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Lesson 3 Drilling Equipment, Costs, Problems

PETE 661 Drilling Engineering www.pe.tamu.edu/schubert/public_html/PETE%20661/Lessons/Exam%20I/3.%20Drilling%. Lesson 3 Drilling Equipment, Costs, Problems. Drilling Equipment. Rig Pumps Solids Control Equipment The Rotary System The Swivel The Well Control System Offshore Drilling.

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Lesson 3 Drilling Equipment, Costs, Problems

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  1. PETE 661Drilling Engineeringwww.pe.tamu.edu/schubert/public_html/PETE%20661/Lessons/Exam%20I/3.%20Drilling% Lesson 3 Drilling Equipment, Costs, Problems

  2. Drilling Equipment • Rig Pumps • Solids Control Equipment • The Rotary System • The Swivel • The Well Control System • Offshore Drilling

  3. Assignments: READ: ADE all of Ch. 1 HW #2:ADE 1.12, 1.13, 1.14, 1.24 Due Friday, September 10, 2004 NOTE: Answers in book are not always correct…

  4. Schematic of Rig Circulating System for liquid drilling fluid

  5. Example 1.3 Compute the pump factor in units of barrels per stroke for a double-acting duplex pump having 6.5-inch liners, 2.5 inch rods, 18-inch strokes and a volumetric efficiency of 90%. Eq. 1.10

  6. Recall: There are 231 in.3 inan U. S. gallon and 42 U.S. gallons in a U.S. barrel. Thus converting to the desired field units yields: 1991 in.3/stroke * gal/231 in.3 * bbl/42 gal. = 0.2052 bbl/stroke. Thus: Pump Factor = 0.2052 bbl/stroke

  7. Pump Factor = 3 * p/4 dL2 LS EV/(231 * 42)

  8. Example: Pump Factor for Triplex Pump

  9. Example: Pump Rate = Pump Factor * Strokes/min = 0.09442 = 7.554 bbl/min = 317.3 gal/min

  10. Hydrocyclone • desander • desilter * No moving parts * Low cost * Pressure drop * Diameter

  11. Decanting Centrifuge Use?

  12. Fig. 1.33 Schematic of Rotary System

  13. Fig. 1.34 Cutaway View of Swivel * Seals * Bearings ROTATING

  14. PIN BOX TJ Shoulder Fig. 1.38 Cutaway View and Dimensions for Example Tool Joint

  15. Fig. 1.39 Stabilizer * Keeps pipe in center of hole * Aids in drilling straight hole * Prolongs bit life

  16. Fig. 1.41 Kick Detection During Drilling Operations 3 GAIN IN PIT VOLUME EQUAL TO KICK VOLUME KICK 2 1

  17. Fig. 1.46 Remote Control Panel for operating Blowout Preventers CHOKE What to do if KICK occurs?

  18. DP TJ DC OH Press Fig. 1.44 Annular Blowout Preventer

  19. Ram Blowout Preventer

  20. SHEAR / BLIND RAM ASSEMBLY Ram Blowout Preventer - cont’d

  21. Fig. 1.51 High-Pressure Circulating System for Well Control Operations Kick Keep BHP const.

  22. Fig. 1.58 Schematic of Equipment for Marine Drilling

  23. Fig. 1.63 Subsea Equipment Installation Procedure

  24. Typical Casing Strings Water Level Depth Below ML Seafloor Conductor pile 36” 30” 200’ Conductor Casing 26” 20” 1000’ Surface Casing 17 1/2” 13 3/8”4000’ Hole Csg. Depth

  25. Some Typical Casing Strings DepthBelow ML Conductor pile 36” 30” 200’ Conductor Casing 26” 20” 1000’ Surface Casing 17 1/2” 13 3/8”4000’ Hole Csg. Depth

  26. What is the capacity of 10,000 ft of 5” OD, 19.50 lb/ft drillpipe? Capacity = Area * Length Area = p/4 d2 = p/4 * 4.2762 = 14.36 in2 Length = 10,000 ft = 120,000 in Capacity = 14.36 *120,000 in3 /(231*42 in3 /bbl) Capacity = 177.6 bbls

  27. Drilling Cost and Drilling Rate • The AFE • Drilling Cost and Bit Change • Factors Affecting Drilling Rate • Bit Weight, Rotary Speed • Bottom-hole Cleaning • Mud Properties, Solids Content • Hydrostatics

  28. Before getting approval to drill a well the Drilling Engineer must prepare an AFE- a detailed cost estimate for the well DRY COMPLETED HOLE INTANGIBLE COSTS $ $ TANGIBLE COSTS $ $ TOTAL COST $ $

