1. Lesson 14 Jet Bit Nozzle Size Selection
PETE 411 Well Drilling
Lesson 14 Jet 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
Quiz A Thursday, Oct. 10, p.m. Rm. 101 Closed Book 1 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 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. 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 parasitic pressure loss in the system (friction).

10. Maximum Bit Hydraulic Horsepower
The parasitic pressure 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 Horsepower Examples - 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 -

23. 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:

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, Ppump = 2,800 psi
At 247 gal/min, Ppump = 900 psi

25. 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

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

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

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

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

32. 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:

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

35. Mud Program Mud Plastic Yield Depth Density Viscosity Point
(ft) (lbm/gal) (cp) (lbf/100 sq ft) 5, 6, 7, 8, 9,

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

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

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. Table 5,
6, ,004
7, ,120
8, , * 1,703
9, , * 111* 2,084
* Laminar flow pattern indicated by Hedstrom number criteria.

41. The proper pump operating conditions and nozzle areas, are as follows:
Table
The proper pump operating conditions and nozzle areas, are as follows:
5, , ,
6, , ,
7, , ,
8, , ,
9, , ,

42. Table
The first three columns were read directly from Fig (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

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