iii

contents▼▼▼

Figures v

Tables vii

Foreword ix

Acknowledgments xi

Units of Measurement xii

Introduction 1

Well Planning 5

Bits 9Bit Selection 9Bit Design 11How Bits Drill 12Roller Cone Bits 13Natural Diamond Bits 19Fixed-Cutter Bits 21Hybrid Bits 23Special Purpose Bits 24Bit Classification 26Dull Bit Evaluation 33

Drilling Performance Records 45

Weight on Bit and Rotary Speed 51

Special Considerations 57

Rate of Penetration Control 65

Drilling Mud 71Mud Characteristics that Affect ROP 73

Air or Gas Drilling 83Air Drilling Equipment 84

Bit Hydraulics 91Hydraulics Calculations 94

Formation Properties 101

New Technology 107

Glossary 111

Review Questions 131

Answers to Review Questions 137

iv

v

Figures ▼▼▼

1. IADC footage drilling bid-contract 2 2. Factors affecting penetration rate 4 3. “The learning curve” for drilling offshore development wells 5 4. A recommended bit or well program 9 5. A rig site integrated drilling system for measurement-while-drilling

(MWD) 10 6. Bits 11 7. Drilling action of bits 12 8. Combination journal and ball bearings in a roller cone bit showing

the journal angle 13 9. The rows of cutters on one cone intermesh with the cutters on the

other cones. 14 10. Cone offset. Each cone rotates on its own axis. 14 11. Soft-formation milled-tooth bit 15 12. Tungsten carbide inserts 16 13. Soft-formation insert bit 17 14. Medium-formation insert bit 17 15. Hard-formation insert bit 17 16. Flat tungsten carbide gauge row inserts 18 17. Four parts of a diamond bit 19 18. Natural diamond bit showing watercourses 20 19. A polycrystalline diamond compact (PDC) 21 20. Six-blade PDC bit 21 21. Detail of PDCs set in blade 21 22. Combination TSP and natural diamond bit 22 23. Diamond-impregnated pad set in gauge surface of bit body 23 24. Diamond-impregnated stud backup to a PDC cutter 23 25. Ream-while-drilling bits 24 26. Air hammer bits 25 27. Special purpose bits 25 28. Steerable directional drilling bit 25 29. Industry accepted PDC bit profiles 30 30. Cutter wear measurement 34 31. Gauge ring measurement using the two-thirds rule 36 32. An evenly worn dull bit, which is in gauge. 37 33. Cone dragging or skidding caused by a locked cone 37 34. Cracked cone 38 35. Cone erosion 38 36. Off-center wear 39 37. Center coring 39 38. Broken inserts 40 39. Heat checking (small cracks) on insert cutters 41 40. Steel tooth breakage 41 41. Self-sharpened tooth wear 42 42. Bit gauge wear or rounding 43 43. Undergauge hole caused by bit gauge wear or rounding 43

vi

44. Bit record form 46 45. Rig site daily drilling report form 47 46. Office drilling report 48 47. Computerized drilling information network 49 48. Effect of rotary RPM on drilling rate 54 49. Dogleg produced by reduced weight 57 50. Rotary drive power required at various torque loads and RPM 58 51. Tension and compression on drill string during rotation 59 52. Cut-away drawing of a downhole motor powered by drilling mud 60 53. Turbodrill design 60 54. Drilling assembly using a downhole motor and a bent sub 61 55. Horizontal turn radii 61 56. Short radius articulated downhole motor equipped with PDC bit 62 57. Adjustable kick-off (AKO) downhole motor assembly can be used for

drilling vertical to short-radius horizontal holes. 63 58. GeolographTM chart. Note drilling break at 4,915 feet where average

ROP decreases from average 6.5 min/ft to 3.5 min/ft. 66 59. Pick-up and slack-off chart 68 60. Functions of drilling mud 72 61. Daily drilling mud report (water base mud) from previously drilled

well. Computerized report as printed out at rig site by mud engineer. 74

62. Effect of mud weight on drilling rate 78 63. Effect of mud solids on drilling rate 80 64. Buildup of filter (mud) cake on borehole walls. Solid particles in the

drilling mud plaster the wall of the hole forming an impermeable barrier. 81

65. Skid-mounted air compressors for air drilling 84 66. Air drilled cuttings blown through a blooey line with flare set to ignite

any gas encountered 85 67. Air hammer (percussion) drilling tool 86 68. Arrangement of equipment for air drilling 87 69. Blowout preventers and lines for air drilling 88 70. Hydraulic power losses in rig mud system 92 71. Factors affecting rig hydraulics 94 72. Overburden (formation pressure increases with depth) 101 73. Drilling through alternating hard and soft zones can produce offset

ledges. 102 74. In formations with dip of less than 45 degrees, the bit tends to drift or

walk up-dip. 103 75. Faster drilling may be achieved if the bit is allowed to drift into the

target area. 103 76. In formations with dip of 45 degrees or more, the bit tends to drift

(slide) down-dip along bedding planes. 104 77. Single-cone bit for drilling small diameter holes 109

vii

tables ▼▼▼

1. Steel tooth bit specifications relative to formation type 15 2. Insert bit specifications relative to formation type 18 3. IADC roller cone bit classification chart 27 4. IADC classification chart for PDC bits 28 5. IADC classification chart for TSP and natural diamond bits

29 6. Tooth bit comparison chart 31–32 7. IADC dull grading chart 35 8. Typical weights and RPMs for roller cone bits 52–53 9. Typical specifications and operating guidelines for natural diamond

bits run on downhole mud motor 55 10. Sample drill-off test in sandy shale 67 11. Mud density conversion table 76 12. Mud-weight adjustment with barite or water 77 13. Approximate rate of circulation in ft3/min in 8¾-inch hole

(m3/ min in 222-mm hole) with 4½- inch (114-mm) drill pipe with volumes to produce lifting power equivalent to a velocity of 3,000 ft3/min (915 m3/min) 89

14. Pressure losses as illustrated in figure 70 with mud pumping rate of 400 gal/min at 2,000 psi (1.5 m3/min at 13,791 kPa) 93

15. Determining pressure loss through drill stem bore 96 15A. Determining pressure loss through drill stem bore (metric) 97 16. Determining pressure drop in psi across bit nozzle 98 16A. Determining pressure drop in kPa across bit nozzle (metric) 99