PETE 661Drilling Engineering Lesson 19Kick Detection and ControlATM

Kick Detection and Control Primary and Secondary Well Control What Constitutes a Kick Why Kicks Occur Kick Detection Methods Kicks while TrippingATM 2

Kick Detection and Control Shut-in Procedures Soft Shut-in Hard Shut-in Water Hammer

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Kick Detection and Control Read: ADE Ch. 6 Reference: Advanced Well Control Manual, SPE Textbook, ~2003... Homework # 11 - due November 25ATM 4

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.ATM 5

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 kicksATM 6

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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Kicks Kicks may occur while: Drilling Tripping Making a connection Logging Running Casing Cementing N/U or N/D BOP, etc.ATM 8

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 cuttingATM 9

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 holeATM 10

Causes of Kicks - contd Excessive swab friction pressure while moving pipe Wellbore collision between a drilling and producing well Cement hydrationATM 11

Kick indicators Indicator Drilling break Increase in mud return rate Pit gain Flow w/ pumps offATM

Significance Medium High High Definitive12

Kick indicators Indicator Pump pressure decrease / rate increase Increase in drillstring weight Gas cutting or salinity changeATM

Significance Low Low Low13

Kick Influx Rate This equation would where rarely be strictly q = influx flow rate, applicable in the event of a kick since k = formation permeability fluid compressibility h = formation thickness, is not considered p e = pore pressure at the drainage radius and transient p w = pore pressure at the wellbore relationships better = influx viscosity describe influx flow re = drainage radius behavior.rw = wellbore radiusATM 14

kh( pe pw ) q= ln ( re rw )

Kick Influx Rate Extremely important to detect a

kick early, to minimize its size. If a kick is suspected,

run a flow check!!!ATM 15

Circulation path for Drilling Fluid

What goes in Must come out unless a kick occursorATM

As drilling proceeds, mud level in pit drops slowly. Why?

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Mud Return RateSet alarm for high or low flow rate If a kick occurs, flow rate from the well increases - an early indicator

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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 onshoreATM

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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 detectATM 19

Mud pulse telemetry - pressure pulses detected at the surfaceHigh amplitude positive pulse Compare signals from drillpipe and annulus Low amplitude negative pulseATM 20

Acoustic kick detection

Gas in the annulus will attenuate a pressure signal, and will reduce the velocity of sound in the mudATM 21

Minimum kick size that can be detected by an acoustic systemKick volume, bbl

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

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Pressure, psi

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Delta flow indicator

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Delta flow indicatorDelta flow = qout - qinDelta Flow IndicatorUpper Alarm Threshold Kick detected

Lower Alarm Threshold

TimeATM 24

Delta flow indicatorField Examples of Kick Detection and Final Containment Volumes using the Delta Flow MethodHole Size in. Depth ft. Influx Rate gal/min Volume Detected bbl Volume Contained bbl

5 7/8 5 7/8 5 7/8ATM

15,770 14,005 17,152

35 7 60

0.72 0.70 1.00

2.0 1.5 5.025

BOP stack

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BOP Control Panel

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Choke Manifold

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Choke panel

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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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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 timeATM 31

Hard Shut-In1. 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.ATM 32

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).ATM 33

Hard Shut-In8. 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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Hard Shut-In

Water hammer ?

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Soft Shut-In1. 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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Soft Shut-In4. Observe flowline for flow. 5. If flow is verified, open remoteactuated valve to choke manifold and close annular preventer. 6. Shut well in by closing choke. 7. Notify supervisor (company drilling supervisor, toolpusher, rig manager).ATM 37

Soft Shut-In8. 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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Soft Shut-In

Larger Kick !

