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Prassl w l_-_drilling_engineer

  1. 1. Drilling Engineering Dipl.-Ing. Wolfgang F. PrasslCurtin University of Technology
  2. 2. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringContents1 Introduction 1 1.1 Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.2 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.3 Personal at rig site . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1.4 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Rotary Drilling Rig 5 2.1 Rig Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 2.2 Hoisting System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 2.2.1 Derrick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 2.2.2 Block and Tackle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 2.2.3 Drawworks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 2.3 Rig Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 2.4 Circulation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 2.4.1 Mud Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 2.5 The rotary System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 2.5.1 Swivel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 2.5.2 Kelly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 2.5.3 Rotary Drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 2.6 Drilling Cost Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 2.6.1 Drilling Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 2.6.2 Drilling Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44CHAPTER 0 Page i
  3. 3. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 2.6.3 Tripping Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 2.7 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463 Geomechanics 59 3.1 Geology Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 3.2 Pore pressure Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 3.2.1 Hydrostatic Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 3.3 Fracture Gradient Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 3.3.1 Interpretation of Field Data . . . . . . . . . . . . . . . . . . . . . . . . . . 72 3.4 Mud Weight Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 3.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 774 Drilling Hydraulics 81 4.1 Hydrostatic Pressure Inside the Wellbore . . . . . . . . . . . . . . . . . . . . . . . 82 4.2 Types of Fluid Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 4.3 Rheological Classification of Fluids . . . . . . . . . . . . . . . . . . . . . . . . . . 87 4.4 Laminar Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . . . . . . . . . . 90 4.5 Turbulent Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . . . . . . . . . . 92 4.6 Pressure Drop Across Surface Connections . . . . . . . . . . . . . . . . . . . . . . 101 4.7 Pressure Drop Across Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 4.8 Initiating Circulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 4.9 Optimization of Bit Hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 4.10 Particle Slip Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 4.11 Surge and Swab Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 4.12 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1115 Drilling Bits 113 5.1 Drill Bit Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 5.1.1 Roller Cone Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 5.1.2 Fixed Cutter Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120CHAPTER 0 Page ii
  4. 4. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 5.1.3 Coring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125 5.2 Drill Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127 5.2.1 Roller Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127 5.2.2 Drag Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129 5.3 Drill Bit Selection and Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 130 5.3.1 Tooth Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 5.3.2 Bearing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 5.3.3 Gauge Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 5.4 Factors that Affect the Rate Of Penetration . . . . . . . . . . . . . . . . . . . . . 132 5.4.1 Bit Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 5.4.2 Formation Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 5.4.3 Drilling Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 5.4.4 Operating Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135 5.4.5 Bit Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138 5.4.6 Bit Hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138 5.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1396 Drillstring Design 145 6.1 Drill Pipe Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146 6.2 Calculation of Neutral Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148 6.3 Drillstring Design Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 6.3.1 Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 6.3.2 Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160 6.3.3 Biaxial Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162 6.3.4 Shock Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163 6.3.5 Torsion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163 6.4 Drillpipe Bending resulting from Tonging Operations . . . . . . . . . . . . . . . . 164 6.5 Selecting Drill Collar Weights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167 6.6 Stretch of Drillpipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167 6.7 Critical Rotary Speeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168CHAPTER 0 Page iii
  5. 5. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 6.8 Bottom Hole Assembly Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169 6.9 Placement of Stabilizers and Reamers . . . . . . . . . . . . . . . . . . . . . . . . . 170 6.9.1 Building Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 6.9.2 Holding Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 6.9.3 Dropping Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 6.9.4 WOB Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 6.10 Dogleg Severity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183 6.11 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1857 Drilling Fluid 191 7.1 Functions of Drilling Mud . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191 7.2 Types of Drilling Mud . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192 7.2.1 Water-base Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193 7.2.2 Oil-base Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195 7.3 Mud Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 7.4 Recommended Mud Flow Properties . . . . . . . . . . . . . . . . . . . . . . . . . 203 7.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2048 Casing Design 207 8.1 Casing Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 8.1.1 Conductor Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 8.1.2 Surface Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 8.1.3 Intermediate Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 8.1.4 Production Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 8.1.5 Liners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209 8.2 Casing Setting Depths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210 8.3 Casing Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211 8.4 API Casing Performance Properties . . . . . . . . . . . . . . . . . . . . . . . . . . 215 8.5 General Casing Design Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238 8.6 Graphical Method for Casing Design . . . . . . . . . . . . . . . . . . . . . . . . . 240CHAPTER 0 Page iv