  29. EXPENDITURE DRY HOLE COMPLETED (24.5 DAYS) (32.5 DAYS) AUTHORIZATION FOR EXPENDITURE (AFE) INTANGIBLE COSTS LOCATION PREPARATION 30,000 65,000 DRILLING RIG AND TOOLS 298,185 366,613 DRILLING FLUIDS 113,543 116,976 RENTAL EQUIPMENT 77,896 133,785 CEMENTING 49,535 54,369 SUPPORT SERVICES 152,285 275,648 TRANSPORTATION 70,200 83,400 SUPERVISION AND ADMIN. 23,282 30,791 SUB-TOTAL 814,928 1,126,581 TANGIBLE COSTS TUBULAR EQUIPMENT 406,101 846,529 WELL HEAD EQUIPMENT 16,864 156,201 COMPLETION EQUIPMENT 0 15,717 SUB-TOTAL 422,965 1,018,447 SUB-TOTAL 1,237,893 2,145,028 + CONTINGENCY (15% ??) 1,423,577 2,466,782

  30. Drilling Cost vs. Time DEPTH ft TD DAYS or DOLLARS

  31. The Drilling Engineer • Examples of routine rig operations • drilling fluid treatment • pump operation • bit selection • problems during the drilling process

  32. The Drilling Cost Equation: Eq. 1.16 Cf= drilling cost, $/ft Cb= cost of bit, $/bit Cr= fixed operating cost of rig, $/hr tb= total rotating time, hrs tc= total non-rotating time, hrs tt= trip time (round trip), hrs = footage drilled with bit, ft

  33. Example 1.5 A recommended bit program is being prepared for a new well using bit performance records from nearby wells. Drilling performance records for three bits are shown for a thick limestone formation at 9,000 ft. Determine which bit gives the lowest drilling cost if the operating cost of the rig is $400/hr, the trip time is 7 hours, and connection time is 1 minute per connection.

  34. Example 1.5 cont’d Assume that each of the bits was operated at near the minimum cost per foot attainable for that bit. Mean Bit Rotating Connection Penetration Cost Time Time Rate Bit ($) (hours)(hours)(ft/hr) A 800 14.8 0.1 13.8 B 4,900 57.7 0.4 12.6 C 4,500 95.8 0.5 10.2 Which bit would you select?

  35. Solution: The cost per foot drilled for each bit type can be computed using Eq. 1.16. For Bit A, the cost per foot is

  36. Solution, cont’d Bit A: $46.81 /ft Bit B: $42.56 /ft Bit C: $46.89 /ft The lowest drilling cost was obtained using Bit B. - Highest bit cost …but - longest life and intermediate ROP...

  37. Drilling Costs • Tend to increase exponentially with depth. Thus, when curve-fitting drilling cost data, it is often convenient to assume a relationship between total well cost, C, and depth, D, given by C = aebD …………………..(1.17)

  38. Fig. 1-65. Least-square curve fit of 1978 completed well costs for wells below 7,500 ft in the south Louisiana area.

  39. Drilling Time cont’d Plotting depth vs. drilling time from past drilling operations: A. Allows more accurate prediction of time and cost for drilling a new well B. Is used in evaluating new drilling procedures (designed to reduce drilling time to a given depth).

  40. Cost per ft for one entire bit run Minimum Cost

  41. An increase in TORQUE may indicate that a bit should be pulled. Experience often dictates when to pull bit (footage or hours).

  42. Factors that affect Penetration Rate Variables: Drill bit Bit weight Rotary speed Bottom-hole cleaning Mud properties Fixed Factors: • Rock hardness • Formation pore pressure

  43. Bit Selection is based on Past bit records Geologic predictions of lithology Drilling costs in $/bit Drilling cost in $/ft

  44. Bit Weight and Rotary Speed • Increasing bit weight and rotary speed boosts drilling rate • These increases accelerate bit wear • Field tests show that drilling rate increases more or less in direct proportion to bit weight

  45. 40,000 lbf Consider 10” hole (don’t overdo!!) Drilling Rate, ft/hr Bit Weight x 1,000 lb/in

  46. Don’t overdo! Casing wear, bit life ... Drilling Rate, ft/hr Rotary Speed, RPM

  47. EFFECT OF BACK PRESSURE 0 - 5,000 psi Drilling Rate, ft/hr Hydrostatic Pressure, 1,000’s of psi

  48. EFFECT OF DRILLING FLUID water vs. air Depth, ft Rotating Time, hours

  49. EFFECT OF SOLIDS IN THE MUD

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