Grace Robert. Advanced Blowout and Well Control
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226
Advanced
Blowout
and
Well
Control
psi less
than
the pressure required to pump into the zone
at
10,000
feet. Therefore, when pumping operations
commenced, the zone at the casing seat fractured and the
mud was pumped into
that
zone.
2.
The surface pressure after the bullheadmg operation was
100
psi more
than
the surface pressure before the pumping
job
(500
psi versus
400
psi) because the
25
bbl influx
had
risen during the pumping operation. (See Chapter
4
on
bubble rise for a further discussion
of
this
topic.)
There are other reasons that
a
bullheading operation can fail. For
example, after a well
has
been shut in, often the influx migrates
to
the
sufice, leaving drilling mud opposite the kick zone. Once pumping
begins, the surface pressure must
be
increased until the zone to be
bullheaded into is fractured by the drilling mud. The fracture pressure
may be several hundred
to
several thousand pounds per square inch above
the shut-in pressure.
This
additional pressure may
be
enough to rupture
the casing in the well and cause an underground blowout.
Sometimes bullheading operations are unsuccessful when
an
annulus in a well is completely filled with gas that is to be pumped back
into the formation. The reason for the failure in an instance such
as
this
is
that
the kill mud bypasses the gas in the annulus during the pumping
operation. Therefore, after the
kill
mud is pumped and the well is shut in
to observe the surface pressure, there is pressure at the surface and
gas
throughout the system, The result is that the well
unloads
and blows out
again.
Another consideration
is
the rate
at
which the mud being
bullheaded is pumped.
In the discussion concerning influx migration, it
was noted that the influx most commonly migrates up one side of the
annulus while the mud falls down the other side of the annulus. Further,
when the influx nears the surface, the velocity of migration
can
be very
high
as
evidenced by the rate
of
surface pressure increase. Under those
conditions, bullheading
at
!4
barrel per minute will not be successful
because the mud will simply bypass the migrating influx. This is
particularly problematic when the annulus area is large. The bullheading
rate may have to be increased
to
more
than
10
barrels per minute
in
order
Fluid
DyMmics
in
Well
Control
227
to be successfid.
In
any
event, the bullheading rate will have
to
be
increased until the shut-in surface pressure
is
observed
to
be decreasing
as
the mud
is
bullheaded into the annulus.
Bullheading
is
often
used in deep, high-pressure well control
situations
to
maintain
acceptable surface pressures.
Consider Example
5.2 during underground blowouts:
Example
5.2
Given:
Depth,
D
=
20,OOOfeet
Bottomhole pressure,
pb
=
20000psi
Casing
shoe
at,
DSh
=
10,OOOfeet
Fracture gradient
at
shoe,
5
=
0.9
psi/ft
The production is gas and the well
is
blowing out underground.
Required:
Approximate the surfice pressure if the gas is permitted to
migrate to the surface.
Determine the surface pressure
if
15-ppg mud
is
continuously
bullheaded into the
annulus.
Solution:
If the gas is permitted
to
migrate to the surface, the surface
pressure will
be
approximately
as
follows:
Pmg
=
(F,
-
0.1
O)Dsh,
Pmf
=
(0.90
-
0.1
O)(
10000)
p~g
=
8000
psi
228
Advanced
Blowout
and
Well
Control
With 15-ppg mud bullheaded from the surface to the casing shoe
at
10,000
feet, the surfhce pressure would
be
PSyf
=
8000
-
(0.052)(15)(10000)
Therefore,
as
illustrated in Example 5.2, without the bullheading
operation, the surface pressure would build
to
8000
psi. At that pressure
surface operations are very difficult at best. If 15-ppg mud is bullheaded
into
the
lost
circulation zone
at
the casing shoe, the surface pressure can
be reduced to
200
psi. With
200
psi
surface
pressure,
all
operations such
as
snubbing or wire line are considerably easier and faster.
In
summary,
bullheading operations
can
have unpleasant results
and should be thoroughly evaluated prior
to
commencing the operation.