  6. 6. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 8.7 Maximum Load Casing Design for Intermediate Casing . . . . . . . . . . . . . . . 244 8.8 Casing Centralizer Spacings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244 8.9 Stretch in Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246 8.10 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2499 Directional Drilling and Deviation Control 251 9.1 Mayor Types of Wellbore Trajectories . . . . . . . . . . . . . . . . . . . . . . . . . 262 9.2 Trajectory Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267 9.3 Calculating the Survey of a Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268 9.3.1 Average angle method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271 9.3.2 Radius of curvature method . . . . . . . . . . . . . . . . . . . . . . . . . . 273 9.3.3 Minimum Curvature Method . . . . . . . . . . . . . . . . . . . . . . . . . . 273 9.4 Dogleg Severity Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274 9.5 Deflection Tools and Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275 9.5.1 Natural Formation Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . 278 9.5.2 Hydraulic Method (Jetting) . . . . . . . . . . . . . . . . . . . . . . . . . . 278 9.5.3 Mechanical Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279 9.6 While Drilling Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284 9.6.1 Measurement While Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . 284 9.6.2 Logging While Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285 9.6.3 Data Transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285 9.7 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28610 Borehole Problems 289 10.1 Differential Pipe Sticking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 10.2 Free Point Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291 10.3 Freeing Differentially Stuck Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292 10.3.1 Spotting Organic Fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292 10.3.2 Hydrostatic Pressure Reduction . . . . . . . . . . . . . . . . . . . . . . . . 292 10.3.3 Backoff Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294CHAPTER 0 Page v
  7. 7. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 10.4 Lost Circulation Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294 10.5 Keyseats . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 10.6 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29711 Kick Control and Blowout Prevention 301 11.1 Blowout Preventer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302 11.1.1 Ram preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304 11.1.2 Annular preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306 11.2 Well Control Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 11.3 Length and Density of Kick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313 11.4 Kick Tolerance and Kill Mud Weight . . . . . . . . . . . . . . . . . . . . . . . . . 314 11.5 Pump Pressure Schedules for Well Control Operations . . . . . . . . . . . . . . . . 315 11.6 Kick Removal – Two Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316 11.6.1 Wait-and-weight method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317 11.6.2 Driller’s method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 11.7 Equations Required to Perform Dynamic or Polymer Kill . . . . . . . . . . . . . . 320 11.8 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32412 Cementing 325 12.1 Functions of Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325 12.2 Properties of Cement Slurry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 327 12.2.1 Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 328 12.3 Cement Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 329 12.3.1 Extenders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333 12.3.2 Accelerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333 12.3.3 Retarders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333 12.3.4 Weighting Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 335 12.3.5 Fluid Loss Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 335 12.3.6 Dispersants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336 12.4 Primary Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 340CHAPTER 0 Page vi
  8. 8. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 12.5 Liner Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346 12.6 Squeeze Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346 12.7 Plugback Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 349 12.8 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351CHAPTER 0 Page vii
  9. 9. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringChapter 1Introduction1.1 ObjectivesThis text aims to give students an in-troduction to the principles and somerecommended procedures practicedin drilling engineering. All chapterscontain a theoretical introduction, aswell as examples and exercises. Ref-erences for further readings are givenat the end of this text. Necessaryequations and procedures to solve theexercises are presented through outthe text.1.2 GeneralWhen a drilling project is com-menced, two goals are governing allaspects of it. The first is to realizethe well in a safe manner (personalinjuries, technical problems) and ac-cording to its purpose, the secondone is to complete it with minimumcost. Thereto the overall costs of thewell during its lifetime in conjunctionwith the field development aspectsshall be minimized. This optimiza-tion may influence where the well is Figure 1.1: Rotary Drilling ProcessCHAPTER 1 Page 1
  10. 10. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringdrilled (onshore - extended reach or offshore above reservoir), the drilling technology applied (con-ventional or slim-hole drilling) as well as which evaluation procedures are run to gather subsurfaceinformation to optimize future wells.For making hole, different technologies have been invented. Drilling technology Percussion drilling Rope -> “Pennsylvanian drilling” Drillstring With mud -> Quick percussion drilling Without mud -> “Canadian drilling” Rotating bit Full cross-section drilling Surface driven Rotary drilling Rotary nozzle drilling Subsurface driven Turbine drilling Positive displacement motor drilling Electro motor drilling Annular drilling Diamond coring Shot drilling Special techniques Abrasive jet drilling Cavitating jet drilling Electric arc and plasma drilling Electric beam drilling Electric disintegration drilling Explosive drilling Flame jet drilling Implosion drilling Laser drilling REAM drilling Replaceable cutterhead drilling Rocket Exhaust drilling Spark drilling Subterrene drilling Terra drilling Thermal-mechanical drilling Thermocorer drillingThroughout this text, rotary drilling technology is discussed exclusively.CHAPTER 1 Page 2
  11. 11. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering1.3 Personal at rig siteThis section describes the crew requirements and tasks of some individual crew members at therig site.The people directly involved in drilling a well are employed either by the operating company, thedrilling contractor or one of the service and supply companies. Out of the companies involved,the operating company is the owner and principal user of the services provided by the drillingcontractor and the different service companies.To drill an oil or gas well, the operating company (or simply called operator) acquires the rightfrom the land owner under which the prospective reservoir may exist, to drill and produce from it.Usual, when a well has to be drilled, a tender is run by the operator and various drilling contractorsare invited to place their bid. Since drilling contractors are companies that perform the actualdrilling of the well, their main job is to drill a hole to the depth/location and specifications setby the operator. Along with hiring a drilling contractor ,the operator usually employs variousservice and supply companies to perform logging, cementing or other special operations as well asmaintaining the mud in its planed condition.Most drilling crews consist of a tool pusher, a driller, a derrickman, a mud logger and two or threerotary helpers (also called floormen or roughnecks). Along with this basic crew configuration theoperator sends usually a representative, called company man to the rig. For offshore operationsthe crews usually consist of many more employees.Tool PusherThe tool pusher supervises all drilling operations and is the leading man of the drilling contractoron location. Along with this supervision duties, he has to co-ordinate company and contractoraffairs.Company ManThe company man is in direct charge of all the company’s activities on the rig site. He is responsiblefor the drilling strategy as well as the supplies and services in need. His decisions directly effectthe progress of the well.DrillerThe driller operates the drilling machinery on the rig floor and is the overall supervisor of allfloormen. He is directly responsible to the tool pusher and is the person who is most closelyinvolved in the drilling process. He manipulates from his position at the control console on therig floor brakes, switches, levers and other related controls that influence the drilling parameters.In case of a kick he is the first person to take action by moving the bit off bottom and close theBOP.CHAPTER 1 Page 3
