PETE 661 Drilling Engineering

1
PETE 661Drilling Engineering

• Lesson 19
• Kick Detection and Control

2
Kick Detection and Control

• Primary and Secondary Well Control
• What Constitutes a Kick
• Why Kicks Occur
• Kick Detection Methods
• Kicks while Tripping

3
Kick Detection and Control

• Shut-in Procedures
• Soft Shut-in
• Hard Shut-in
• Water Hammer

4
Kick Detection and Control

• Read ADE Ch. 6
• Reference Advanced Well Control Manual, SPE
  Textbook, 2003...
• Homework 11 - due November 25

5
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.

6
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

7
Kicks

• For a kick to occur, we need
• Wellbore pressure lt pore pressure
• A reasonable level of permeability
• A fluid that can flow

8
Kicks

• Kicks may occur while
• Drilling
• Tripping
• Making a connection
• Logging
• Running Casing
• Cementing
• N/U or N/D BOP, etc.

9
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

10
Causes of Kicks - contd

• 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

11
Causes of Kicks - contd

• Excessive swab friction pressure while moving
  pipe
• Wellbore collision between a drilling and
  producing well
• Cement hydration

12
Kick indicators

• Significance
• Medium
• High
• High
• Definitive

• Indicator
• Drilling break
• Increase in mud return rate
• Pit gain
• Flow w/ pumps off

13
Kick indicators

• Indicator
• Pump pressure decrease / rate increase
• Increase in drillstring weight
• Gas cutting or salinity change

• Significance
• Low
• Low
• Low

14
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.

15
Kick Influx Rate

• Extremely important to detect a kick early, to
  minimize its size.
• If a kick is suspected,

run a flow check!!!
16
Circulation path for Drilling Fluid What goes in
Must come out unless a kick occursor
As drilling proceeds, mud level in pit drops
slowly. Why?
17
Mud Return Rate
Set alarm for high or low flow rate
If a kick occurs, flow rate from the well
increases - an early indicator
18
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
19
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

20
Mud pulse telemetry - pressure pulses detected at
the surface
High amplitude positive pulse
Compare signals from drillpipe and annulus
Low amplitude negative pulse
21
Acoustic kick detection
Gas in the annulus will attenuate a pressure
signal, and will reduce the velocity of sound in
the mud
22
Minimum kick size that can be detected by an
acoustic system
Temperature 212 degrees F. Mud density
16.7 lbm/gal Influx rate 32
gal/min Pump rate 317 gal/min Collar
diameter 6 inches Hole diameter
8-1/2 inches
Kick volume, bbl
Pressure, psi
23
Delta flow indicator
24
Delta flow indicator
Delta flow qout - qin
Kick detected
Upper Alarm Threshold
Delta Flow Indicator
Lower Alarm Threshold
Time
25
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 7/8 5 7/8 5 7/8
15,770 14,005 17,152
35 7 60
0.72 0.70 1.00
2.0 1.5 5.0
26
BOP stack
27
BOP Control Panel
28
Choke Manifold
29
Choke panel
30
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

31
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

32
Hard Shut-In

• Assure beforehand the choke manifold line is open
  to preferred choke and choke is in closed
  position.
• After a kick is indicated, hoist the string and
  position tool joint above rotary table.
• Shut off pump
• Observe flowline for flow.

33
Hard Shut-In

• 5. 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).

34
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.

35
Hard Shut-In
Water hammer ?
36
Soft Shut-In

• Assure beforehand choke manifold line is open to
  preferred choke and choke in in open position.
• After kick is indicated, hoist string position
  tool joint above rotary table.
• Shut off pump.

37
Soft Shut-In

• Observe flowline for flow.
• If flow is verified, open remote-actuated valve
  to choke manifold and close annular preventer.
• Shut well in by closing choke.
• Notify supervisor (company drilling supervisor,
  toolpusher, rig manager).

38
Soft Shut-In

• Read and record SIDPP.
• Read and record SICP.
• Rotate drillstring through closed annular
  preventer if feasible.
• Measure and record pit gain.

39
Soft Shut-In
Larger Kick !
40
Example 5.1

• A 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 muds acoustic velocity is 4,800 ft/s and
• mud density is 10.5 lbm/gal

1.
41
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.
42
Example 5.1, continued
. (5.2)
43
Example 5.1, continued

• The 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.

44
Example 5.1, contd

• 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.

45
Example 5.1 contd

• 2. The velocity change in the annulus is
  computed as

Dv 0.94 ft/s
46
Example 5.1 contd

• The surface pressure increase is given by
  equation 5.2

47
Off Bottom Kicks

• Slugging of drillpipe
• Hole fill during trips
• Surge and Swab pressures
• Kick detection during trips
• Shut-In Procedures
• Blowout Case History

48
Off Bottom Kicks
Pbh g1h1 g2h2 g2h3
When stopping circulation, ECD is lost. Always
check for flow. Slugging of Drillpipe to
prevent Wet Trip AFTER Flow Check
Hydrostatic Balance
49
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.
50
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 0.00182
• 1.815 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 0.00369
• 2.764 13.30 13.86 0.00504
• 2.602 15.50 16.39 0.00596

51
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
• 4 3.476 11.85 12.90 0.00469
• 3.340 14.00 15.14 0.00551
• 3.240 15.70 17.13 0.00623
• 4-1/2 3.958 13.75 14.75 0.00537
• 3.826 16.60 17.70 0.00644
• 3.640 20.00 21.74 0.00791
• 3.500 22.82 24.33 0.00885

52
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
• 5 4.276 19.50 21.58 0.00785
• 4.000 25.60 27.58 0.01003
• 5-1/2 4.778 21.90 23.77 0.00865
• 4.670 24.70 26.33 0.00958
• 6-6/8 5.965 25.20 27.15 0.00988
• 5.901 27.70 29.06 0.01057

53
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 0.00253
• 2-7/8 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 0.00577
• 15.70 17.50 0.00637
• 4-1/2 16.60 18.65 0.00678
• 20.00 22.40 0.00815
• 22.82 25.21 0.00917

54
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 0.00813
• 25.60 28.60 0.01040
• 5-1/2 21.90 25.14 0.00914
• 24.70 28.13 0.01023
• 6-5/8 25.20 28.33 0.01031
• 27.70 30.58 0.01112

55
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 0.00844
• 2.250 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

56
Example 5.2

• Drill 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.

57
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

58
Example 5.2

• To 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.

59
Example 5.2

• These 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.

60
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)

61
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.

62
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.

63
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