Too
often,
crews
react
to
well control problems without analyzing the
problem and
get
into
worse condition
than
when the operation began.
Remember, the best well control procedure is one that has predictable
results from the technical
as
well
as
the mechanical perspective.
KILL-FLUID LUBRICATION -VOLUMETRIC KILL
PROCEDURE
Kill-Fluid Lubrication, also sometimes called the Volumetric Kill
Procedure, is
the
most overlooked well control technique. Lubricating
the
kill fluid into the wellbore involves an understanding of only the most
fundamental
aspects
of
physics. Basically, Kill-Fluid Lubrication is a
technique whereby the
influx
is replaced by the kill fluid while the
bottomhole pressure is maintained at or above the formation pressure.
The result of the proper Kill-Fluid Lubrication operation is that the influx
is removed from
the
wellbore, the bottomhole pressure is controlled by the
kill-mud hydrostatic and no additional influx is permitted during the
operation.
Fluid
Dynamics
in
Well
Control
229
Kill-Fluid Lubrication has application
in
a wide variety
of
operations. The only requirement is
that
the
influx
has migrated to the
surface or,
as
in some instances, the wellbore is completely void of drilling
mud, Kill-Fluid Lubrication
has
application in instances when the pipe is
on bottom, the pipe is part-way out of the hole or the pipe is completely
out of the hole. The technique is applicable in floating drilling operations
where the
rig
is
often
required, due
to
weather or some other emergency,
to
hang
off,
shut
in
and move
off
the hole. In each instance, the principles
are fundamentally the same.
Consider the following from
a
recent well control problem at
a
deep,
high-pressure operation
in
southeastern New Mexico.
A
kick was
taken while on a routine trip at 14,080 feet. The pipe
was
out of the hole
when the crew observed that the well was
flowing.
The crew ran
1,500
feet of drill string back into the hole. By that time the well was flowing
too hard for the crew
to
continue the trip into the hole
and
the well was
shut in.
A
sizable kick
had
been taken. Subsequently, the drillpipe was
stripped into the hole in preparation for
a
conventional kill operation.
However, the back-pressure valve, placed in the drill string
1,500
feet
above the bit to enable the drillpipe to
be
stripped into the hole,
had
become plugged during the stripping operation.
In
addition, during
the
time the snubbing unit was being
rigged
up and the drillpipe was being
stripped
to
bottom, the
gas
migrated
to
the surf8ce. The
influx
came from
a
prolific interval
at
13,913 feet. The zone
had
been drill-stem tested in
this
wellbore and
had
flowed
gas at
a
rate
of 10 mmscfpd with a flowing
surface pressure
of
5100 psi and
a
shut-in bottomhole pressure
of
8442
psi.
Since
it
was
not possible
to
circulate the influx out of the wellbore in
a classic manner,
kill
fluid was lubricated into the wellbore while efforts
were being made
to
remove the obstruction in the drillpipe. The
conditions
as
they existed at
this
location on that pleasant November
afternoon are schematically illustrated
in
Figure
5.3.
The following
example illustrates the proper procedure for lubricating kill fluid
into
a
wellbore:
230
Advanced
Blowout
and Well
Control
FRESH
&TOP
OF
MUD
AT
VIS
FT.
Pm
=
II.'I#/ML.
I
L
-
~-s/~'~~owFT.
n-ss
ST
hC
AT
4,-
FT.
-
TOC
ON
7"AT
S,SaO
PT.
Q
.:
IQ
MMSCFPD
AT
5,100
PSI
FTP
SIBHP
c
8.442
PSI
TOTAL
DEPTH
14,080
FT.
