimize ECD. It is possible to live with the cavings, keep the hole clean, have low hole drags, and have few loss problems. If the hole was to be kicked off higher up, increasing hole angle would lead to problems of cuttings/cavings beds forming and consequent hole cleaning
[ ]
ties. Logging will show large washouts (off-scale in places), but the benefits in saved time with avoided losses more than compensates.
If losses occur in spite of good mud control, try reducing the cir-culation rate. You may find that a small reduction is all that is needed to cure the losses. After an hour or two of drilling ahead, it may be possible to slowly bring the circulation back to full rate. If total loss-es occur, first measure how much water is needed to fill the annulus. If the hole is static and full with water on top, slowly kick in the pumps and try to attain a circulation rate that will at least lift cuttings up the hole to the loss zone and cool the bit with very low weight on bit/revolutions per minute (WOB/RPM). Circulation of 250 gallons per minute (GPM) will give 50 feet per minute annular velocity (FPM AV) around 5 in drillpipe in 121/4 in hole; this should be used as the
minimum. Drill ahead at reduced parameters and monitor drags and torques carefully for signs of drilled solids causing problems (poten-tial stuck pipe). The losses are likely to cure themselves as generated cuttings act as lost circulation material (LCM) to plug the loss zone. Note that in past wells, LCM and cement have both been pumped, lost lots of time, and did not work.
The shale interbeds need a fair amount of inhibition and by expe-rience it has been determined that if KCl is maintained at 40-42 ppb and shaledrill polymer at 1.0-1.5 ppb, there are no shale hydration problems. Keep a close eye on the mud properties and have the mud man run several tests throughout the day. The drilling engineer can be delegated the specific task of keeping an eye on this and personally supervising the tests to ensure that the tests are done properly and accurate results are given. There have been cases of mud men giving false results after a test to make it look as if the mud is in good shape when in fact it needs treatment.
In order to get the best drilling performance, the driller has to have the freedom to adjust the parameters for best ROP. The formation is quite streaky and changes constantly. The limestone is more sensitive to high RPM/lower WOB and the shales are better drilled with maxi-mum WOB/lower RPM. If the driller is given a range of parameters to work within and is constantly experimenting for best ROP, the overall bit run will be far better.
Differential sticking is not probable in the Abu Roash formation. On trips out of the hole (through hole drilled since the last trip) the shales can give quite high overpulls. Backreaming is not necessary or helpful, just take the time to work up carefully without setting off the jar. Make sure you can come up about 3 m extra before setting the slips to break off a stand, otherwise you may not be able to go down enough to free the pipe if you pull straight into tight hole after racking the stand. Once you have wiped through it, you will probably not see sig-nificant overpull again at the same depth.
In summary, keep a very tight handle on the mud properties. Ensure that solids control equipment is kept functioning at top effi-ciency and check this personally several times a day. Do not rely on the crews to spot equipment problems. A centrifuge is worthwhile. Dump the sand trap and dilute as necessary. Avoid swab/surge that will increase shale instability and possibly induce losses. If losses occur it will be quicker and easier to cure with cuttings and care than pumping LCM and waiting. Run large nozzles, since maximizing hydraulic horsepower (HHP) does not seem to have a measurable ben-eficial effect; optimize impact force if optimization is preferred. Good bit runs have been obtained with Hughes ATM05 and Smith F1 in a 121/4 12º in hole. Be willing to use maximum WOB. General type of
bit: journal bearing, good gauge protection with diamond-coated heel row and gauge inserts, and a 4-1-7 or 4-2-7 type cutting structure. Also use locked bottom hole assemblies (BHAs) where possible. Ream before connections. Work carefully through high overpulls when trip-ping out, it may add a couple of hours to the trip, but you should not get into trouble.
Well Design: General
1.2
[ ]
The well design defines the desired final status of the well. The design, therefore, defines casing sizes, grades, weights, connections, and setting position (relative to depths or formation tops). Cement tops and particular requirements will be noted. It will define whether the well is to be completed, tested, suspended, or abandoned. Precompletion sta-tus (e.g., permanent packers, perforation intervals, downhole sand con-trol measures such as gravel packs, completion fluid) and required com-pletion design, wellhead, and Xmas tree will be specified. Surface loca-tion and direcloca-tional requirements are also part of the well design.
Once the well design is known then the drilling program can be written to achieve the well design safely and cost effectively.
