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PETE 661 Drilling Engineering

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The actual mechanics are complicated, but can be sufficiently ... q100 = 17 lbf/100 ft2. q6 = 5 lbf/100 ft2. q3 = 4 lbf/100 ft2. 9. ATM. Example B-1, solution ... – PowerPoint PPT presentation

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Title: PETE 661 Drilling Engineering


1
PETE 661 Drilling Engineering
  • Lesson 20
  • Surge and Swab

2
Surge and Swab
  • Three Different Forms of Surge and Swab
    Pressures
  • Kick Detection on Trips
  • Well Shut-in Procedures when a KICK is
    Detected
  • A Blowout Case History

3
Surge and Swab
  • Read ADE Ch. 6
  • Reference Advanced Well Control Manual, SPE
    Textbook, 2003...
  • Homework 11 - due Nov. 25
  • Homework 12 - due Dec. 02
  • Project - due Dec 6

4
Surge Swab
  • The actual mechanics are complicated, but can be
    sufficiently described by
  • Pressure to initiate movement in a thixotropic
    mud
  • Steady-flow viscous drag between moving pipe
    and a static borehole,
  • Dynamic pressures resulting from mud
    acceleration or deceleration

5
  • Annulus Mud Velocity Profile during downward
    movement of drillstring resulting in surge
    pressure
  • Function of
  • pipe speed
  • system geometry
  • flow regime
  • whether the pipe is open or closed

6
Inertial effects of pipe movement
Peak Velocity
Deceleration effects while breaking
Pipe at rest
Swab due to acceleration when P/U off of slips
7
Example B-1
  • The following conditions apply to a drilling
    liner job on a deep well.
  • Present depth 16,000 ft
  • Last casing setting depth 12,100 ft
  • Last casing inner diameter 8.835 in
  • Liner outer diameter 7.625 in
  • Drillpipe outer diameter 5.0 in
  • Liner length 4,300
    ft
  • Mud density 15.8
    lbm/gal
  • Average running speed one min. for

  • a 90 ft stand
  • Maximum acceleration 0.60 ft/s2

12,100
16,000
8
Example B-1
  • Assume the mud has developed an average gel
    strength of 30 lbf/100 ft2 use the following
    Fann multispeed viscometer data
  • q600 65 lbf/100 ft2
  • q300 39 lbf/100 ft2
  • q200 27 lbf/100 ft2
  • q100 17 lbf/100 ft2
  • q6 5 lbf/100 ft2
  • q3 4 lbf/100 ft2

9
Example B-1, solution
  • When dealing with tapered string geometries
    (liner strings, drilling assemblies, etc.), the
    maximum surge or swab pressure is usually
    experienced when the bottom of the string reaches
    the depth of interest.
  • So, determine the surge pressure at 12,100 ft for
    each of the three effects and calculate the
    equivalent density based on the highest value.

10
Example B-1
  • Equation B-1 yields the pressure required to
    break the gel strength

d1
d2
11
Example B-1
  • We estimate the maximum string velocity using
    Equation B-4
  • Vp 1.5 (90/60)
  • 2.25 ft/s
  • 135 ft/min

12
Example B-1
  • From Equation B-2, the relative velocity opposite
    the liner for Newtonian fluids is

13
Example B-1
  • The liner-casing clearance expressed as a ratio
    is (7.625/8.835) or 0.863. Assuming power law
    behavior, Schuhs extrapolated mud clinging
    constant is about 0.48. Hence the effective
    annular velocity from Equation B-5 is
  • Væ 394 (0.48)(135) 459 ft/min.

14
Turbulent
Laminar
Mud Clinging Constant
Ratio of Pipe Diameter to Hole Diameter
15
Example B-1
  • To estimate annular friction losses, plot the
    Fann viscometer data as shown in Figure B-2 and
    the equivalent viscometer speed at 459 ft/min
    using

16
66
Viscometer Reading, lbf/100ft2
611
Viscometer Speed, rpm
17
Example B-1
  • The viscometer shear stress q611 obtained from
    Figure B-2 is about 66 lbf/100 ft2. The laminar
    flow surge pressure for the liner is
  • where is the steady-flow surge pressure
    and the subscript 1 designates the lowermost
    string section.

