PETE 411 Well Drilling

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
ReadApplied Drilling Engineering, to p.162
HW 7On the Web - due 10-09-02
Quiz A Thursday, Oct. 10, 7 - 9 p.m. Rm.
101Closed Book1 Equation sheet allowed, 8 1/2x
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 HorsepowerExamples - contd

• 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
(No Transcript)
22
(No Transcript)
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
Example 4.31 - 1(a), 485 gpm

• Calculate pressure drop through bit nozzles

27
Example 4.31 - 1(b), 247 gpm
(q1, p1) (485, 906) (q2, p2) (247, 409)
Plot these two points in Fig. 4.36
28
(No Transcript)
29
Example 4.31 - contd
3
2

• 2. For optimum hydraulics

1
30
Example 4.31

• 3. From graph, optimum point is at

31
(No Transcript)
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 9.857 in. washed out to 10.05 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)

5,000 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
36
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

• 5,000 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.

41
Table

• The proper pump operating conditions and nozzle
  areas, are as follows

42
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

43
(No Transcript)
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