19. kick detection and control
TRANSCRIPT
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ATM
PETE 661
Drilling Engineering
Lesson 19
Kick Detection and Control
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2ATM
Kick Detection and Control
Primary and Secondary Well Control
What Constitutes a Kick
Why Kicks Occur
Kick Detection Methods
Kicks while Tripping
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3ATM
Kick Detection and Control
Shut-in Procedures
Soft Shut-in
Hard Shut-in
Water Hammer
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4ATM
Kick Detection and Control
Read: ADE Ch. 6
Reference: Advanced Well Control Manual, SPE Textbook,
~2003...
Homework # 11 - due November 25
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5ATM
Kick Detection and Control
The focus of well control theory is to contain and manage
formation pressure. Primary well control involves efforts at
preventing formation fluid influx into the wellbore.
Secondary well control involves detecting an influx and
bringing it to the surface safely.
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6ATM
Kicks
A kick may be defined as an unscheduled influx of formation fluids.
Fluids produced during underbalanced drilling are not considered kicks
Fluids produced during a DST are not considered kicks
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7ATM
Kicks
For a kick to occur, we need:
Wellbore pressure < pore pressure
A reasonable level of permeability
A fluid that can flow
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8ATM
Kicks
Kicks may occur while: Drilling Tripping Making a connection Logging Running Casing Cementing N/U or N/D BOP, etc.
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9ATM
Causes of Kicks
Insufficient wellbore fluid density
Low drilling or completion fluid density
Reducing MW too much
Drilling into abnormally pressured formations
Temperature expansion of fluid
Excessive gas cutting
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10ATM
Causes of Kicks - cont’d
Reduction of height of mud column
Lost circulation because of excess static or dynamic wellbore
pressure
Fluid removal because of swabbing
Tripping pipe without filling the hole
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11ATM
Causes of Kicks - cont’d
Excessive swab friction pressure while moving pipe
Wellbore collision between a drilling and producing well
Cement hydration
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12ATM
Kick indicators
Indicator
Drilling break
Increase in mud return
rate
Pit gain
Flow w/ pumps off
Significance
Medium
High
High
Definitive
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13ATM
Kick indicators Indicator
Pump pressure decrease/ rate increase
Increase in drillstring weight
Gas cutting or salinity change
Significance
Low
Low
Low
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14ATM
Kick Influx Rate
This equation would rarely be strictly applicable in the event of a kick since fluid compressibility is not considered and transient relationships better describe influx flow behavior.
radius wellborer
radius drainage r
cosityinflux vis
wellboreat the pressure pore p
radius drainage at the pressure pore p
thickness,formation h
typermeabiliformation k
rate, flowinflux q
where
ln
w
e
w
e
we
we
rr
ppkhq
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15ATM
Kick Influx Rate
Extremely important to detect a kick early, to minimize its
size.
If a kick is suspected,
run a flow check!!!
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16ATM
Circulation path for Drilling Fluid
What goes in Must come out
unless a kick occurs…or…
As drilling proceeds, mud level in pit drops slowly.
Why?
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17ATM
Set alarm for high or low flow rate
If a kick occurs, flow rate from the well increases - an early indicator
Mud Return Rate
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18ATM
Pit Volume Totalizer, PVT shows pit gain or loss.
Pit level is a good kick indicator
System should detect a 10 bbl kick under most conditions onshore
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19ATM
Kick size Under most conditions a 10 bbl kick
can be handled safely.
An exception is slimhole drilling, where even a small kick occupies a large height in the annulus.
In floating drilling, where the vessel moves, small kicks are more difficult to detect
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20ATM
Mud pulse telemetry - pressure pulses detected at the surface
Compare signals
from drillpipe
and annulus
High amplitudepositive pulse
Low amplitudenegative pulse
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21ATM
Acoustic kick detection
Gas in the annulus will attenuate a pressure signal, and will reduce the velocity of sound in the mud
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22ATM
Minimum kick size that can be detected by an acoustic system
Temperature = 212 degrees F.Mud density = 16.7 lbm/galInflux rate = 32 gal/minPump rate = 317 gal/minCollar diameter = 6 inchesHole diameter = 8-1/2 inches
Pressure, psi
Kic
k vo
lum
e, b
bl
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23ATM
Delta flow
indicator
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24ATM
Delta flow indicatorDelta flow = qout - qin
Kick detected
Upper Alarm Threshold
Lower Alarm Threshold
Time
Del
ta F
low
In
dic
ato
r
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25ATM
Delta flow indicator
Field Examples of Kick Detection and Final Containment Volumes using the Delta Flow Method
Hole Depth Influx Volume Volume Size ft. Rate Detected
Contained in. gal/min bbl bbl
5 7/85 7/85 7/8
15,77014,00517,152
35 760
0.720.701.00
2.01.55.0
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26ATM
BOP stack
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27ATM
BOP Control Panel
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28ATM
Choke Manifold
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29ATM
Choke panel
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30ATM
If a kick is suspected
Lift the drillstring until a tool joint is just above the rotary table
Shut down the mud pumps
Check for flow
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31ATM
If a kick is suspected
If flowing - shut the annular, open the HCR valve, and close the choke
Record SIDPP and SICP
Record pit gain and depth (MD and TVD)
Note the time
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32ATM
Hard Shut-In
1. Assure beforehand the choke manifold line is open to preferred choke and choke is in closed position.
2. After a kick is indicated, hoist the string and position tool joint above rotary table.
3. Shut off pump
4. Observe flowline for flow.
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33ATM
Hard Shut-In5. If flow is verified, shut the well in by
using annular preventer and open the remote-actuated valve to the choke manifold.
