14 Jet Bit Nozzle Size Selection
Transcript of 14 Jet Bit Nozzle Size Selection
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PETE 411
Well Drilling
Lesson 14
Jet Bit Nozzle Size Selection
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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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Read:Applied Drilling Engineering, to p.162
Quiz AThursday, Oct. 10, 7 - 9 p.m. Rm. 101
Closed Book1 Equation sheet allowed, 8 1/2 x 11 (both sides)
HW #7:On the Web - due 10-09-02
{ Quiz A_2001 is on the web }
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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
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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 ofthese three parameters should be maximized.
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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 themaximum allowable pressure rating of the
pump and the surface equipment.
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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
4
bdn
10*074.8PCv
=
bn Pv
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Maximum Nozzle Velocity
This (maximization) will be achieved when
the surface pressure is maximized and thefrictional pressure loss everywhere is
minimized, i.e., when the flow rate is
minimized.
pressure.surfaceallowablemaximumtheand
ratencirculatiominimumtheat
satisfied,areabove2&1whenmaximizedisvn
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Maximum Bit Hydraulic Horsepower
The hydraulic horsepower at the bit is
maximized when is maximized.q)p( bit
dpumpbit ppp =
where may be called the parasiticpressure
loss in the system (friction).dp
bitdpump ppp +=
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Maximum Bit Hydraulic Horsepower
.turbulentisflowtheif
cqpppppp 75.1dpadcadcdpsd =++++=
In general, wherem
d cqp = 2m0
The parasitic pressure loss in the system,
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Maximum Bit Hydraulic Horsepower
0)1(pwhen0
17141714
pump
1
=+=
=
=
+
mHbit
m
pumpbitHbit
qmcdq
dP
cqqpqpP
dpumpbit ppp =m
d cqp =
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Maximum Bit Hydraulic Horsepower
whenmaximumis
1
1
pwhen.,.
)1(pwhen.,.
d
pump
Hbit
pump
d
P
pmei
pmei
+
=
+=
pumpd p
m
p
+
=
1
1
0)1(ppump =+ m
qmc
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Maximum Bit Hydraulic Horsepower
- Examples -
In turbulent flow, m = 1.75
pumpbit
pump
pumpd
pof%64p
pof36%
%100*p
175.1
1p
=
=
+=
pdp
1m
1p
+
=
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In laminar flow, for Newtonian fluids, m = 1
pumpb
pump
pumpd
pof%50p
pof50%
%100*p
11
1p
=
=
+=
Maximum Bit Hydraulic Horsepower
Examples - contd
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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 forthe entire well
Note that at no time should the flow rate beallowed to drop below the minimum
required for proper cuttings removal
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Maximum Jet Impact Force
The jet impact force is given by Eq. 4.37:
)(c0.01823
01823.0
d dpump
bitdj
ppq
pqcF
=
=
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Maximum Jet Impact Force
But parasitic pressure drop,
2201823.0
+=
=
m
dpdj
m
d
qcqpcF
cqp
)(c0.01823 d dpumpj ppqF =
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Maximum Jet Impact Force
Upon differentiating, setting the first derivative
to zero, and solving the resulting quadraticequation, it may be seen that the impact
force is maximized when,
pdp
2m
2p
+
=
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Maximum Jet
Impact Force
- Examples -
pb
pd
pof%47pand
pof%53p1.75,mif,
=
==Thus
pb
pd
pof33%pandpof%67p1.00mif,=
==Also
pd p2m
2
p +
=
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Nozzle Size Selection
- Graphical Approach -
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1. Show opt. hydraulic path
2. Plot pdvs q3. From Plot, determine
optimum q and pd
4. Calculate
5. CalculateTotal Nozzle Area:
(TFA)
6. Calculate Nozzle Diameter
dpumpbit ppp =
optbd
opt
opttpC
qA
)(
10*311.8)(
2
25
=
With 3 nozzles:3
A4d totN =
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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 12/32Mud Density = 9.6 lbm.gal
At 485 gal/min, Ppump = 2,800 psi
At 247 gal/min, Ppump = 900 psi
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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