  12. 12. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringDerrick ManThe derrickman works on the so-called monkeyboard, a small platform up in the derrick, usuallyabout 90 [ft] above the rotary table. When a connection is made or during tripping operations heis handling and guiding the upper end of the pipe. During drilling operations the derrickman isresponsible for maintaining and repairing the pumps and other equipment as well as keeping tabson the drilling fluid.Floor MenDuring tripping, the rotary helpers are responsible for handling the lower end of the drill pipe aswell as operating tongs and wrenches to make or break a connection. During other times, theyalso maintain equipment, keep it clean, do painting and in general help where ever help is needed.Mud Engineer, Mud LoggerThe service company who provides the mud almost always sends a mud engineer and a mud loggerto the rig site. They are constantly responsible for logging what is happening in the hole as wellas maintaining the propper mud conditions.1.4 MiscellaneousAccording to a wells final depth, it can be classified into: Shallow well: < 2,000 [m] Conventional well: 2,000 [m] - 3,500 [m] Deep well: 3,500 [m] - 5,000 [m] Ultra deep well: > 5,000 [m]With the help of advanced technologies in MWD/LWD and extended reach drilling techniqueshorizontal departures of 10,000+ [m] are possible today (Wytch Farm).CHAPTER 1 Page 4
  13. 13. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringChapter 2Rotary Drilling RigThe most common drilling rigs in use today are rotary drilling rigs. Their main tasks are to createrotation of the drillstring and facilities to advance and lift the drillstring as well as casings andspecial equipment into and out of the hole drilled. The main components of a rotary drilling rigcan be seen in picture 2.1.Since the rig rate (rental cost ofthe rig) is one of the most influenc-ing cost factors to the total costof a well, careful selection of theproper type and capacity is vitalfor a successful drilling project.For all rigs, the depth of theplanned well determines basic rigrequirements like hoisting capac-ity, power system, circulation sys-tem (mud pressure, mud stream,mud cleaning), as well as the pres-sure control system. The se-lection of the most cost-efficientrig involves both quantitative andqualitative considerations. Of thequantitative considerations, therig power system, the hoisting sys-tem, the circulation system, therotary system, the derrick andsubstructure as well as the pres-sure control system are the mostimportant ones. How to calculatethe various requirements is dis-cussed below. The qualitative as-CHAPTER 2 Figure 2.1: Rotary Drilling Rig Page 5
  14. 14. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringpects involve technical design, appropriate expertise and training of the drilling crew, contractor’strack record and logistics handling.In general, rotary rigs can be distinguished into: Land rigs: conventional rigs: small land rigs, medium land rigs, large land rigs, mobile rigs: portable mast, jacknife, Offshore rigs: bottom anchored rigs: artificial island, TLP, submersible, jackup, concrete-structured, etc., floating rigs: drillship, semi-submersible, barge.For offshore rigs, factors like water depth, expected sea states, winds and currents as well aslocation (supply time) have to be considered as well.It should be understood that rig rates are not only influenced by the rig type but they are alsostrongly dependent on by the current market situation (oil price, drilling activity, rig availabilities,location, etc.). Therefore for the rig selection basic rig requirements are determined first. Thendrilling contractors are contacted for offers for a proposed spud date (date at which drillingoperation commences) as well as for alternative spud dates. This flexibility to schedule the spuddate may reduce rig rates considerably.2.1 Rig Power SystemThe power system of a rotary drilling rig has to supply the following main components: (1) rotarysystem, (2) hoisting system and (3) drilling fluid circulation system. In addition, auxiliaries likethe blowout preventer, boiler-feed water pumps, rig lighting system, etc. have to be powered.Since the largest power consumers on a rotary drilling rig are the hoisting and the circulationsystem, these components determine mainly the total power requirements. At ordinary drillingCHAPTER 2 Page 6
  15. 15. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringoperations, the hoisting (lifting and lowering of the drillstring, casings, etc.) and the circulationsystem are not operated at the same time. Therefore the same engines can be engaged to performboth functions.The power itself is either generated at the rig site using internal-combustion diesel engines, ortaken as electric power supply from existing power lines. The raw power is then transmitted tothe operating equipment via: (1) mechanical drives, (2) direct current (DC) or (3) alternatingcurrent (AC) applying a silicon-controlled rectifier (SCR). Most of the newer rigs using the AC-SCR systems. As guideline, power requirements for most rigs are between 1,000 to 3,000 [hp].The rig power system’s performance is characterised by the output horsepower, torque and fuelconsumption for various engine speeds. These parameters are calculated with equations 2.1 to 2.4: ω.T P = (2.1) 33, 000 Qi = 0.000393.Wf .ρd .H (2.2) P Et = (2.3) Qi ω = 2.π.N (2.4)where: P [hp] ... shaft power developed by engine ω [rad/min] ... angular velocity of the shaft N [rev./min] ... shaft speed T [ft-lbf] ... out-put torque Qi [hp] ... heat energy consumption by engine Wf [gal/hr] ... fuel consumption H [BTU/lbm] ... heating value (diesel: 19,000 [BTU/lbm]) Et [1] ... overall power system efficiency ρd [lbm/gal] ... density of fuel (diesel: 7.2 [lbm/gal]) 33,000 ... conversion factor (ft-lbf/min/hp)When the rig is operated at environments with non-standard temperatures (85 [F]) or at highaltitudes, the mechanical horsepower requirements have to be modified. This modification isaccording to API standard 7B-11C: (a) Deduction of 3 % of the standard brake horsepower for each 1,000 [ft] riseCHAPTER 2 Page 7
  16. 16. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering in altitude above mean sea level, ◦ (b) Deduction of 1 % of the standard brake horsepower for each 10 rise or fall in temperature above or below 85 [F], respectively.2.2 Hoisting SystemThe main task of the hoisting system is to lower and raise the drillstring, casings, and othersubsurface equipment into or out of the well.The hoisting equipment itself consists of: (1)draw works, (2) fast line, (3) crown block, (4) travel-ling block, (5) dead line, (6) deal line anchor, (7) storage reel, (8) hook and (9) derrick, see sketch2.2. Figure 2.2: Hoisting systemCHAPTER 2 Page 8
  17. 17. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringMaking a connectionWith the phrase “Making a connection”, the periodic process of adding a new joint of drillpipe tothe drillstring as the hole deepens is referred. This process can be seen in figure 2.3. Figure 2.3: Making a connectionMaking a tripWith the phrase “Making a trip”, the process of moving the drillstring out of the hole, changethe bit or alter the bottom-hole assembly, and lower the drillstring again into the hole is referred.The process of tripping out is sketched at figure 2.5. Figure 2.4: Sketch of slips for drill pipe(a), drill collar(b) and casing(c)CHAPTER 2 Page 9