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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. 1. 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/galATM 40

Example 5.1, continued For the same conditions: 2. 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.41

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Example 5.1, continued v a v pc = gc. (5.2)

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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. 43

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Example 5.1, contd

v a v pc = gc

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.ATM 44

Example 5.1 contd

v a v pc = gc

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

q (3.0 bbl/min)(5 .615 ft /bbl)(144 in /ft ) = = 2 2 2 (60 s/min) /4(8.921 - 5 ) in3 2 2

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v = 0.94 ft/sATM 45

Example 5.1 contd

v a v pc = gc

The surface pressure increase is given by equation 5.2

(10.5 lbm/gal) ( 7.48 gal/ft3 )( 4,800 ft/s)( 0.94 ft/s) =c

32.17 lbm - ft / lbf - s22

= 11,015 lbf/ft = 76 psi. cATM 46

Off Bottom Kicks Slugging of drillpipe Hole fill during trips Surge and Swab pressures Kick detection during trips Shut-In Procedures Blowout Case HistoryATM 47

Pbh = g1h1 + g2h2 = g2h3

Off Bottom KicksWhen stopping circulation, ECD is lost. Always check for flow. Slugging of Drillpipe to prevent Wet Trip AFTER Flow Check

Hydrostatic Balance

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Failure to keep the hole fullWhen 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.ATM 49

Nominal Dimensions-Displacement Factors for API DrillpipeOutside Nominal Nominal Average Inside Weight Approximate Factor in. Diameter, in. lbm/ft Weight 2-3/8 1.815 2-7/8 3-1/2 2.764 2.602 1.995 6.65 2.441 2.151 2.992 13.30 15.50 4.85 6.80 6.85 10.40 9.50 13.86 16.39 5.02 0.00247 7.09 10.53 10.15 0.00504 0.00596 Displacement bbl/ft 0.00182 0.00258 0.00383 0.00369 Diameter

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Nominal DimensionsDisplacement factors for API DrillpipeOutside Nominal Nominal Average Inside Weight Approximate Factor in. Diameter, in. lbm/ft Weight 4 3.340 3.240 4-1/2 3.826 3.640 3.500 3.476 14.00 15.70 3.958 16.60 20.00 22.82 11.85 15.14 17.13 13.75 17.70 21.74 24.33 12.90 0.00551 0.00623 14.75 0.00644 0.00791 0.00885 Displacement bbl/ft 0.00469 Diameter

0.00537

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Nominal DimensionsDisplacement factors for API DrillpipeOutside Nominal Nominal Average Inside Weight Approximate Factor in. Diameter, in. lbm/ft Weight 5 4.000 5-1/2 4.670 6-6/8 5.901 4.276 25.60 4.778 24.70 5.965 27.70 19.50 27.58 21.90 26.33 25.20 29.06 21.58 0.01003 23.77 0.00958 27.15 0.01057 Displacement bbl/ft 0.00785 0.00865 0.00988 Diameter

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Displacement Factors for High Strength DrillpipeOutside Diameter in. 2-3/8 2-7/8 Nominal Weight lbm/ft 6.656.95 10.40 Average Approximate Weight, lbm/ft. 0.00253 11.01 14.51 15.85 18.65 Displacement Factor bbl/ft 0.00400 0.00528 0.00577 0.00678

3-1/2 13.30 15.5017.020.00619 4 14.00 15.7017.500.00637 4-1/2 16.60 20.0022.400.00815 22.8225.210.00917ATM

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Displacement Factors for High Strength DrillpipeOutside Diameter in. Nominal Weight lbm/ft Average Displacement Approximate Factor Weight, lbm/ft. bbl/ft 22.34 25.14 28.33 0.00813 0.00914 0.01031

5 19.50 25.6028.600.01040 5-1/2 21.90 24.7028.130.01023 6-5/8 25.20 27.7030.580.01112

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Displacement Factors for Heavy-Wall DrillpipeOutside Nominal Connection Approx. Diameter Inside Weight in. Diameter, in. lbm/ft 3-1/2 4 4-1/2 5ATM

Displacement Factor bbl/ft 0.00844 0.00920 0.01080 0.01491 0.0179355

2.063 2.250 2.563 2.750 3.00

NC38 NC38 NC40 NC46 NC50

23.20 25.30 29.70 41.00 49.30

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.ATM 56

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 bblATM 57

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.ATM 58

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.ATM 59

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)ATM 60

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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Example 5.2For 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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Example 5.2The 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 psiATM 63