18
Example B-1
  • Convert the effective annular velocity into a
    flow rate
  • and determine the turbulent loss

19
Example B-1
  • The turbulent flow expression yields the highest
    pressure loss so 897 psi is considered the
    answer. Repeat the procedure for the drillpipe /
    casing annulus.
  • K is 0.43 for the 0.566 diameter ratio so the
    effective annular velocity is
  • Vae 64 (0.43)(135) 122 ft/min.

20
Example B-1
  • The equivalent viscometer speed is
  • and q51 is 12.5 lbf/100ft2 from the logarithmic
    plot.
  • Determine the laminar surge pressure across the
    drillpipe annulus as

21
Example B-1
  • Repeating the turbulent flow calculations
  • and

22
Example B-1
  • The surge pressure across the drillpipe is 85 psi
    and the total frictional pressure drop for the
    tapered string is

23
Example B-1
  • Finally, equation B-6 yields the pressure
    increase due to pipe acceleration.

24
Example B-1
  • And,
  • Of the three effects, the steady-flow condition
    is the most significant and the maximum
    equivalent density seen at the last casing seat
    is

25
2
Results in Mud lifted from annulus
And evacuation of the drillstring
3
and a drop in DP fluid level and a drop in BHP
4
Tight Clearance
5
1
26
Example 5.3
  • A trip operation commences at 5,010 ft with
  • a 0.45-psi/ft gas sand at 5,000 ft
  • a 13-3/8 in. 54.5-lbm/ft surface casing set at
    2,000 ft
  • the hole diameter assumed to be 12.25 in.

27
Example 5.3
  • The drillstring consists of
  • 4-1/2 in., 16.60 lbm/ft Grade E drillpipe and
  • 600 ft.(182.9 m) of 7 x 3 in drill collars.
  • Excess hole drag is indicated some distance off
    bottom and the annulus soon becomes packed off.
  • Determine the pressure gradient at the gas sand
    after pulling one more 90 ft stand of drillpipe
    if the mud density is 9.2 lbm/gal

28
Example 5.3, solution
  • The mud in the space between the drillpipe and
    openhole and steel volume are removed from the
    hole by pulling one stand. The capacity factor
    for a 4.5 x 12.25 inch annulus is 0.12611 bbl/ft.
    The voided volume is
  • V (Cd Ca)
  • V 90 (0.00644 0.12611)
  • 11.9 bbl

29
Example 5.3, solution
  • The mud level change in the drillpipe is this
    volume divided by the internal capacity factor
  • ?h 11.9/0.01422 836.8 ft.
  • Which leads to the final wellbore pressure
    gradient.

Then what…?
( gsand 0.45 psi/ft )
30
Kick detection during trips-Example 5.4
  • A national 10-P-130 triplex pump has a rated 3.7
    gal/stroke output when furnished with 6.0 in.
    liners.
  • How many strokes should this pump take to fill
    the hole after pulling 10 stands of 5 in., 19.50
    lbm/ft high - strength drillpipe? (Assume 95
    volumetric efficiency.)

31
Kick detection during trips-Solution
  • The displacement factor for the drillpipe is
    obtained from table 5.6 and the volume
    corresponding to ten 90 stands is determined as
  • Vd (0.00813)(900) 7.3 bbl.
  • Pump stroke counters that come with a PVT rental
    package usually have a trip mode setting which
    causes the counter to automatically stop the
    stroke count when the flowline sensor detects
    return flow. From Equation 5.9 the stroke counter
    should read
  • when the hole fills.

32
Kick detection during trips
To mud pit
Flowline
Fillup line
Annulus kept full by continuous circulation from
trip tank
Stack
Trip tank
Centrifugal pump
33
Kick detection during trips
Wellhead Sonar
Water gun
Receiver Processor
Gas cut mud
Welbore Discontinuity
Hole Bottom
34
Hard Shut-In while tripping DP
  • Assure first that the choke manifold line is open
    to preferred choke choke is in closed
    position.
  • When a kick is verified, position upper tool
    joint above the floor and set slips.
  • Stab and makeup a full-opening safety valve in
    open position
  • Close safety valve.
  • Shut the well in, using annular preventer open
    remote-actuated valve to the choke manifold.

35
Hard Shut-In while tripping DP
  • Notify supervisory personnel.
  • Install kelly.
  • Open safety valve. Read record SIDPP.
  • Read record SICP.
  • Rotate drillstring through the closed annular
    preventer if feasible.
  • Measure record the pit gain.