  18. 18. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.5: Tripping Out Figure 2.6: Lifting pipe at the rig floorCHAPTER 2 Page 10
  19. 19. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringSometimes the drillstring is not completely run out of the hole. It is just lifted up to the top of theopen-hole section and then lowered back again while continuously circulating with drilling mud.Such a trip, called “wiper trip”, is carried out to clean the hole from remaining cuttings that mayhave settled along the open-hole section. Figure 2.7: Sketch of a drill pipe spinner2.2.1 DerrickDerricks are classified (or rated) by the American Petroleum Institute (API) according to theirheight as well as their ability to withstand wind and compressive loads. API has publishedstandards for the particular specifications.The higher the derrick is, the longer stands it can handle which in turn reduces the tripping time.Derricks that are capable to handle stands of two, three or four joints are called to be able to pull“doubles”, “thribbles”, or “fourbles” respectively.CHAPTER 2 Page 11
  20. 20. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.8: Storage of doubles inside the derrick2.2.2 Block and TackleThe crown block, the travelling block and the drilling line comprise the block and tackle whichpermits the handling of large loads. To lift and lower the heavy loads into and out of the borehole,the drilling line is strung multiple times between the crown and the travelling block, see sketch2.11.When no friction is assumed in the travelling and the crown block (constant tension in the drillingline), the hook load W creates a load to the drawworks with is equal the load in the fast line Ffwhich in turn depends on the number the line is strung n between the travelling and the crownblock. This is expressed with: W = n.Ff (2.5)CHAPTER 2 Page 12
  21. 21. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.9: Sketch of load-distribution over derrick Figure 2.10: BrakesThe input power Pi of the block and tackle is equal to the drawworks load Ff times the velocityof the fast line νf . Pi = Ff .νf (2.6)CHAPTER 2 Page 13
  22. 22. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.11: Block and tackleThe output power or “hook power” Ph is given by the hook load times the velocity of the travellingblock. Ph = W.νb (2.7) Figure 2.12: Efficiency factors for different tacklingsDrilling line:The drilling line is a wire rope that is made of strands wounded around a steel core. It ranges indiameter from 1 to 2 [in]. Its classification is based on the type of core, the number of strands 2wrapped around the core, and the number of individual wires per strand. Examples of it can besee in figure 2.13.CHAPTER 2 Page 14
  23. 23. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.13: Drilling LineSince the drilling line is constantly under biaxial load of tension and bending, its service life isto be evaluated using a rating called “ton-mile”. By definition, a ton-mile is the amount of workneeded to move a 1-ton load over a distance of 1 mile.When the drilling line has reached a specific ton-mile limit, which is mainly due to round trips,setting casings, coring and drilling, it is removed from service. The ton-mile wear can be estimatedby:Round Trip: D. (Ls + D) .We D. Wb + WC 2 TR = + (2.8) 10, 560, 000 2, 640, 000where: Wb [lb] ... effective weight of travelling assembly Ls [ft] ... length of a drillpipe stand We [lb/ft] ... effective weight per foot of drillpipe D [ft] ... hole depth WC [lb] ... effective weight of drill collar assembly less the effective weight of the same length of drillpipeIt should be noted that the ton-miles are independent of the number of lines strung.CHAPTER 2 Page 15
  24. 24. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringThe ton-mile service of the drilling line is given for various activities according to:Drilling operation: (drilling a section from depth d1 to d2 ) which accounts for: 1. drill ahead a length of kelly 2. pull up length of kelly 3. ream ahead a length of kelly 4. pull up a length of kelly 5. pull kelly in rathole 6. pick up a single (or double) 7. lower drill string in hole 8. pick up kelly and drill ahead Td = 3. (TR at d2 − TR at d1 ) (2.9)Coring operation: which accounts for: 1. core ahead a length of core barrel 2. pull up length of kelly 3. put kelly in rathole 4. pick up a single joint of drillpipe 5. lower drill string in hole 6. pick up kelly Tc = 2. (TR2 − TR1 ) (2.10)where: TR2 [ton-mile] ... work done for one round trip at depth d2 where coring stopped TR1 [tin-mile] ... work done for one round trip at depth d1 where coring started.CHAPTER 2 Page 16
  25. 25. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringRunning Casing: D. (Lcs + D) .Wcs D.Wb Tsc = 0.5. + (2.11) 10, 560, 000 2, 640, 000where: Lcs [ft] ... length of casing joint Wcs [lbm/ft] ... effective weight of casing in mudThe drilling line is subjected to most severe wear at the following two points: 1. The so called “pickup points”, which are at the top of the crown block sheaves and at the bottom of the travelling block sheaves during tripping operations. 2. The so called “lap point”, which is located where a new layer or lap of wire begins on the drum of the drawworks.It is common practice that before the entire drilling line is replaced, the location of the pickuppoints and the lap point are varied over different positions of the drilling line by slipping and/orcutting the line.A properly designed slipping-cut program ensures that the drilling line is maintained in goodcondition and its wear is spread evenly over its length.To slip the drilling line, the dead-line anchor has to be loosened and a few feet of new line is slippedfrom the storage reel. Cutting off the drilling line requires that the line on the drawworks reelis loosened. Since cutting takes longer and the drawworks reel comprise some additional storage,the drilling line is usually slipped multiple times before it is cut. The length the drilling line isslipped has to be properly calculated so that after slipping, the same part of the line, which wasused before at a pickup point or lap point, is not used again as a pickup point or lap point.When selecting a drilling line, a “design factor” for the line is applied to compensate for wearand shock loading. API’s recommendation for a minimum design factor (DF ) is 3 for hoistingoperations and 2 for setting casing or pulling on stuck pipe operations. The design factor of thedrilling line is calculated by: Nominal Strength of Wire Rope [lb] DF = (2.12) Fast Line Load [lb]CHAPTER 2 Page 17
  26. 26. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringFigure 2.14: Nominal breaking strength of 6 X 19 classification rope, bright (uncoated) or drawn-galvanized wire, (IWRC)2.2.3 DrawworksThe purpose of the drawworks is to provide the hoisting and breaking power to lift and lower theheavy weights of drillstring and casings. The drawworks itself consists of: (1) Drum, (2) Brakes,(3) Transmission and (4) Catheads, see figure 2.15.The drum provides the movement of the drilling line which in turn lifts and lowers the travellingblock and consequently lifts or lowers the loads on the hook. The breaking torque, supplied bythe drum, has to be strong enough to be able to stop and hold the heavy loads of the drillingline when lowered at high speed. The power required by the drawworks can be calculated whenconsidering the fast line load and fast line speed. In this way: νf = n.νb (2.13) W.νb Ph = (2.14) 33, 000.Ewhere: Ph [hp] ... drum power output νf [ft/min] ... velocity of the fast line νb [ft/min] ... velocity of the travelling block W [lb] ... hook loadCHAPTER 2 Page 18
  27. 27. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering n [1] ... number of lines strung E [1] ... power efficiency of the block and tackle system Figure 2.15: DrawworksThe input power to the drawworks is influenced by the efficiency of the chain drive and the shaftsinside the drawworks. This is expressed with: K. (1 − K n ) E= (2.15) n. (1 − K)where: K [1] ... sheave and line efficiency, K = 0.9615 is an often used value.When lowering the hook load, the efficiency factor and fast line load are determined by:CHAPTER 2 Page 19
