1 PETE 411 Well Drilling Lesson 3 The Rig - Drilling Equipment.
PETE 411 Well Drilling
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Transcript of PETE 411 Well Drilling
1
PETE 411
Well Drilling
Lesson 24
Kicks and Well Control
2
Kicks and Well Control Methods
The Anatomy of a KICK Kicks - Definition Kick Detection
Kick Control (a) Dynamic Kick Control (b) Other Kick Control Methods
* Driller’s Method
* Engineer’s Method
3
Read:
Applied Drilling Engineering, Ch.4
HW #13dc - Exponent
due Nov. 6, 2002
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5
6
7
8
Causes of Kicks
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Causes of Kicks
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Causes of Kicks
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12
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14
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What?
What is a kick?
An unscheduled entry of formation fluid(s) into the wellbore
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Why?
Why does a kick occur?
The pressure inside the wellbore is lower than the formation pore pressure (in a permeable formation).
pw < pf
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How?
How can this occur?
Mud density is too low
Fluid level is too low - trips or lost circ.
Swabbing on trips
Circulation stopped - ECD too low
)pp( FW
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What ?
What happens if a kick is not controlled?
BLOWOUT !!!
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Typical Kick Sequence
1. Kick indication
2. Kick detection - (confirmation)
3. Kick containment - (stop kick influx)
4. Removal of kick from wellbore
5. Replace old mud with kill mud (heavier)
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Kick Detection and Control
Kick Detection Kick Control
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1. Circulate Kick out of hole
Keep the BHP constant throughout
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2. Circulate Old Mud out of hole
Keep the BHP constant throughout
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Kick Detection
Some of the preliminary events that may be associated with a well-control problem, not necessarily in the order of occurrence, are:
1. Pit gain;
2. Increase in flow of mud from the well
3. Drilling break (sudden increase in drilling rate)
26
Kick Detection
5. Shows of gas, oil, or salt water
6. Well flows after mud pump has been shut down
7. Increase in hook load
8. Incorrect fill-up on trips
4. Decrease in circulating pressure;
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Dynamic Kick Control[Kill well “on the fly”]
For use in controlling shallow gas kicks
No competent casing seat No surface casing - only conductor Use diverter (not BOP’s) Do not shut well in!
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Dynamic Kick Control
1. Keep pumping. Increase rate!
(higher ECD)
2. Increase mud density
0.3 #/gal per circulation
3. Check for flow after each
complete circulation
4. If still flowing, repeat 2-4.
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Dynamic Kick Control
Other ways that shallow gas kicks
may be stopped:
1. The well may breach with the
wellbore essentially collapsing.
2. The reservoir may deplete to the
point where flow stops.
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Conventional Kick Control{Surface Casing and BOP Stack are in place}
Shut in well for pressure readings.
(a) Remove kick fluid from wellbore;
(b) Replace old mud with kill weight mud
Use choke to keep BHP constant.
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Conventional Kick Control
1. DRILLER’S METHOD
** TWO complete circulations **
Circulate kick out of hole using old mud
Circulate old mud out of hole using kill weight mud
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Conventional Kick Control
2. WAIT AND WEIGHT METHOD
(Engineer’s Method)
** ONE complete circulation **
Circulate kick out of hole using kill weight mud
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Driller’s Method - Constant Geometry
Information required:
Well Data:
Depth = 10,000 ft.
Hole size = 12.415 in. (constant)
Drill Pipe = 4 1/2” O.D., 16.60 #/ft
Surface Csg.: 4,000 ft. of 13 3/8” O.D. 68 #/ft
(12.415 in I.D.)
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Driller’s Method - Constant Geometry
Kick Data:
Original mud weight = 10.0 #/gal
Shut-in annulus press. = 600 psi
Shut-in drill pipe press. = 500 psi
Kick size = 30 bbl (pit gain)
Additional Information required:
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Constant Annular
Geometry.
Initial conditions:
Kick has just entered the
wellbore
Pressures have
stabilized
SIDPP = 500 psi
SICP = 600 psi
4,000 ft
10,000 ft
DP OD= 4.5 in
Hole dia= 12.415 in
AnnularCapacity= 0.13006
bbl/ft
231 ft
BHP = 5,700 psig
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Successful Well Control
1. At no time during the process of removing the kick fluid from the wellbore will the pressure exceed the pressure capability of
the formation the casing the wellhead equipment
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Successful Well Control
2. When the process is complete the wellbore is completely filled with a fluid of sufficient density (kill mud) to control the formation pressure.
Under these conditions the well will not flow when the BOP’s are opened.