The steps to take to design the well include the following:
■ Summarize and evaluate all relevant offset information. This first
stage is vital if you want to write the best possible drilling pro-gram. (Refer to “Sources of offset data,” “Hole section sum-maries,” and “Field operational notes” in Section 1.1.2., Data Acquisition and Analysis)
[ ]
1.2 Well Design■ Identify all potential hazards (surface and subsurface) and
poten-tial drilling problem areas. For each potenpoten-tial hazard or problem gather as much information as possible, establish the root causes of the problem, and determine how they can be addressed. Ensure that the well design takes account of them to minimize impact and allow safe recovery. At this stage the outline casing points and mud performance requirements may start to become clear.
■ Identify completion design or drill stem test (DST) requirements,
including fluids, necessary sand control measures, or other down-hole equipment (e.g., packers). This should be done before the cas-ing design since it may have an impact on the cascas-ing.
■ Choose casing points that allow kick tolerances to be maintained,
minimize potential downhole hazards, and minimize potential drilling problems. Identify casing properties (outside diameter, weight, grade, connections, etc.) for each casing string, taking into account the directional plan. This is an iterative process because the directional plan may depend on the casing design and vice versa. If the rig is known at this stage, ensure that the conductor and casings can all be handled (rotary table inside diameter, der-rick load, handling equipment).
■ Specify the cementing requirements. Tops of cement slurries; any
particular requirements (e.g., high compressive strength for perfo-rating).
■ Define the wellhead and Xmas tree requirements. If the well has to
be suspended this might mean a mudline suspension or subsea wellhead system offshore.
■ Check all items on the proposal and ensure that the well is
designed to meet them; obtain dispensations or amendments if necessary from the sponsoring department.
■ Issue the well design document for approval.
■ Estimate times and costs to prepare an authorization for
expendi-ture (AFE) and time/depth curve. (Note: a more accurate estimate can be made after finishing the drilling program but timescales usually dictate that an AFE is done sooner.)
■ Identify long lead time items and obtain approval to place orders in
■ Check that the supporting infrastructure (roads, airfields, support
bases, etc.) is in place and fit for purpose; flag up if infrastructure needs upgrading.
■ Define the earliest possible start date (logistics, permits/approvals,
Precompletion and Completion Design
1.3
[ ]
“Precompletion” covers the well requirements that need to be met after drilling operations have ceased and before running the completion string. Precompletion will cover pre-installed downhole sand control measures (such as gravel packs), packers run before the tubing, etc.
“Completion” covers the tools and tubing that are run in as part of the production tubing string. This will include completion-run sand control measures (such as screens), downhole safety valves, etc. The type of completion run will be determined by the production needs of the well. Size of tubing, types of connections, accessories to run, etc. will depend on factors such as fluids produced, gas/oil ratio (GOR), production potential, tertiary recovery techniques planned, sand control requirements, etc.
Casing sizes should be no larger than that required by formation evaluation requirements and drilling and production equipment sizes in order to drill cost-effective wells that are fit for purpose. Sizing down a conventional well by one casing size can save over 20% on the drilled well cost. A production well traditionally drilled to total depth
[ ]
(TD) in 81/2in hole with a 7 in liner and 5 in production tubing could
be TD’d in 6 in with a 5 in liner/5 in monobore completion with no loss of production for significantly less cost. This would not be termed “slimhole” according to the current definition (completed in 43/4 in
hole or smaller) but it takes advantage of some of the slimhole devel-opments to drill a cheaper, fit-for-purpose well while avoiding the complications of true slimhole.
1.3.1. How the Completion Relates to the Well Design
The completion will affect the entire well design, especially the casing design. The completion proposed must be considered for all stages of the well’s lifecycle: running the completion, pressure testing, production, stimulation, workover, and abandonment.
Refer to the requirements of the well proposal in regard to what we need to know about the completion.
Preparation for the completion. There may be work required after the production casing or liner are cemented and before the completion is run. This work may just be a bit and scraper run or it may be nec-essary to install packers, perforate, and gravel pack, etc.
The following preparations may affect the production casing and/or liner string, including the cement:
■ Perforated intervals require high-compressive strength cement
(2000 psi is recommended) and a competent (360˚ coverage) sheath for zonal isolation. If it is a gas well, gas-blocking additives may be called for. Where future recompletions on other zones are anticipated, these intervals also need to have carefully tailored cement. Wells with bottom hole static temperatures above approx-imately 230˚F require silica flour in the cement for long-term tem-perature stability.