  28. 28. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering n.K n . (1 − K) ELowering = (2.16) 1 − Kn W.K −n . (1 − K) Ff −Lowering = (2.17) 1 − Knwhere: Ff [lbf] ... tension in the fast line2.3 Rig SelectionFollowing parameters are used to determine the minimum criteria to select a suitable drilling rig: (1) Static tension in the fast line when upward motion is impending (2) Maximum hook horsepower (3) Maximum hoisting speed (4) Actual derrick load (5) Maximum equivalent derrick load (6) Derrick efficiency factorThey can be calculated by following equations: Pi = Ff .νf (2.18) Ph νb = (2.19) W 1 + E + E.n Fd = .W (2.20) E.n n+4 Fde = .W (2.21) n Fd E.(n + 1) + 1 Ed = = (2.22) Fde E.(n + 4)where:CHAPTER 2 Page 20
  29. 29. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Fd [lbf] ... load applied to derrick, sum of the hook load, tension in the dead line and tension in the fast line Fde [lbf] ... maximum equivalent derrick load, equal to four times the maximum leg load Ed [1] ... derrick efficiency factorCHAPTER 2 Page 21
  30. 30. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering2.4 Circulation SystemThe principle components of the mud circulation system are: (1) mud pumps, (2) flowlines, (3)drillpipe, (4) nozzles, (5) mud pids and tanks (settling tank, mixing tank, suction tank), (6) mudmixing equipment (mud mixing hopper) and (7) contaminant removal equipment (shale shaker,desander, desilter, degasser), see sketch 2.16. Figure 2.16: Circulation systemCHAPTER 2 Page 22
  31. 31. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringThe flow of circulated drilling mud can be described as from the mud pit (storage of mud) via themud mixing hopper, where various additives like weighting material etc. can be mixed into themud, or the suction line to the mud pumps. At the mud pumps the mud is pressured up to therequired mud pressure value. From the mud pumps the mud is pushed through the stand pipe (apipe fixed mounted at the derrick), the rotary hose (flexible connection that allows the fed of themud into the vertically moving drillstring), via the swivel into the drillstring. Inside the drillstring(kelly, drillpipe, drill collar) the mud flows down to the bit where it is forced through the nozzlesto act against the bottom of the hole. From the bottom of the well the mud rises up the annuli(drill collar, drillpipe) and the mud line (mud return line) which is located above the BOP. Fromthe mud line the mud is fed to the mud cleaning system consisting of shale shakers, settlementtank, de-sander and de-silter. After cleaning the mud, the circulation circle is closed when themud returns to the mud pit. Figure 2.17: Sketch of mud pitCHAPTER 2 Page 23
  32. 32. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.18: Mixing hopper2.4.1 Mud PumpsNowadays there are two types of mud pumps in use (duplex pump, triplex pump), both equippedwith reciprocating positive-displacement pistons. The amount of mud and the pressure the mudpumps release the mud to the circulation system are controlled via changing of pump liners andpistons as well as control of the speed [stroke/minute] the pump is moving.Duplex Mud PumpThe duplex mud pump consists of two cylinders and is double-acting. This means that drillingmud is pumped with the forward and backward movement of the barrel. The pump displacementon the forward movement of the piston is given by: π 2 Ff d = .d .Ls (2.23) 4 lOn the backward movement of the piston, the volume is displaced: π 2 π π .dl .Ls − .d2 .Ls = .(d2 − d2 ).Ls r (2.24) 4 4 4 l rThus the total displacement per complete pump cycle is:CHAPTER 2 Page 24
  33. 33. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.19: Duplex mud pump Figure 2.20: Duplex mud pump - Pumping Scheme π 2 π π .dl .Ls + .(d2 − d2 ).Ls = .Ls .(2.d2 − d2 ) l r l r (2.25) 4 4 4Since duplex mud pumps are equipped with two cylinders, and assuming a volumetric efficiencyEv , the total pump displacement per cycle is given by: π Fp = .Ls 2.d2 − d2 .Ev l r (2.26) 2Triplex Mud PumpThe triplex mud pump consists of three cylinders and is single-acting. The pump displacementper cylinder for one complete cycle is given by: π 2 .d .Ls (2.27) 4 lThus the triplex mud pump, having a volumetric efficiency Ev has a total mud displacement ofFp per complete cycle.CHAPTER 2 Page 25
  34. 34. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering 3.π Fp = .Ls .d2 .Ev l (2.28) 4where: Fp [in2 /cycle] ... pump displacement (also called “pump factor”) Ev [1] ... volumetric efficiency (90 ÷ 100 %) Ls [in] ... stroke length dr [in] ... piston rod diameter dl [in] ... liner diameter Figure 2.21: Triplex mud pump Figure 2.22: Triplex mud pump - Pumping SchemeThe triplex pumps are generally lighter and more compact than the duplex pumps and theiroutput pressure pulsations are not as large. Because of this and since triplex pumps are cheaperto operate, modern rigs are most often equipped with triplex mud pumps.The the flow rate of the pump [in2 /min] can be calculated with:CHAPTER 2 Page 26
  35. 35. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering q = N.Fp (2.29)where: N [cycles/min] ... number of cycles per minuteThe overall efficiency of a mud pump is the product of the mechanical and the volumetric efficiency.The mechanical efficiency is often assumed to be 90% and is related to the efficiency of the primemover itself and the linkage to the pump drive shaft. The volumetric efficiency of a mud pumpwith adequately charged suction system can be as high as 100%. Therefore most manufacturesrate their pumps with a total efficiency of 90% (mechanical efficiency: 90%, volumetric efficiency:100%).Note that per revolution, the duplex pump makes two cycles (double-acting) where the triplexpump completes one cycle (single-acting).The terms “cycle” and “stroke” are applied interchangeably in the industry and refer to onecomplete pump revolution.Pumps are generally rated according to their: 1. Hydraulic power, 2. Maximum pressure, 3. Maximum flow rate.Since the inlet pressure is essentially atmospheric pressure, the increase of mud pressure due tothe mud pump is approximately equal the discharge pressure.The hydraulic power [hp] provided by the mud pump can be calculated as: ∆p.q PH = (2.30) 1, 714where: ∆p [psi] ... pump discharge pressure q [gal/min] ... pump discharge flow rateCHAPTER 2 Page 27
  36. 36. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringAt a given hydraulic power level, the maximum discharge pressure and the flow rate can be variedby changing the stroke rate as well as the liner seize. A smaller liner will allow the operator toobtain a higher pump pressure but at a lower flow rate. Pressures above 3,500 [psi] are appliedseldomly since they cause a significant increase in maintenance problems.In practice, especially at shallow, large diameter section, more pumps are often used simultaneouslyto feed the mud circulation system with the required total mud flow and intake pressure. For thisreason the various mud pumps are connected in parallel and operated with the same outputpressure. The individual mud streams are added to compute the total one.Between the mud pumps and the drillstring so called “surge chambers”, see figure 2.23, areinstalled. Their main task is to dampen the pressure pulses, created by the mud pumps. Figure 2.23: Surge chamberFurthermore a “discharge line” containing a relief valve is assembled before the mud reaches thestand pipe, thus in case the pump is started against a closed valve, line rapture is prevented.When the mud returns to the surface, it is lead over shale shakers that are composed of one ormore vibrating screens over which the mud passes before it is feed to the mud pits.The mud pits are required to hold an excess mud volume at the surface. Here fine cuttings cansettle and gas, that was not mechanically separated can be released further. In addition, in theevent of lost circulation, the lost mud can be replaced by mud from the surface pits.CHAPTER 2 Page 28
