Transcript Petroleum Engineering 405 Drilling Engineering

PETE 411
Well Drilling
Lesson 24
Kicks and Well Control
1
Kicks and Well Control Methods
 The Anatomy of a KICK
 Kicks - Definition
 Kick Detection
 Kick Control
 (a)
 (b)
*
*
Dynamic Kick Control
Other Kick Control Methods
Driller’s Method
Engineer’s Method
2
Read:
Applied Drilling Engineering, Ch.4
HW #13
dc - Exponent
due Nov. 6, 2002
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4
5
6
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Causes of Kicks
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Causes of Kicks
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Causes of Kicks
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11
12
13
14
15
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What?
What is a kick?
 An unscheduled
entry of
formation
fluid(s) into the
wellbore
17
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?
( pW  pF )
 Mud density is too low
 Fluid level is too low - trips or lost circ.
 Swabbing on trips
 Circulation stopped - ECD too low
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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)
25
Kick Detection
4. Decrease in circulating pressure;
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
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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
Additional Information required:
Kick Data:
Original mud weight
Shut-in annulus press.
Shut-in drill pipe press.
Kick size
= 10.0 #/gal
= 600 psi
= 500 psi
= 30 bbl
(pit gain)
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Constant
Annular
Geometry.
Initial
conditions:
Kick has just
entered the
wellbore
Pressures
have
stabilized
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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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Calculate New Bottom Hole Pressure
PB = SIDPP + Hydrostatic Pressure in DP
= 500
+ 0.052 * 10.0 * 10,000
= 500 + 5,200
PB = 5,700 psig
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Calculate Pressure at Casing Seat
P4,000 = P0 + DPHYDR. ANN. 0-4,000
= SICP + 0.052 * 10 * 4,000
= 600 + 2,080
P4,000 = 2,680 psig
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Calculate EMW at Casing Seat
This corresponds to a pressure gradient of
2,680 psi
 0.670 psi/ft
4,000 ft
Equivalent Mud Weight (EMW) =
0.670
psi / ft
 12.88 lb/gal
0.052 (psi / ft )(lb / gal)
( rmud = 10.0 lb/gal )
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Calculate Initial Height of Kick
Annular capacity per ft of hole:
vx 

4

(D H  D P )L
2
2
gal
bbl
 (12.415  4.5 ) *12 in *
3
4
231 in 42 gal
2
2
3
 0.13006 bbls/ft
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Calculate Height of Kick
Height of kick at bottom of hole,
VB
30 bbl
hB 

 230.7 ft
v x 0.13006 bbl/ft
hB  231 ft
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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
PB = SICP + DPMA + DPKB
Drill String
PB = SIDPP + DPMD
600  0.052 *10
*(10,000- 231)  DPKB  500  (0.052*10*10,000)
600  5,080  DPKB  500  5,200
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Density of Kick Fluid
 DPKB  20 psi
 r KB
20

 1.67 lb/gal
0.052 * 231
(must be primarily gas!)
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Circulate Kick Out of Hole
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
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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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Top of Kick at Surface
As the kick fluid moves up the annulus, it
expands. If the expansion follows the gas law,
then
P0 V0
PB VB

Z 0n0RT0
ZBnBRTB
[surface ]
[bottom]
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Top of Kick at Surface
Ignoring changes due to compressibility
factor (Z) and temperature, we get:
P0 V0  PB VB
P0 v 0h0  PB v BhB
i.e.
P0h0  PBhB
Since cross-sectional area = constant
(v 0  v B  const .)
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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 + DPKO + DPMA
5,700 = Po + 20 + 0.052 * 10 * (10,000 - hO )
PB hB
5,700 - 20 - 5,200 = Po - 0.52 *
Po
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Top of Kick at Surface
480 P0  P0  0.52 * 5700 * 231
2
P0  480 P0  684684  0
2
 P0 
480 
480 2  4 * 684,684
2
P0  240  862  1,102 psi
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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 WORKSHEET
Division of PETE Dept., TAMU
College Station, TX 77843-3116
DATE:
TIME WELL CLOSED IN:
1. PRE-RECORDED INFORMATION
System Pressure Loss @ 40 stks
STROKES - Surface to Bit
TIME - Surface to Bit - 2,000 stks / 40 stks/min
= 1,200 psi
= 2,000 stks
=
50 min
2. MEASURE
Shut-in Drill Pipe Pressure (SIDPP)
Shut-in Casing Pressure (SICP)
Pit Volume Increase (Kick Size)
= 800 psi
= 1,100 psi
=
40 bbl
3. CALCULATE INITIAL CIRCULATING PRESSURE (ICP)
ICP = System Pressure Loss + SIDPP = 1,200 + 800 = 2,000 psi
4. 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 psi54
3,000
3,000
2,000
2,000
1,298
1,000
1,000
0
0
0
0
2,000
Final Circ. Press., FCP, psi
Initial Circ. Press., ICP, psi
Graphical Analysis
0
5
10
15
20
25
30
35
40
45
50
2,000
minutes
pump stks.
bbls
1,298
psi
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Csg
DS DS
Csg
Pressure When Circulating
2,000
1,298
Static Pressure
Driller’s
Method
800
2,000 stks
First Circulation
Second Circulation
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Csg
DS DS
Csg
Driller’s
Method
1,100
800
0 psi
800
Drillpipe Pressure
0 psi
Volume Pumped, Strokes
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1
3
4
Engineer’s
Method
2
5
6
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