■ The sump required below the bottom perforation (e.g., to drop
guns after perforating) will affect the final TD. Below the sump will be the shoetrack (normally two casing joints plus float equipment) and a pocket below the shoe.
■ Fluid gradients, temperatures, and potential surface pressures will
dictate the strength of the casing required for any treatments car-ried out before the completion is run.
■ Permanent packers set in the well will work over a range of casing
sizes and weights. The correct packer must therefore be used. If the packer is only available to fit a certain casing’s inside diameter (ID), it may affect the choice of casing. Where heavier wall casing (smaller ID) is run higher up, the packer will have to clear through the smaller ID when run and there must be sufficient clearance. Special drift casing could also be used.
■ If the completion is to sting into the liner polished bore receptacle
(PBR) then the liner must incorporate a PBR and generally will require a polishing mill to be run before the completion. This could be combined with a bit and scraper run.
■ It is essential that the liner lap seals. Liner hangers can incorporate
integral packers, which are set after cementing; this may save time compared to running a tieback packer and can isolate the forma-tion from well pressures while the cement is still fluid (e.g., when reversing out excess cement).
Other preparatory work that may affect the well design apart from the casings includes:
■ Completion fluid characteristics may be dictated by the type of
per-forations, reservoir physical characteristics, and reservoir fluids chemistry.
Running the completion. The following circumstances may affect the well design:
■ Tubing accessories outside diameters (ODs) (such as SSSV
nip-ples, side pocket mandrels, packers, etc.) may dictate the possible range of casing IDs. In some cases a tapered casing string is required; for instance if a 7 in completion is run in 95/8 in casing,
the SSSV nipple may be too large for the 95/8in casing ID. It may
be possible to run 103/4 in casing higher up, swaged down to 95/8
in below the SSSV depth. Of course this introduces further com-plications for running and cementing.
■ If a dual completion is run, the sizes of tubings, collars, and
acces-sories must be carefully checked to ensure that sufficient clearance exists inside the production casings. Remember that the strings
[ ]
will move relative to each other during running as the telescopic joints take up the differences in joints run. Thus, tubing acces-sories may move opposite collars on the other string.
■ In high-angle wells, the maximum practical deviation for cable or
wireline tools is about 60˚. This may necessitate alternative strate-gies such as using coiled tubing or, if possible, pump down tools or setting nipples higher up in the well.
■ The type of completion will also dictate what kind of wellhead
system to use and how it is to be configured. Pressure testing the completion.
■ Fluid gradients, temperatures, and potential surface pressures will
dictate the minimum strength of the casing required during pres-sure testing. Tubing and packer leaks must also be considered in terms of where the pressures may be exerted and whether in col-lapse or burst. Temperature correction factors (TCF) are needed in hotter wells. (Note: TCF at 200˚C = 0.81 for Nippon steels!)
■ In deviated wells, consider the potential for casing wear and the
effect on the pressure rating of the casing. Burst strength will be determined by the thinnest part of the casing wall.
Production.
■ Fluid gradients, temperatures, and potential surface pressures will
dictate the strength of the casing required during production. Tubing and packer leaks must also be considered in terms of where the pressures may be exerted and whether in collapse or burst. Temperature correction factors are needed in hotter wells.
■ In deviated wells, consider the potential for casing wear and the
effect on the pressure rating of the casing.
■ Produced fluids and temperatures could affect the grade of
cas-ings used.
■ Produced fluids could affect the completion fluid chemistry.
Stimulation including gas lift.
■ Fluid gradients, temperatures, and potential surface pressures will
dictate the strength of the casing required for any treatments
ried out during stimulations.
■ Injection pressures for gaslift must be considered for casing burst;
also remember that if the production casing leaks, this pressure will be exerted against the previous casing.
Workovers and recompletions.
■ Provision may need to be made for a different completion in the
future; for instance as the well depletes it may be desired to run gas lift valves, submersible pumps, or other tools. The casing design will have to account for these future possibilities.
■ Where other zones may be produced later on, the casing design
will have to ensure that the required zones are accessible (e.g., not behind multiple casings), and that the cement sheath at that depth is high-compressive strength and provides good zonal isolation. Abandonment. Eventually the well will be abandoned. Government regulations may require certain actions to be taken. For example, in Egypt it is required that all annuli have cement between the casing and open hole, even though no permeable zones may be present. This is not currently a requirement in the North Sea. It is important to know these details at the well design stage to avoid unnecessary work in the future.
Restoration of the site after abandonment should also be consid-ered at the well design stage to minimize the expense later on.