  37. 37. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 2.24: Shale shaker2.5 The rotary SystemThe function of the rotary system is to transmitrotation to the drillstring and consequently rotatethe bit. During drilling operation, this rotation isto the right.The main parts of the rotary system are: (1) swivel,(2) rotary hose, (3) kelly, (4) rotary drive (masterpushing, kelly pushing), (5) rotary table and (6)drillstring, see sketch 2.25.2.5.1 SwivelThe swivel which established a connection betweenhook and kelly, has to be constructed extremely ro-bust since it has to carry the total drillstring weightand at the same time, provide a high pressure seal(connection between flexible, non-rotating rotaryhose and the rotation kelly).2.5.2 KellyThe kelly has a square or hexagonal cross-sectionand provides the rotation of the drillstring. Since Figure 2.25: Rotary systemCHAPTER 2 Page 29
  38. 38. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringthe kelly is made of high quality, treated steel, itis an expensive part of the drillstring. Thus to prevent the kelly from excessive wear caused bymaking and breaking connections, a kelly sub is mounted at the bottom end of it. To preventpossible backward flow of the mud in case of an kick, a kelly cock providing a backflow restrictionvalve is often mounted between kelly and swivel. Figure 2.26: SwivelCHAPTER 2 Page 30
  39. 39. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering2.5.3 Rotary DriveThe rotary drive consists of master pushing and kelly pushing. The master pushing receives itsrotational momentum from the compound and drives the kelly pushing which in turn transfersthe rotation to the kelly. Figure 2.27: Master and kelly pushingFollowing equation can be applied to calculate the rotational power that is induced to the drill-string: T.N PR = (2.31) 5, 250where: PR [hp] ... rotational power induced to the drillstring T [ft-lb] ... rotary torque induced to the drillstring N [rpm] ... rotation speedPrior to drilling, the estimation of induced rotational torque is difficult since it comprises a com-bination of the torque at the bit as well as torque losses at the drillstring, following empiricalrelation has been developed:CHAPTER 2 Page 31
  40. 40. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering PR = F.N (2.32)The torque factor is approximated with 1.5 for wells with MD smaller than 10,000 [ft], 1.75 forwells with MD of 10,000 to 15,000 [ft] and 2.0 for wells with MD larger than 15,000 [ft].The volume contained and displaced by the drillstring can be calculated as:Capacity of drillpipe or drill collar: d2 Vp = (2.33) 1, 029.4Capacity of the annulus behind drillpipe or drill collar: (d2 − d2 ) 2 1 Va = (2.34) 1, 029.4Displacement of drillpipe or drill collar: (d2 − d2 ) 1 Vs = (2.35) 1, 029.4where: d [in] ... inside diameter of drillpipe or drill collar d1 [in] ... outside diameter of drillpipe or drill collar d2 [in] ... hole diameter V [bbl/ft] ... capacity of drillpipe, collar or annulus2.6 Drilling Cost AnalysisTo estimate the cost of realizing a well as well as to perform economical evaluation of the drillingproject, before commencing the project, a so called AFE (Authority For Expenditure) has to beprepared and signed of by the operator. Within the AFE all cost items are listed as they areknown or can be estimated at the planning stage. During drilling, a close follow up of the actualcost and a comparison with the estimated (and authorized) ones are done on a daily bases.When preparing an AFE, different completions and objectives (dry hole, with casing and comple-tion, etc) can be included to cost-estimate different scenarios.Generally, an AFE consists of the following major groups:CHAPTER 2 Page 32
  41. 41. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering (1) Wellsite preparation, (2) Rig mobilization and rigging up, (3) Rig Rental, (4) Drilling Mud, (5) Bits and Tools, (6) Casings, (7) Formation evaluationThe listed cost items and their spread are different at each company and can be different withinone company (onshore-offshore, various locations, etc.).Along with the well plan (well proposal) a operational schedule as well as a schedule of expecteddaily costs has to be prepared.In the following simple methods to estimate the drilling costs as well as, the drilling and trippingtimes are given.2.6.1 Drilling CostsOn of the most basic estimations of drilling costs is given by: Cb + Cr (tb + tc + tt ) Cf = (2.36) Dwhere: Cf [$/ft] ... cost per unit depth Cb [$] ... cost of bit Cr [$/hr] ... fixed operating cost of rig per unit time D [ft] ... depth drilled tb [hr] ... total rotation time during the bit run tc [hr] ... total non-rotating time during the bit run tt [hr] ... trip timeIt has been found that drilling cost generally tend to increase exponentially with depth. Thus,when curve-fitting and correlation methods are applied, it is convenient to assume a relationshipbetween drilling cost C and depth D as in equation 2.37: C = a.eb.D (2.37)The constants a and b depend primary on the well location.CHAPTER 2 Page 33
  42. 42. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering2.6.2 Drilling TimeThe drilling time can be estimated based on experience and historical penetration rates. Note thatthe penetration rate depends on: (1) type of bit used, (2) wear of bit used, (3) drilling parametersapplied (WOB, RPM), (4) hydraulics applied (hydraulic impact force due to mud flow throughnozzles), (5) effectiveness of cuttings removal, (6) formation strength and (7) formation type.Therefore an analytic prediction of the rate of penetration (ROP) is impossible. Estimations aregenerally based on the assumption of similar parameters and historic ROPs.To estimate the drilling time, the so called “penetration rate equation”, equation 2.38, is analyzed. dD = K.ea2 .D (2.38) dtWhen the historical values of depth [ft] versus ROP [ft/hr] are plotted on a semilogarithmic graphpaper (depth on linear scale), a straight line best-fit of the equation: 1 td = .e2.203.a2 .D (2.39) 2.303.a2 .Kestimates the drilling time. Here a2 is the reciprocal of the change in depth per log cycle of thefitted straight line, K is the value of ROP at the surface (intercept of fitted straight line at depth= 0 ft).The depth that can be drilled with each individual bit depends on (1) bit condition when inserted,(2) drilling parameters, (3) rock strength and (4) rock abrasiveness. Estimations of possiblefootages between trips can be obtained from historical data or applying equation 2.40: 1 D= .ln 2.303a2 .L.tb + 22.303.a2 .Di (2.40) 2.303.a2where: Di [ft] ... depth of the last trip D [ft] ... depth of the next tripAll other parameters are defined as above.2.6.3 Tripping TimeTripping time is also a major contributor to the total time spent for drilling a well. Tripping canbe either scheduled (change of bit, reach of casing point, scheduled well-cleaning circulation) orCHAPTER 2 Page 34
  43. 43. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringon-scheduled, due to troubles. Types of troubles, their origin and possible actions are discussedin a later chapter.Following relationship can be applied to estimate the tripping time to change the bit. Thus theoperations of trip out, change bit, trip in are included: ts tt = 2. .D (2.41) lswhere: tt [hr] ... required time for round trip ts [hr] ... average time required to handle one stand D [ft or m] ... length of drillstring to trip ls [ft or m] ... average length of one standThe term “stand” refers to the joints of drillpipe left connected and placed inside the derrickduring tripping. Depending on the derrick seize, one stand consists mostly of three, sometimesfour drillpipes. In this way during tripping only each third (fourth) connection has to be brokenand made up for tripping.CHAPTER 2 Page 35