36
Soft Shut-In while tripping DP
  • Assure first that the choke manifold line is open
    to preferred choke choke is in open position.
  • When a kick is verified, position upper tool
    joint above the floor and set slips.
  • Stab and makeup a full-opening safety valve in
    open position.
  • Close safety valve.
  • Close the annular preventer open
    remote-actuated valve to the choke manifold.

37
Soft Shut-In while tripping DP
  • Shut well in by closing choke.
  • Notify supervisory personnel.
  • Install kelly.
  • Open safety valve. Read record SIDPP.
  • Read record SICP.
  • Rotate drillstring through closed annular
    preventer if feasible.
  • Measure record the pit gain.

38
Shut-In while tripping DP-- more than one stand
in hole
  • First assure that the choke manifold line is open
    to preferred choke choke is in open position.
  • When a kick is verified, position upper
    connection above the floor and set slips.
  • Pickup last drillpipe or combination stand make
    up into collar.
  • Run stand into hole, position tool joint set
    slips.
  • Stab makeup a full-opening safety valve in open
    position.
  • Close safety valve.

39
Shut-In while tripping DP-- more than one stand
in the hole
  • Close pipe rams open remote-actuated valve to
    choke manifold.
  • Shut well in by closing the choke.
  • Notify supervisory personnel.
  • Install kelly.
  • Open safety valve. Read record SIDPP.
  • Read record SICP.
  • Rotate drillstring through closed annular
    preventer if feasible.
  • Measure record pit gain.

40
Shut-In tripping DC
41
Example 5.5
  • Two 9 x 3 in. drill collars left to be pulled
    when flow is detected. The bore is shut-in with a
    FOSV and the annular preventer is closed.
  • At what shut-in pressure will the string be
    ejected from the hole if friction between the
    packing element and collar is 1,000 lbf and the
    mud density is 9.4 lbm/gal
  • Assume the casing pressure gauge is 20 ft below
    the closed value.

42
Example 5.5, solution
  • Problem solution lies in setting equal to
    zero in equation 5.11 and solving for

43
Example 5.5
  • Note the denominator term is equivalent to
    cross-sectional area of pipe OD, Ao. Solving for
    Ao and the other cross-sectional areas.

44
Example 5.5
  • The unit weight of the collar section can be
    determined by multiplying the steel volume over
    one foot by the steel specific weight of 0.2833
    lbf/cu in
  • W1(56.548 sq in)(12 in/ft)(0.2833 lbf/cu in)192
    lbf/ft
  • Assume a 180 ft stand length, substitute terms
    and solve for

45
Shut-in when out of hole
  • Choke line open with blind ram closed--
  • When a kick is verified, close the choke.
  • Close manifold gate valve immediately upstream
    from the closed choke.
  • Notify supervisory personnel.
  • Read record SICP.
  • Measure record pit gain.

46
Shut-in when out of hole
  • Choke line closed with blind ram open (Hard Shut
    in)
  • When a kick is verified, close the blind ram.
  • Close manifold gate valve immediately upstream
    from the closed choke.
  • Notify supervisory personnel,
  • Read record SICP.
  • Measure record pit gain.

47
Shut-in when out of hole
  • Choke line open with blind ram open or soft
    shut-in--
  • When a kick is verified, close blind ram.
  • Close choke.
  • Close manifold gate valve immediately upstream
    from the closed choke.
  • Notify supervisory personnel.
  • Read record SICP.
  • Measure record pit gain.

48
Blowout Case History
49
Blowout Case History
  • Significant events pertaining to a blowout from a
    shallow oil well.
  • Set 18-5/8 in conductor casing at 415 ft (100 ft
    BML). Installed diverter equipment.
  • Had a good oil show in the samples from 520 ft.
  • Lost full returns at 650 ft. Attempts to regain
    circulation were futile. Resumed dry drilling
    with hole standing full but not circulating.
  • Topped an oil reservoir at 900 ft continued to
    drill to 960 ft. Began trip out of the hole.

50
Blowout Case History
  • Significant events pertaining to a blowout from a
    shallow oil well.
  • Well began to flow at some point in the trip. The
    flow was not detected until oil began to impinge
    on rotary table.
  • Poorly maintained FOSV could not be installed. No
    backup was available.
  • Panic ensued causing misuse of diverter. Off-duty
    personnel were not alerted.
  • Crews failed to don breathing equipment in
    presence of flowing hydrogen sulfide.
  • Failed to recognize that rig equipment was
    inadequate to control blowout that abandonment
    was in order.
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