3. Keep the BHP constant throughout.
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Calculations
From the initial shut-in data we can calculate:
Bottom hole pressure
Casing seat pressure
Height of kick
Density of kick fluid
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PB = SIDPP + Hydrostatic Pressure in DP
= 500
+ 0.052 * 10.0 * 10,000
= 500 + 5,200
PB = 5,700 psig
Calculate New Bottom Hole Pressure
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Calculate Pressure at Casing Seat
P4,000 = P0 + PHYDR. ANN. 0-4,000
= SICP + 0.052 * 10 * 4,000
= 600 + 2,080
P4,000 = 2,680 psig
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This corresponds to a pressure gradient of
Equivalent Mud Weight (EMW) =
psi/ft 670.0ft
psi
000,4
680,2
lb/gal 88.12)gal/lb)(ft/psi(
ft/psi
052.0
670.0
Calculate EMW at Casing Seat
mud = 10.0 lb/gal )
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Annular capacity per ft of hole:
bbls/ft 0.13006
gal 42
bbl
in 231
gal*in 12*)5.4415.12(
4
L)DD(4
v
3322
2P
2Hx
Calculate Initial Height of Kick
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ft 231
ft 7.230bbl/ft 0.13006
bbl 30
v
Vh
x
BB
hole, of bottomat kick ofHeight
Calculate Height of Kick
hB
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Calculate Density of Kick Fluid
The bottom hole pressure is the pressure at the surface plus the total hydrostatic pressure between the surface and the bottom:
Annulus Drill String
PB = SICP + PMA + PKB PB = SIDPP + PMD
600 0 052 10
. *
*(10,000 - 231) P 500 (0.052 *10*10,000)KB
600 5,080 P 500 5,200KB
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Density of Kick Fluid
(must be primarily gas!)
lb/gal 67.1231*052.0
20KB
P psiKB 20
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NOTE:
The bottom hole pressure is kept constant while the kick fluid is circulated out of the hole!
In this case
BHP = 5,700 psig
Circulate Kick Out of Hole
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Constant Annular
Geometry
Driller’s Method.
Conditions When Top of Kick Fluid Reaches the Surface
BHP = const.
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49
Top of Kick at Surface
As the kick fluid moves up the annulus, it expands. If the expansion follows the gas law, then
[bottom] ]surface[
RTnZ
VP
RTnZ
VP
BBB
BB
000
00
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Top of Kick at Surface
Ignoring changes due to compressibility factor (Z) and temperature, we get:
Since cross-sectional area = constant
.)constv(v
hPhP .e.i
hvPhvP
VPVP
B0
BB00
BBB000
BB00
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Top of Kick at Surface
We are now dealing two unknowns, P0 and h0. We have one equation, and need a second one.
BHP = Surface Pressure + Hydrostatic Head
5,700 = Po + PKO + PMA
5,700 = Po + 20 + 0.052 * 10 * (10,000 - hO )
5,700 - 20 - 5,200 = Po - 0.52 * o
BB
P
hP
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Top of Kick at Surface
psi 102,1862240P
2
684,684*4480480P
0684684P 480P
231*5700*52.0PP 480
0
2
0
02
0
200
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Well Control Worksheet
Example:
When circulating at a Kill Rate of 40 strokes per
minute, the circulating pressure = 1,200 psi
The capacity of the drillstring = 2,000 strokes
Mud Weight = 13.5 lb/gal
Well Depth = 14,000 ft
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Aggie Drilling Research PRESSURE CONTROL WORKSHEETDivision of PETE Dept., TAMU DATE: College Station, TX 77843-3116 TIME WELL CLOSED IN:
1. PRE-RECORDED INFORMATION System Pressure Loss @ 40 stks = 1,200
psi STROKES - Surface to Bit = 2,000 stks TIME - Surface to Bit - 2,000 stks / 40 stks/min = 50 min
2. MEASURE Shut-in Drill Pipe Pressure (SIDPP) = 800
psi Shut-in Casing Pressure (SICP) = 1,100 psi Pit Volume Increase (Kick Size) = 40 bbl
3. CALCULATE INITIAL CIRCULATING PRESSURE (ICP) ICP = System Pressure Loss + SIDPP = 1,200 + 800 = 2,000
psi4. CALCULATE KILL MUD DENSITY (New MW) Mud Weight Increase = SIDPP / (0.052 * Depth) = 800/(0.052*14,000) = 1.10 lb/gal
Kill Mud Density (New MW) = Old MW + MW Increase = 13.5 + 1.10 = 14.6 lb/gal
5. CALCULATE FINAL CIRCULATING PRESSURE (FCP) FCP = System Pressure Loss * (New MW / Old MW)
= 1,200 * (14.6 / 13.5) = 1,298 psi
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1,298
0
Graphical Analysis
Fin
al C
irc.
Pre
ss.,
FC
P,
ps
i
Init
ial C
irc
. Pre
ss
., IC
P,
psi
3,000
2,000
1,000
0
3,000
2,000
1,000
0 5 10 15 20 25 30 35 40 45 50 minutes
0 2,000 pump stks.
0 bbls
2,000 1,298 psi
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Csg DS DS Csg
Pressure When Circulating
Static Pressure
First Circulation Second Circulation
Dri
llPip
e P
ress
ure
Driller’sMethod
1,298
2,000
800
2,000 stks
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Csg DS DS CsgC
asi n
g P
r ess
ur e
Volume Pumped, Strokes
Drillpipe Pressure
Driller’sMethod
800
1,100
0 psi
800
DP
Pr e
ss.
0 psi
58
1
65
43
2
Engineer’sMethod