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

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Presentation on theme: "1 PETE 411 Well Drilling Lesson 14 Jet Bit Nozzle Size Selection."— Presentation transcript:

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

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

4 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 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 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 to lift the drill cuttings out of the hole. - This requirement sets the minimum fluid circulation rate.  2. The surface pump pressure must stay within the maximum allowable pressure rating of the pump and the surface equipment.

7 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 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 9 Maximum Bit Hydraulic Horsepower The hydraulic horsepower at the bit is maximized when is maximized. where may be called the parasitic pressure loss in the system (friction).

10 10 Maximum Bit Hydraulic Horsepower In general, where The parasitic pressure loss in the system,

11 11 Maximum Bit Hydraulic Horsepower

12 12 Maximum Bit Hydraulic Horsepower

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

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

15 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 16 Maximum Jet Impact Force The jet impact force is given by Eq. 4.37:

17 17 Maximum Jet Impact Force But parasitic pressure drop,

18 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 19 Maximum Jet Impact Force - Examples -

20 20 Nozzle Size Selection - Graphical Approach -

21 21

22 22

23 23 1. Show opt. hydraulic path 2. Plot  p d vs q 3. From Plot, determine optimum q and  p d 4. Calculate 5. Calculate Total Nozzle Area: (TFA) 6. Calculate Nozzle Diameter With 3 nozzles:

24 24 Example 4.31 Determine the proper pump operating conditions and bit nozzle sizes for max. jet impact force for the next bit run. Current nozzle sizes: 3 EA 12/32” Mud Density = 9.6 lbm.gal At 485 gal/min, P pump = 2,800 psi At 247 gal/min, P pump = 900 psi

25 25 Example 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

26 26 Example (a), 485 gpm Calculate pressure drop through bit nozzles:

27 27 Example (b), 247 gpm Plot these two points in Fig (q 1, p 1 ) = (485, 906) (q 2, p 2 ) = (247, 409)

28 28

29 29 Example cont’d 2. For optimum hydraulics: 3 2 1

30 30 Example From graph, optimum point is at

31 31

32 32 Example 4.32 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: Well Planning

33 33 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

34 34 Example 4.32 Surface Equipment: Equivalent to 340 ft. of drillpipe Hole Size: in. washed out to in in.-I.D. casing Minimum Annular Velocity: 120 ft/min

35 35 Mud Program Mud Plastic Yield Depth Density Viscosity Point (ft) (lbm/gal) (cp) (lbf/100 sq ft) 5, , , , ,

36 36 Solution The path of optimum hydraulics is as follows: Interval 1

37 37 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,

38 38 Solution Interval 3 For a minimum annular velocity of 120 ft/min opposite the drillpipe,

39 39 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:

40 40 Table 5, , ,004 7, ,120 8, , * 1,703 9, , * 111* 2,084 * Laminar flow pattern indicated by Hedstrom number criteria.

41 41 Table The proper pump operating conditions and nozzle areas, are as follows: 5, ,245 2, , ,245 2, , ,245 2, , ,245 2, , ,370 2,

42 42 Table The first three columns were read directly from Fig (depth, flow rate and  p d ) Col. 4 (  p b ) was obtained by subtracting shown in Col.3 from the maximum pump pressure of 3,423 psi. Col.5 (A tot ) was obtained using Eq. 4.85

43 43

44 44 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.

45 45 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.

46 46 Figure 4.40B - Velocity profile for laminar flow pattern when closed pipe is being run into hole


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