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PETE 411 Well Drilling

PETE 411 Well Drilling. Lesson 14 Jet Bit Nozzle Size Selection. 14. Jet Bit Nozzle Size Selection. Nozzle Size Selection for Optimum Bit Hydraulics: Max. Nozzle Velocity Max. Bit Hydraulic Horsepower Max. Jet Impact Force Graphical Analysis Surge Pressure due to Pipe Movement.

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PETE 411 Well Drilling

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  1. PETE 411Well Drilling Lesson 14Jet Bit Nozzle Size Selection

  2. 14. Jet Bit Nozzle Size Selection • Nozzle Size Selection for Optimum Bit Hydraulics: • Max. Nozzle Velocity • Max. Bit Hydraulic Horsepower • Max. Jet Impact Force • Graphical Analysis • Surge Pressure due to Pipe Movement

  3. Read:Applied Drilling Engineering, to p.162 HW #7:On the Web - due 10-09-02 Quiz AThursday, Oct. 10, 7 - 9 p.m. Rm. 101Closed Book1 Equation sheet allowed, 8 1/2”x 11” (both sides) { Quiz A_2001 is on the web }

  4. Jet Bit Nozzle Size Selection Proper bottom-hole cleaning will eliminate excessive regrinding of drilled solids, and will result in improved penetration rates • Bottom-hole cleaning efficiency • is achieved through proper selection of bit nozzle sizes

  5. Jet Bit Nozzle Size Selection- Optimization - Through nozzle size selection, optimization may be based on maximizing one of the following: Bit Nozzle Velocity Bit Hydraulic Horsepower Jet impact force • There is no general agreement on which of • these three parameters should be maximized.

  6. Maximum Nozzle Velocity Nozzle velocity may be maximized consistent with the following two constraints: 1.The annular fluid velocity needs to be high enough tolift the drill cuttingsout of the hole. - This requirement sets the minimumfluid circulation rate. 2.The surface pump pressure must stay within the maximum allowable pressure rating of the pump and the surface equipment.

  7. Maximum Nozzle Velocity From Eq. (4.31) i.e. so the bit pressure drop should be maximized in order to obtain the maximum nozzle velocity

  8. Maximum Nozzle Velocity This (maximization) will be achieved when the surface pressure is maximized and the frictional pressure loss everywhere is minimized, i.e., when the flow rate is minimized.

  9. Maximum Bit Hydraulic Horsepower The hydraulic horsepower at the bit is maximized when is maximized. where may be called the parasiticpressure loss in the system (friction).

  10. Maximum Bit Hydraulic Horsepower The parasiticpressure loss in the system, In general, where

  11. Maximum Bit Hydraulic Horsepower

  12. Maximum Bit Hydraulic Horsepower

  13. Maximum Bit Hydraulic Horsepower- Examples - In turbulent flow, m = 1.75

  14. Maximum Bit Hydraulic HorsepowerExamples - cont’d In laminar flow, for Newtonian fluids, m = 1

  15. Maximum Bit Hydraulic Horsepower In general, the hydraulic horsepower is not optimized at all times It is usually more convenient to select a pump liner size that will be suitable for the entire well Note that at no time should the flow rate be allowed to drop below the minimum required for proper cuttings removal

  16. Maximum Jet Impact Force The jet impact force is given by Eq. 4.37:

  17. Maximum Jet Impact Force But parasitic pressure drop,

  18. Maximum Jet Impact Force Upon differentiating, setting the first derivative to zero, and solving the resulting quadratic equation, it may be seen that the impact force is maximized when,

  19. Maximum Jet Impact Force- Examples -

  20. Nozzle Size Selection- Graphical Approach -

  21. 1. Show opt. hydraulic path 2. Plot Dpd vs q 3. From Plot, determine optimum q and Dpd 4. Calculate 5. Calculate Total Nozzle Area: (TFA) 6. Calculate Nozzle Diameter With 3 nozzles:

  22. Example 4.31 Current nozzle sizes: 3 EA 12/32” Mud Density = 9.6 lbm.gal At 485 gal/min, Ppump = 2,800 psi At 247 gal/min, Ppump = 900 psi Determine the proper pump operating conditions and bit nozzle sizes for max. jet impact force for the next bit run.