6. Notify supervisor (company drilling supervisor, toolpusher or rig manager).
7. Read and record shut-in drillpipe pressure (SIDPP).
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34ATM
Hard Shut-In 8. Read and record shut-in casing
pressure (SICP).
9. Rotate the drillstring though the closed annular preventer if feasible.
10. Measure and record pit gain.
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35ATM
Water hammer ?
Hard Shut-In
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36ATM
Soft Shut-In
1. Assure beforehand choke manifold line is open to preferred choke and choke in in open position.
2. After kick is indicated, hoist string & position tool joint above rotary table.
3. Shut off pump.
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37ATM
Soft Shut-In
4. Observe flowline for flow.
5. If flow is verified, open remote-actuated valve to choke manifold and close annular preventer.
6. Shut well in by closing choke.
7. Notify supervisor (company drilling supervisor, toolpusher, rig manager).
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38ATM
Soft Shut-In
8. Read and record SIDPP.
9. Read and record SICP.
10.Rotate drillstring through closed annular preventer if feasible.
11.Measure and record pit gain.
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39ATM
Larger Kick !
Soft Shut-In
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40ATM
Example 5.1A kick is detected while drilling at 13,000 ft. The well is shut-in by the ram preventer in
5 seconds.
Determine water hammer load at surface if influx flow rate is 3.0 bbl/min, the mud’s acoustic velocity is 4,800 ft/s and mud density is 10.5 lbm/gal
1.
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41ATM
Example 5.1, continued
For the same conditions:
Compute velocity assuming the annulus flow area corresponds to 5.0 in. drillpipe inside 8.921 in. inner diameter casing.
Ignore effect of influx properties on wave travel time and amplitude.
2.
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42ATM
Example 5.1, continued
……………………. (5.2)c
ac g
vvp
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43ATM
Example 5.1, continuedThe relationship is only valid if valve is fully
closed before the shock wave has time to make the round trip from surface to total depth. If this condition is not met, closure is defined as “slow” as opposed to “rapid” and resultant pressure surge will be lower.
Regardless of method, some pressure increase, however minor, cannot be avoided and the soft shut-in procedure may in fact be considered rapid in some cases.
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44ATM
Example 5.1, cont’d
Solution: The time for the pressure wave to traverse the system is
t = dist/vel = (2)(13,000)/4,800 = 5.4 sec
Hence this would be characterized as a rapid shut-in and Equation 5.2 is appropriate.
c
ac g
vvp
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45ATM
Example 5.1 cont’d
2. The velocity change in the annulus is computed as:
222
223
in )5-/4(8.921s/min) (60
)/ftin /bbl)(144ft .615bbl/min)(5 (3.0q
c
ac g
vvp
v = 0.94 ft/s
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46ATM
Example 5.1 cont’dThe surface pressure increase is given by
equation 5.2
2
3
c s-lbf / ft-lbm 32.17
ft/s .ft/s ,gal/ft .lbm/gal 10.5
9408004487
psi. 76 lbf/ft 11,015 2c
c
ac g
vvp
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47ATM
Off Bottom Kicks
Slugging of drillpipe
Hole fill during trips
Surge and Swab pressures
Kick detection during trips
Shut-In Procedures
Blowout Case History
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48ATM
Off Bottom Kicks
Pbh = g1h1 + g2h2 = g2h3
Hydrostatic Balance
When stopping circulation, ECD is lost. Always check for flow.
“Slugging” of Drillpipe to prevent “Wet Trip”
… AFTER Flow Check
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49ATM
Failure to keep the hole full
When pipe if removed from the wellbore the fluid level drops resulting in loss of HSP.
To prevent kicks the hole must be re-filled with mud.