  44. 44. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering2.7 Examples1. The output torque and speed of a diesel engine is 1,650 [ft-lbf] and 800 [rpm] respectively.Calculate the brake horsepower and overall engine efficiency when the diesel consumption rate is15.7 [gal/hr]. What is the fuel consumption for a 24 hr working day?2. When drilling at 7,000 [ft] with an assembly consisting of 500 [ft] drill collars (8 [in] OD, 2.5[in] ID, 154 [lbm/ft]) on a 5 [in], 19.5 [lbm/ft] , a 10.0 [ppg] drilling mud is used. What are theton-miles applying following assumptions (one joint of casing is 40 [ft], travelling block assemblyweights 28,000 [lbm], each stand is 93 [ft] long) when: (a) Running 7 [in], 29 [lbm/ft] casing, (b) Coring from 7,000 [ft] to 7,080 [ft], (c) Drilling from 7,000 [ft] to 7,200 [ft], (d) Making a round-trip at 7,000 [ft]?3. The rig’s drawworks can provide a maximum power of 800 [hp]. To lift the calculated load of200,000 [lb], 10 lines are strung between the crown block and the traveling block. The lead line isanchored to a derrick leg on one side of the v-door. What is the: (a) Static tension in the fast line, (b) Maximum hook horsepower available, (c) Maximum hoisting speed, (d) Derrick load when upward motion is impending, (e) Maximum equivalent derrick load, (f) Derrick efficiency factor?4. After circulation the drillstring is recognized to be stuck. For pulling the drillstring, followingequipment data have to be considered: derrick can support a maximum equivalent derrick load of500,000 [lbf], the drilling line strength is 51,200 [lbf], the maximum tension load of the drillpipeis 396,000 [lbf]. 8 lines are strung between the crown block and the traveling block, for pulling tofree the stuck pipe, a safety factor of 2.0 is to be applied for the derrick, the drillpipe as well asthe drilling line. What is the maximum force the driller can pull to try to free the pipe?5. To run 425,000 [lb] of casing on a 10-line system, a 1.125 [in], 6x19 extra improved plow steeldrilling line is used. When K is assumed to be 0.9615, does this configuration meet a safety factorrequirement for the ropes of 2.0? What is the maximum load that can be run meeting the safetyfactor?CHAPTER 2 Page 36
  45. 45. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering6. A drillstring of 300,000 [lb] is used in a well where the rig has sufficient horsepower to runthe string at a minimum rate of 93 [ft/min]. The hoisting system has 8 lines between the crownblock and the travelling block, the mechanical drive of the rig has following configuration: Engineno. 1: (4 shafts, 3 chains), engine no. 2: (5 shafts, 4 chains), engine no. 3: (6 shafts, 5 chains).Thus the total elements of engine 1 is 7, of engine 2 9 and of engine 3 11. When the efficiencies ofeach shaft, chain and sheave pair is 0.98 and 0.75 for the torque converter, what is the minimumacceptable input horsepower and fast line velocity?7. A triplex pump is operating at 120 [cycles/min] and discharging the mud at 3,000 [psig]. Whenthe pump has installed a 6 [in] liner operating with 11 [in] strokes, what are the: (a) Pump factor in [gal/cycles] when 100 % volumetric efficiency is assumed, (b) Flow rate in [gal/min], (c) Pump power development?8. A drillstring consists of 9,000 [ft] 5 [in], 19,5 [lbm/ft] drillpipe, and 1,000 [ft] of 8 [in] OD, 3[in] ID drill collars. What is the: (a) Capacity of the drillpipe in [bbl], (b) Capacity of the drill collars in [bbl], (c) Number of pump cycles required to pump surface mud to the bit (duplex pump, 6 [in] liners, 2.5 [in] rods, 16 [in] strokes, pumping at 85 % volumetric efficiency), (d) Displacement of drillpipes in [bbl/ft], (e) Displacement of drill collars in [bbl/ft], (f) Loss in fluid level in the hole if 10 stands (thribbles) drillpipe are pulled without filling the hole (casing 10.05 [in] ID), (g) Change in fluid level in the pit when the hole is filled after pulling 10 stands of drillpipe. The pit is 8 [ft] wide and 20 [ft] long.9. A diesel engine gives an output torque of 1,740 [ft-lbf] at an engine speed of 1,200 [rpm]. Therig is operated in Mexico at an altitude of 1,430 [ft] above MSL at a average temperature of 28◦ C. When the fuel consumption rate is 31.8 [gal/hr], what is the output power and the overallefficiency of the engine?10. A rig must hoist a load of 320,000 [lb]. The drawworks can provide an input power to theblock and tackle system as high as 500 [hp]. Eight lines are strung between the crown block andthe travelling block. Calculate:CHAPTER 2 Page 37
  46. 46. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering (a) Static tension in the fast line, (b) Maximum hook horse power, (c) Maximum hoisting speed, (d) Effective derrick load, (e) Maximum equivalent derrick load, (f) Derrick efficiency factor.11. The weight of the travelling block and hook is 23,500 [lb], the total well depth equals 10,000[ft]. A drillpipe of OD 5 [in], ID 4.276 [in], 19.5 [lb/ft] and 500 [ft] of drill collar OD 8 [in], ID 2- 13 16[in], 150 [lb/ft] comprise the drillstring. The hole was drilled with a mud weight of 75 [lb/ft3 ]. steelweight: 489.5 [lb/ft3 ], line and sheave efficiency factor = 0.9615, block and tackle efficiency=0.81.Calculate: (a) Weight of the drill string in air and in mud, (b) Hook load, (c) Dead line and fast line load, (d) Dynamic crown load, (e) Design factor for wire line for running drill string,CHAPTER 2 Page 38
  47. 47. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringChapter 3GeomechanicsThe knowledge of the formations to penetrate, their strength properties as well as their behaviourwhen in contact with various drilling fluids is essential to properly plan and complete a successfuldrilling project. Parameters like pore pressure and formation strength determine aspects like: 1. Choice of mud weight profile, 2. Determination of casing setting depths, 3. Design of optimal casing strings, 4. Selection of the drill bit, 5. Cementing additives and procedures.The way how the formations react to drilling mud influences the selection of mud additives,borehole stability and therefore well control aspects.Within drilling, it is common to express pressures as gradients. With this concept, the hydrostaticpressure can be given as equivalent density which is independent of the depth and thus makes itscomprehension and correlations of various concepts easier. On the other hand, when gradientsare applied, it has to be always kept in mind that they are referred to a specific depth. Knowingthis reference depth is essential to compute back the corresponding downhole pressures. Withindrilling engineering, the drilling floor or rotary table (RKB) is the most often used reference depth.Geologists and geophysicists generally prefer to use their data in reference to ground floor or meansea level (MSL).To correct data expressed in RKB to MSL or do the reverse, following equations can be applied:CHAPTER 3 Page 39
  48. 48. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringCorrect RKB to MSL reference: D dM SL = dRKB . (3.1) D − hRKBConvert MSL data to RKB: D − hRKB dRKB = dM SL . (3.2) DAnother common problem is when datareferenced to one RKB (e.g. rig usedto drill the wildcat well) has to be ap-plied for further/later calculations (e.g.drilling development wells from a pro-duction platform). Here the data haveto be corrected from RKB1 to RKB2 .Correct from RKB1 to RKB2 : D − ∆h dRKB2 = dRKB1 . (3.3) Figure 3.1: Pore pressure and fracture gradient profile D for different offshore rigs (semisub and jackup)where: D [m or ft] ... total depth of point of interest in reference to RKB hRKB [m or ft] ... height of RKB above MSL ∆h [m or ft] ... difference of elevation of RKB1 to RKB2CHAPTER 3 Page 40
  49. 49. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering3.1 Geology PredictionNormally when a well is to be drilled, the drilling en-gineer is supplied from the geology department (or thegeologist within the project team) with a sequence ofpredicted subsurface formations, their characteristicsand markers, as well as knowledge about where specialcare has to be taken. Geologists draw this informationfrom studying the local geology (deposition history),seismic mappings (2D or 3D surveys) and perform wellto well correlations (geological maps). Whenever newinformation is gained (due to drilling and evaluationof a new well or further geophysical measurements)these maps are updated. A typical geological profilesupplied to the drilling engineer is sketched with figure3.2 which is based on seismic profiles (figure 3.3).3.2 Pore pressure PredictionTo understand the local subsurface pressure regimes,the geologic processes along with the depositional his-tory and tectonic abnormalities have to be studied.When the well is located within shallow sediments thatwere laid down slowly within a deltaic depositional en-vironment, the subsurface formation pressures can beassumed to be hydrostatic. Figure 3.2: Typical geological profile to plan a well3.2.1 Hydrostatic PressureBy definition, a hydrostatic pressure is developed dueto the own weight of a fluid at a certain depth. Thisrelationship is expressed as: p = ρ.g.h = 9.81.ρ.h (3.4)Or in field units: p = 0.052.ρf l .D (3.5)where:CHAPTER 3 Page 41