1.3.2. Monobore Completions
Monobore completions (where fullbore access to the production zone is possible through the completion tubing) allow hole sizes to be decreased with no loss of production compared to traditional comple-tions. (See Fig. 1-3)
[ ]
Fig. 1-3 Examples of Possible Monobore Completion Schemes Advantages of slimhole, monobore wells. 1. Reduced well cost/enhanced project profitability.
2. Increased activity levels as cheaper wells make conventional, mar-ginally economic prospects worthwhile.
3. The capabilities of existing installations can be extended.
4. Possibly reduced location size (purpose-designed slimhole drilling rig), waste, and environmental impact.
5. Ideally suited to completions through several reservoirs where the reservoirs are produced and abandoned from the bottom up or pro-duction can be commingled.
6. Increased wellbore stability in some formations (e.g., fractured shales).
7. Coiled tubing drilling—especially underbalanced—may provide sidetracking opportunities from existing wells while minimizing impairment.
8. More expensive drilling and completion fluids can be used to min-imize impairment since the volumes required are much less. 9. Monobore completions allow fullbore access to the reservoir and
give more flexibility in managing the reservoir. Most or all well
1.3.2 Well Design
PBR Monobore
intervention work could be done under pressure; not killing the well will eliminate impairment due to killing for workovers. 10. May be useful for deeper wells where many casing strings are needed. 11. Reduction in required consumables and tangibles may ease
logisti-cal problems in remote areas. Offshore rigs need less resupply. 12. Exploration wells can be drilled as slim, cheap, throwaway wells
instead of as expensive potential producers. The target zones can be drilled using wireline-retrievable continuous cores to give better petrophysical and geological information. Platform location can then be optimized and wells designed for production can be drilled from the optimum location.
13. Where production is not a constraint (e.g., observation, injection wells) then a slim well may fully meet the objectives at minimum cost. 14. Smaller, compact wellheads and blowout preventers (BOPs) can
be used.
Disadvantages of slimhole wells. 1. Lack of contingency hole sizes.
2. A monobore completion may be less suited than a conventional completion to wells requiring the ability to select different zones. 3. Few dedicated slimhole rigs are presently available and there will be
a lack of incentive for drilling contractors to invest in them, unless operators find ways to create incentives.
4. In true slimhole sizes, well control presents more challenges and requires better training and equipment to detect and deal with small-er kicks, low annular capacities, and highsmall-er annular pressure drops. 5. Commitment is required both from operator management and from contractors and service companies, where many senior people find it hard to commit to radical change. Effective and committed man-agement of the project is a prerequisite to success.
6. Slimmer wells generally mean reduced contractor and supplier profits. New contracting strategies are required to align contractor and operator goals, which will include sharing risks and rewards of field development.
7. Planning and executing slimhole wells require high levels of drilling engineering expertise and the involvement of multidisci-pline teams (including contractor and service company personnel). 8. Limited mud densities due to high equivalent circulating densities
[ ]
9. Limited potential to reuse the original wellbore for sidetracks to other reservoirs.
10. May limit information obtained if the hole size prevents all required logging tools.
Relevant developments. 1. Monobore completions. 2. Coiled tubing drilling.
3. Developments in downhole equipment (i.e., motors, drillstring, bits).
4. Computerized systems to efficiently monitor the operation and to detect very small influxes (<1 bbl).
5. Better understanding of wellbore instability and superior muds now available compared to previously have reduced the risk of los-ing a well while drilllos-ing smaller holes than in the past.
6. Better understanding of downhole hydraulics.
7. All regular logging equipment exists for holes down to 41/8in hole,
150˚C, 15,000 psi.
8. Full production testing capability now exists with 31/8in OD tools.
1.3.3. Multiple String Completions
Where a well penetrates several zones that need to be produced but cannot be commingled, it is possible to run two completion strings using special dual packers to separate the zones. Planning to use dual completions clearly introduces some special considerations.
The two strings will generally be made into a dual packer, such as the Baker RDH (retrievable dual hydraulic) hanger. There will be two strings from above this packer to the dual hangers set in the wellhead. Below the dual packer will generally be a short tailpipe on one side and a long string with a seal assembly on the other side. When the com-pletion is run, the seal assembly on the long string will sting into a packer previously set downhole, so that production is possible along the long string from below this seal assembly depth or along the short string from between this seal assembly and the dual packer.
The long string can also selectively produce from different zones. Sliding side doors that can be opened or closed by wireline can open the long string between different seal assemblies.