  23. Example 4.31 - given data: Max pump HP (Mech.) = 1,250 hp Pump Efficiency = 0.91 Max pump pressure = 3,000 psig Minimum flow rate to lift cuttings = 225 gal/min

  24. Example 4.31 - 1(a), 485 gpm Calculate pressure drop through bit nozzles:

  25. Example 4.31 - 1(b), 247 gpm (q1, p1) = (485, 906) (q2, p2) = (247, 409) Plot these two points in Fig. 4.36

  26. 3 2 Example 4.31 - cont’d 1 2. For optimum hydraulics:

  27. Example 4.31 3. From graph, optimum point is at

  28. Example 4.32 Well Planning It is desired to estimate the proper pump operating conditions and bit nozzle sizes for maximum bit horsepower at 1,000-ft increments for an interval of the well between surface casing at 4,000 ft and intermediate casing at 9,000 ft. The well plan calls for the following conditions:

  29. Example 4.32 Pump: 3,423 psi maximum surface pressure 1,600 hp maximum input 0.85 pump efficiency Drillstring: 4.5-in., 16.6-lbm/ft drillpipe (3.826-in. I.D.) 600 ft of 7.5-in.-O.D. x 2.75-in.- I.D. drill collars

  30. Example 4.32 Surface Equipment: Equivalent to 340 ft. of drillpipe Hole Size: 9.857 in. washed out to 10.05 in. 10.05-in.-I.D. casing Minimum Annular Velocity: 120 ft/min

  31. Mud Program 5,000 9.5 15 5 6,000 9.5 15 5 7,000 9.5 15 5 8,000 12.0 25 9 9,000 13.0 30 12 Mud Plastic Yield Depth Density Viscosity Point (ft) (lbm/gal) (cp) (lbf/100 sq ft)

  32. Solution The path of optimum hydraulics is as follows: Interval 1

  33. Solution Interval 2 Since measured pump pressure data are not available and a simplified solution technique is desired, a theoretical m value of 1.75 is used. For maximum bit horsepower,

  34. Solution Interval 3 For a minimum annular velocity of 120 ft/min opposite the drillpipe,

  35. Table The frictional pressure loss in other sections is computed following a procedure similar to that outlined above for the sections of drillpipe. The entire procedure then can be repeated to determine the total parasitic losses at depths of 6,000, 7,000, 8,000 and 9,000 ft. The results of these computations are summarized in the following table:

  36. Table 5,000 38 490 320 20 20 888 6,000 38 601 320 20 25 1,004 7,000 38 713 320 20 29 1,120 8,000 51 1,116 433 28 75* 1,703 9,000 57 1,407 482 27* 111* 2,084 * Laminar flow pattern indicated by Hedstrom number criteria.

  37. 5,000 600 1,245 2,178 0.380 6,000 570 1,245 2,178 0.361 7,000 533 1,245 2,178 0.338 8,000 420 1,245 2,178 0.299 9,000 395 1,370 2,053 0.302 Table The proper pump operating conditions and nozzle areas, are as follows:

  38. Table The first three columns were read directly from Fig. 4.37. (depth, flow rate and Dpd) Col. 4 (Dpb) was obtained by subtracting shown in Col.3 from the maximum pump pressure of 3,423 psi. Col.5 (Atot) was obtained using Eq. 4.85

  39. Surge Pressure due to Pipe Movement When a string of pipe is being lowered into the wellbore, drilling fluid is being displaced and forced out of the wellbore. The pressure required to force the displaced fluid out of the wellbore is called the surge pressure.

  40. Surge Pressure due to Pipe Movement An excessively high surge pressure can result in breakdown of a formation. When pipe is being withdrawn a similar reduction is pressure is experienced. This is called a swab pressure, and may be high enough to suck fluids into the wellbore, resulting in a kick.

  41. Figure 4.40B - Velocity profile for laminar flow pattern when closed pipe is being run into hole

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