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50ATM
Nominal Dimensions-Displacement Factors for API Drillpipe
Outside Nominal Nominal Average Displacement Diameter Inside Weight Approximate Factor
in. Diameter, in. lbm/ft Weight bbl/ft
2-3/8 1.995 4.85 5.02 0.001821.815 6.65 6.80 0.00247
2-7/8 2.441 6.85 7.09 0.00258 2.151 10.40 10.53 0.00383
3-1/2 2.992 9.50 10.15 0.003692.764 13.30 13.86 0.005042.602 15.50 16.39 0.00596
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51ATM
Nominal Dimensions-Displacement factors for API
DrillpipeOutside Nominal Nominal Average Displacement
Diameter Inside Weight Approximate Factorin. Diameter, in. lbm/ft Weight bbl/ft
4 3.476 11.85 12.90 0.004693.340 14.00 15.14 0.005513.240 15.70 17.13 0.00623
4-1/2 3.958 13.75 14.75 0.005373.826 16.60 17.70 0.006443.640 20.00 21.74 0.007913.500 22.82 24.33 0.00885
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52ATM
Nominal Dimensions-Displacement factors for API
DrillpipeOutside Nominal Nominal Average Displacement
Diameter Inside Weight Approximate Factorin. Diameter, in. lbm/ft Weight bbl/ft
5 4.276 19.50 21.58 0.007854.000 25.60 27.58 0.01003
5-1/2 4.778 21.90 23.77 0.008654.670 24.70 26.33 0.00958
6-6/8 5.965 25.20 27.15 0.009885.901 27.70 29.06 0.01057
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53ATM
Displacement Factors for High Strength Drillpipe
Outside Nominal Average Displacement Diameter Weight Approximate Factor
in. lbm/ft Weight, lbm/ft. bbl/ft
2-3/8 6.65 6.95 0.002532-7/8 10.40 11.01 0.00400
3-1/2 13.30 14.51 0.00528
15.50 17.02 0.00619
4 14.00 15.85 0.0057715.70 17.50 0.00637
4-1/2 16.60 18.65 0.0067820.00 22.40 0.0081522.82 25.21 0.00917
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54ATM
Displacement Factors for High Strength Drillpipe
Outside Nominal Average Displacement Diameter Weight Approximate Factor
in. lbm/ft Weight, lbm/ft. bbl/ft
5 19.50 22.34 0.0081325.60 28.60 0.01040
5-1/2 21.90 25.14 0.0091424.70 28.13 0.01023
6-5/8 25.20 28.33 0.0103127.70 30.58 0.01112
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55ATM
Displacement Factors for Heavy-Wall Drillpipe
Outside Nominal Connection Approx. Displacement Diameter Inside Weight Factor
in. Diameter, in. lbm/ft bbl/ft
3-1/2 2.063 NC38 23.20 0.008442.250 NC38 25.30 0.00920
4 2.563 NC40 29.70 0.01080
4-1/2 2.750 NC46 41.00 0.01491
5 3.00 NC50 49.30 0.01793
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56ATM
Example 5.2Drill a well to 9,500 total depth with a 10.0
lbm/gal mud. 8.097 in. ID casing has been set at 1,500 ft.
Determine the hydrostatic pressure loss if ten 90 ft stands of 4 1/2 in., 16.60 lbm/ft Grade E drillpipe are pulled without filling the hole.
Also determine the losses after pulling ten
stands of drillpipe if the bit is plugged and after pulling one stand of 6 1/4 x 2 1/2 in drill collars.
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57ATM
Example 5.2
Solution
The displacement factor for open drillpipe is obtained from Table 5.5 and the displacement volume is computed as:
Vd = (0.00644) (10) (90) = 5.80 bbl
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58ATM
Example 5.2To determine the drop in fluid level, we must
have capacity factors for the drillpipe and annulus. These can be obtained directly from a published table or by calculation.
Inside Drillpipe:
Ci = 3.8262/1,029.4 = 0.1422 bbl/ft. and
Inside Annulus:
Cc = (8.0972 - 4.52)/1,029.4 = 0.04402 bbl/ft.
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59ATM
Example 5.2These values are only approximate since the effect of the pipe upsets and tool joints are not considered. The mud level will fall by
h = 5.80/(0.01422 + 0.04402) = 99.6 ft.
and the corresponding hydrostatic pressure loss is
p = 99.6(10.0/19.25) = 52 psi.
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60ATM
Example 5.2
Tripping out with a plugged bit implies the string is pulled wet and, if no mud falls back in the hole, the drillstring inner capacity is being evacuated along with the steel. The volume removed after pulling ten stands wet is
V = Vi + Vd = (0.00644 + 0.01422)(10)(90)
= 18.59 bbl
(inside drillpipe + steel in drillpipe)
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61ATM
Example 5.2
The mud level drop in the annulus and pressure loss are thus
h = 18.59/0.04402 = 422.3 ft.
and
p = (422.3)(0.519) = 219 psi.
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62ATM
Example 5.2
For drill collars, we compute the displacement factor and displacement volume as
Cd = (6.252 - 2.52)/1,029.4 = 0.03188 bbl/ft.
and
Vd = (0.0318) (1)(90) = 2.87 bbl.
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63ATM
Example 5.2
The pressure loss is determined in the same manner as the open drillpipe case.
Ci = 2.52/1,029.4 = 0.00607 bbl/ft
Ca = (8.0972- 6.252)/1,029.4 = 0.02574 bbl/ft
h = 2.87/(0.00607 + 0.02574) = 90.2 ft
and
p = (0.519) (90.2) = 47 psi