  50. 50. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering ρf l [ppg] ... density of the fluid causing hydrostatic pressure ρ [kg/m3 ] ... average fluid density D [ft] ... depth at which hydrostatic pressure occurs (TVD) h [m] ... vertical height of column of liquid p [psi] ... hydrostatic pressure g [m/s2 ] ... acceleration due to gravity Figure 3.3: Seismic record to determine the subsurface structureWhen the weight of the solid particles buried are supported by grain-to-grain contacts and the withthe particles buried water has free hydraulic contact to the surface, the formation is consideredas hydrostatically pressured. As it can be seen, the formation pressure, when hydrostaticallypressured, depends only on the density of the formation fluid (usually in the range of 1.00 [g/cm3 ]to 1.08 [g/cm3 ], see table 3.4) and the depth in TVD.CHAPTER 3 Page 42
  51. 51. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 3.4: Water density in relation to salinity at 20 ◦ CWhen the burial depth increases, the overlaying pressure (overburden stress) increases. Thisdecreases the pore space between the grains and thus the porosity of the formation.The overburden stress can be calculatedassuming an average bulk density ρbof the overlaying formations applyingequation 3.6: D σob = ρb .g.dD (3.6) 0The average bulk density is normallyfound by integration of the density logreadings. When density logs were notrun (e.g. at shallow formations), soniclog correlation methods, together withlithology and mineralogical evaluationsare applied to determine ρbDuring burial of the sediments, forma-tion water is constantly expelled due tothe reduction of formation porosity, seefig 3.6.As long as formation water can be ex-pelled, the formations are hydrostatic Figure 3.5: Porosity profile with increasing depth(or normally) pressured.When drilling a well, formations are often encountered that are under a different pressure regime.These formations are named to be “abnormally pressured”. Abnormal pressures can be positive(actual formation pressures are higher than hydrostatic pressure) or negative (actual formationpressures are lower than hydrostatic pressure). Sometimes the term “subnormal pressure” is usedCHAPTER 3 Page 43
  52. 52. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineeringwhen the formation pressure is lower than the hydrostatic one. Figure 3.6: Volume of fluid expelled during compaction of an argillaceous sedimentSome mechanisms that lead to abnormally pressured formations are: 1. Compaction effects, 2. Aquathermal expansion, 3. Diagenetic effects, 4. Differential density effects (Osmosis), 5. Fluid migration effects, 6. Evaporite Deposits, 7. Organic matter transformation, 8. Tectonics, 9. Connection to depleted reservoirs, 10. Others.From the various effects mentioned above, the compaction one is considered to be often thegoverning one and hence is discussed in more detail below.As mentioned above, while burying of the sediments, formation water is expelled with increasingdepth and temperatures due to reduction in pore space and diagenesis of the rock materials. Aslong as the permeability and the effective porosity of the rock is high enough so that the formationwater can escape as quickly as the natural compaction takes place, the formations are normallypressured. The (vertical) pressures acting inside formations can be modelled as: σob = σz + p (3.7)where:CHAPTER 3 Page 44
  53. 53. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering σob [psi] ... overburden stress σz [psi] ... vertical stress supported by the grain-to-grain connections p [psi] ... formation pore pressureWhen the formation water can not escape as quickly as the pore space is reduced, it is trappedinside the formations. In this scenario, the increasing overburden stress will pressurize the forma-tion water and the formation will become abnormally pressured. In this situation, the porosityof the formation will not follow the natural compaction trend (porosity at abnormally pressuredformations will be higher than at normally pressured ones). Along with the higher porosity, thebulk density as well as the formation resistivity will be lower at abnormally pressured formations.These circumstances are often applied to detect and estimate the abnormal formation pressures.The bulk density [ppg] of a formation is estimated by equation 3.8: ρb = ρg .(1 − φ) + ρf l .φ (3.8)where: ρg [ppg] ... grain density ρf l [ppg] ... formation fluid density φ [1] ... total porosity of the formation Figure 3.7: Average bulk density change in sedimentsAs it can be seen from figure 3.7, an average bulk density of 2.31 [g/cm3] (equal to 1 [psi/ft]) canbe assumed for deep wells as approximation.CHAPTER 3 Page 45
  54. 54. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling EngineeringIn areas of frequent drilling activities or where formation evaluation is carried out extensively, thenatural trend of bulk density change with depth is known.For shale formations that follow the natural compaction trend, it has been observed that theporosity change with depth can be described using below relationship: φ = φo .e−K.Ds (3.9)where: φ [1] ... porosity at depth of interest φo [1] ... porosity at the surface K [ft−1 ] ... porosity decline constant, specific for each location Ds [ft] ... depth of interest (TVD)When equation 3.9 is substituted in equation 3.8 and equation 3.6 and after integration theoverburden stress profile is found for an offshore well as: 0.052 σob = 0.052.ρsw .Dw + 0.052.ρg .Dg − .(ρg − ρf l ).φo .(1 − e−K.Dg ) (3.10) Kwhere: Dg [ft] ... depth of sediment from sea bottom ρsw [ppg] ... sea water densityThus when the overburden stress profile is known, the depth where the abnormal pressure startsis given and with the shape of the profile, it is determined at which depth the matrix stress isequal to the matrix stress at the abnormal formation pressure (“matrix point”), see figure 3.8.Now, the normal formation pressure at the matrix point is calculated by equation 3.5 and thematrix stress with equation 3.7. Applying the assumption that the matrix stress is equal at thematrix point with the one at the abnormal formation pressure, and when the overburden stressat the abnormal formation pressure is calculated with equation 3.10, the abnormal formationpressure is found when rearranging equation 3.7.The actual measurement of formation pore pressure is very expensive and possible only after theformations have been drilled. In this respect, pore pressures have to be estimated before drilling toproperly plan the mud weights, casing setting depths, casing design, etc. as well as being closelymonitored during drilling.CHAPTER 3 Page 46
  55. 55. Curtin University of Technology Master of Petroleum EngineeringDepartment of Petroleum Engineering Drilling Engineering Figure 3.8: Overburden stress profile for abnormal formation pressureTo estimate the pore pressure and most important, define where abnormal pore pressures are to beexpected, porosity logs and seismic measurements are applied most often. As mentioned before,shale formations tend to follow a defined porosity reduction trend with increasing depth. Whenthis trend is interrupted, abnormally pressured formations are to be expected. To knowledge ofits depths are importment since they may lead to a necessary setting of casing and weighting upthe mud system. The amount of how much the mud weight has to be increased depends on theamount of abnormal pressure expected and the contingency of the well.CHAPTER 3 Page 47

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