Figure
5.3
Examvle
5.3
Given:
Figure
5.3
Surface
pressure,
Mud
weight,
D
=
14,080feet
P,
=
1420psi
p
=
11.7ppg
Fluid Llynarnics in Well Control
231
Fracture gradient at
shoe,
Fg
=
0.702psiIft
Intermediate
casing:
7-inch
casing
@
29
#/ft
P-110
26
#/fi
S-95
29
#/ft
P-1 10
Gas
gravity,
Bottomhole pressure,
Temperature,
Kill-mud weight,
Compressibility factor,
Capacity
of
Drillpipe annulus,
Dsh
=
12,097feet
82 feet
7,800
feet
4,200
feet
sg
=
0.6
=
8442psi
=
54OORankine
A
=
12.8PPg
z,
=
0.82
Gpca
=
0.0264bbVfi
Drill-stem test
at
13,913 feet
Volume rate of flow,
Q
=
1Ommscfpd@51OOpsi
Plugged drillpipe at 12,513 feet
Required:
Design a procedure
to
lubricate kill mud
into
and the gas
influx
out of
the
annulus.
Solution:
Determine
the
height
of
the
gas
bubble,
h,
as
follows from
Equations 2.7
and
3.5:
232
Advanced Blowout
and
Well Control
5
=pfh+pm(D-h)+P,
s*P,
Pf
=
53.3zsT,
(0.6)(
1420)
”
=
53.3(0.82)(540)
Pf
=
0.035
pdft
Solve for,
h
,
using Equation
2.7:
8442
=
1420
+
(0.052)(11.7)(13913
-
h)
+
0.03
5h
h
=
2,520
feet
Gas
volume
at
the surface,
Y,
:
yS
=
(2520)(0.0264)
Y,
=
66.5
bbls
Determine the margin for pressure increase
at
the casing
shoe
using Equation
5.1
:
Where:
pShm
Pf
=
Influx
gradient,
psi/ft
=
Pressure at the
casing
shoe,
psi
nuid
Dynamics
in
Well
Control
233
h
pa
=
Annulus pressure, psi
Pln
Dshm
=
Height
of
the influx,
feet
=
Original
mud gradient,
psi/ft
=
Depth to the
casing
shoe,
fet
pJho4
=
0.036(2520) +1420+0.6087(12097-2520)
Pshw
=
7340
psi
Determine
maximum
permissible pressure at
shoe,
P
f.ac:
Ppac
=
(0.052)(
13.5)(
12097)
pfi~
=
8492
psi
Where:
Fg
=
Fracture gradient, psi/&
DSk
=
Depth
of
the
casing
shoe,
feet
Maximum
increase
in
surface pressure and
hydrostatic,
Mt,
that
will not result
in
fracturing
at the
shoe
is
given
by Equation
5.3
:
Ut
=
8492
-
7340
Mt
=
1152
psi
234
Advanced Blowout
and
Well Control
Where:
pfim
p,h,
=
Fracture pressure at
casing
shoe,
psi
=
Calculated pressure at
casing
shoe,
psi
The
volume
of
the kill-weight mud,
K,
with density,
p,,
to
achieve,
Mt,
is given by Equation
5.4:
0.667(66.5)
+
0.0264(1420+ 1 152)
Z(0.667)
x,
=
X,
=
84.150
r
1
152(0.0264)(66.5)
1:
1
F
=
84.150 84.1502
-
-1
0.667
=
20.5
bbls
Where:
Mt
=
Maximum surface pressure, psi
CdFa
=
Annular capacity, bbVft
Y,
=
Gas
volume at the sufice, bbl
Pm1
=
Kill mud gradient, psi/ft
X,
=
Intermediate
calculation
Fluid
Dynamics
in
Well
Control
235
Determine the effect
of
pumping
20
bbls
of
kill
mud with density
p,
=
12.8 ppg. The resulting additional hydrostatic,
myd
,
is
calculated with Equation
5.6:
Myd
=
(0.052)(12.8)
-
(0.:L!)
myd
=
504 psi
Additional surface pressure resulting
from
compressing
1
he
bubble at the surface with
20
bbls
of
kill mud
is
given by
Equation
2.3:
1
-
Prior
to
pumping
kill
mud
2
-
After pumping
kill
mud
Therefore, by modifjmg Equation
2.2