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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
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1. PETE 661Drilling Engineering Lesson 19
Kick Detection and Control
2. 2 Kick Detection and Control Primary and Secondary Well Control
What Constitutes a Kick
Why Kicks Occur
Kick Detection Methods
Kicks while Tripping
3. 3 Kick Detection and Control Shut-in Procedures
Soft Shut-in
Hard Shut-in
Water Hammer
4. 4 Kick Detection and Control Read: ADE Ch. 6
Reference: Advanced Well Control Manual, SPE Textbook, ~2003...
Homework # 11 - due November 25
5. 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. 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. 7 Kicks For a kick to occur, we need:
Wellbore pressure < pore pressure
A reasonable level of permeability
A fluid that can flow
8. 8 Kicks Kicks may occur while:
Drilling
Tripping
Making a connection
Logging
Running Casing
Cementing
N/U or N/D BOP, etc.
9. 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. 10 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
11. 11 Causes of Kicks - cont’d Excessive swab friction pressure while moving pipe
Wellbore collision between a drilling and producing well
Cement hydration
12. 12 Kick indicators Indicator
Drilling break
Increase in mud return rate
Pit gain
Flow w/ pumps off Significance
Medium
High
High
Definitive
13. 13 Kick indicators Indicator
Pump pressure decrease / rate increase
Increase in drillstring weight
Gas cutting or salinity change Significance
Low
Low
Low
14. 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. 15 Kick Influx Rate Extremely important to detect a kick early, to minimize its size.
If a kick is suspected,
16. 16
17. 17
18. 18
19. 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. 20
21. 21 Acoustic kick detection
22. 22 Minimum kick size that can be detected by an acoustic system
23. 23 Delta flow indicator
24. 24 Delta flow indicator
25. 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
26. 26 BOP stack
27. 27 BOP Control Panel
28. 28 Choke Manifold
29. 29 Choke panel
30. 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. 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. 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. 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. 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. 35 Hard Shut-In
36. 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. 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. 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. 39 Soft Shut-In
40. 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 mud’s acoustic velocity is 4,800 ft/s and
mud density is 10.5 lbm/gal
41. 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.
42. 42 Example 5.1, continued
43. 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. 44 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.
45. 45 Example 5.1 cont’d 2. The velocity change in the annulus is computed as:
46. 46 Example 5.1 cont’d The surface pressure increase is given by equation 5.2
47. 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. 48 Off Bottom Kicks
49. 49 Failure to keep the hole full
50. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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