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Example 4.31 - 1(a), 485 gpm
Calculate pressure drop through bit nozzles:
22
2510*311.8:)34.4.(
td
bAc
qpEq
=
psi9061,894-2,800losspressureparasitic
psi1,894
32
12
43(0.95)
)485)(6.9)(8.311(10p2
2
2
2-5
b
==
=
=
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Example 4.31 - 1(b), 247 gpm
psip b 491
32
12
43)95.0(
)247)(6.9)(10(311.82
2
2
25
=
=
psi409491-900losspressureparasitic ==
Plot these two
points in Fig. 4.36
(q1, p1) = (485, 906)
(q2, p2) = (247, 409)
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Example 4.31 - contd
2. For optimum hydraulics:
gal/min650000,3
)91.0)(250,1(714,1714,1q
max
max ===P
EPHp
1,Interval)a(
gal/min225q
psi875,1
)000,3(22.1
2
2
2p
min
maxd
=
=
+=
+= P
m2,Interval(b)
3,Interval(c)
3
2
1
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Example 4.31
3. From graph, optimum point is at
)(
10*311.8)(2
25
optbd
opt
opttpC
qA
=
)700,1(*)95.0()650(*6.9*10*8.311
2
2-5
=
( ) indoptN
nds2
opt 3214in0.47A ==
psippsigal
q b 700,1300,1p,min650d ===
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psippsigal
q b 700,1300,1p,
min
650 d ===
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Example 4.32
It is desired to estimate the proper pump
operating conditions and bit nozzle sizes for
maximum bit horsepower at 1,000-ftincrements for an interval of the well
between surface casing at 4,000 ft and
intermediate casing at 9,000 ft. The wellplan calls for the following conditions:
Well Planning
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Example 4.32
Pump: 3,423 psi maximum surface pressure
1,600 hp maximum input0.85 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
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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
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Mud Program
Mud Plastic YieldDepth 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
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Solution
The path of optimum hydraulics is as
follows:
Interval 1
gal/min.681
423,3)85.0)(600,1(714,1
pEP714,1q
max
Hp
max
=
==
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Solution
Interval 2
Since measured pump pressure data are notavailable and a simplified solution technique
is desired, a theoretical m value of 1.75 is
used. For maximum bit horsepower,
( )
psia1,245
423,3
175.1
1
1
1max
=
+
=
+
= p
m
pd
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Solution
Interval 3
For a minimum annular velocity of120 ft/min opposite the drillpipe,
( )
gal/min395
60
1205.405.10448.2 22min
=
=q
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Table
The frictional pressure loss in other
sections is computed following aprocedure similar to that outlined above for
the sections of drillpipe. The entire
procedure then can be repeated todetermine the total parasitic losses at
depths of 6,000, 7,000, 8,000 and 9,000 ft.
The results of these computations aresummarized in the following table:
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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 1,1208,000 51 1,116 433 28 75* 1,703
9,000 57 1,407 482 27* 111* 2,084
* Laminar flow pattern indicated byHedstrom number criteria.
ddpadcadcdps ppppppDepth
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Table
The proper pump operating conditions
and nozzle areas, are as follows:
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 0.3388,000 420 1,245 2,178 0.299
9,000 395 1,370 2,053 0.302
in.)(sq(psi)(psi)(gal/min))ft(
(5)Ap(4)p(3)Rate(2)FlowDepth)l( tbd
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Table
The first three columns were read directly
from Fig. 4.37. (depth, flow rate and
pd)
Col. 4 (pb) was obtained by subtracting
shown in Col.3 from the maximum pumppressure of 3,423 psi.
Col.5 (Atot) was obtained using Eq. 4.85
dp
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Surge Pressure due to Pipe Movement
When a string of pipe is
being lowered into thewellbore, 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 thesurge pressure.
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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 behigh enough to suck fluids into the wellbore,
resulting in a kick.
swabsurge PP ,vfixedFor pipe =
Fi 4 40B
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Figure 4.40B
- Velocity profile for laminar flow pattern when closed
pipe is being run into hole