Grace Robert. Advanced Blowout and Well Control
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36
Advanced Blowout
and
Well
Control
~~
Figure
2
I
-
Wellbore Schematic
Required:
Determine the
maximum
permissible surface pressure on the
annulus,
assuming
that
the
casing
burst
is
limited
to
80%
of
design specification.
Classic
Pressure
Control
Procedures
37
Solution:
80%
burst
=
0.8
(2470
psi)
=
1976
psi
Pr
=
P,
(Maximum)
+pmDsc
Where:
p.
=
Fracture pressure, psi
e
=
Annulus pressure, psi
Pm
=
Mud gradient, psi/ft
D,,
=
Depth
to
the casing shoe
Therefore:
P,(Maximum)
=
Pr
-p,,,D,,
=
0.76
(2000)
-
0.5
(2000)
=
520 psi
Therefore, the maximum permissible annular pressure
at
the
surhce is
520
psi, which is that pressure which would produce formation
fracturing
at
the casing seat.
Recording the gain in pit volume, drillpipe pressure and annulus
pressure initially and over time
is
very important to controlling the kick.
As
will be seen in the discussion of special problems in Chapter
4,
the
surface pressures are critical for determining the condition of the well and
the potential success of the well control procedure. Analysis of the gain in
the surface volume in consideration of the casing pressure is critical in
defit.ung the potential for
an
underground blowout.
In
some instances, due
to a lack of familiarity with the
surface
equipment, the crew
has
failed
to
shut in the well completely. When the pit volume continued to increase,
the oversight was detected and the well shut in. Recording the surface
pressures over time is extremely important.
Gas
migration, which is also
discussed in Chapter
4,
will
cause
the surfke pressures
to
increase over
38
Advanced
Blowout
and
Well
Control
time. Failure to recognize the resultant superpressuring can result in the
failure
of the well control procedure.
These procedures are hdamental to pressure control and
represent the most singularly important aspect of pressure control. They
are the responsibility
of the rig crew and should be practiced and studied
until they become
as
automatic
as
breathing. The entire operation
depends upon the ability
of the driller and crew to react to
a
critical
situation. Now, the well is under control and
the
kill operation
can
proceed to circulate out the influx.
CIRCULATING OUT
THE
INFLUX
THEORETICAL CONSIDERATIONS
Gas
Expansion
Prior to the early
1960s,
an
influx
was circulated to the surface
by keeping the pit level constant.
This
was
also
known
as
the Barrel In
-
Barrel Out
Method.
Some insist on using
this
technique today although it
is
no
more successll now
than
then. If the influx
was
mostly liquid,
this
technique
was
successfid. If the
influx
was mostly gas, the results were
disastrous.
When
a
proponent of the Constant Pit Level
Method
was
asked about the results, he replied,
“Oh,
we just keep pumping until
something breaks!” Invariably, something did break,
as
illustrated in the
drilling report at the beginning
of
this
chapter.
In
the late
1950s
and early
1960s
some began to realize that
this
Barrel In
-
Barrel Out technique could not be successful. If the influx was
gas, the
gas
had
to
be permitted
to
expand
as
it
came to the surface. The
basic relationship
of
gas
behavior is given in Equation
2.2:
PV
=
mRT
(2.2)
Where:
P
=
Pressure,
ptia
V =Volume,ft
z
=
Compressibility fkctor
Classic
Pressure
Control
Procedures
39
n
=
Number of moles
R
=
Units
conversion constant
T
=
Temperature, 'Rankine
For the purpose of studying gas under varying conditions,
the
general relationship
can
be
extended to another
form
as
givcn in
Equation
2.3:
1'
2-
Denotes conditions at any point
Conditions at any point other
than
point 1
By neglecting changes in temperature,
T,
and compressibility
fxtx,
z
,
Equation
2.3
can
be
simplified into Equation
2.4
as
follows:
(2.4)
In
simple language, Equation
2.4
states
that
the pressure of a gas
multiplied by the volume of the gas is constant. The significance of gas
expansion in well control is illustrated by Example
2.2:
Example
2.2
Given:
Wellbore schematic
=
Figure
2.2
Mud density,
P
=
9.6PPg
Mud gradient,
P,
=
0.5
psi/ft
Well depth,
D
=
10,000 feet
Conditions described in Example 2.1
Assume that the wellbore is
a
closed container.
Assume that
1
cubic foot of
gas
enters the wellbore.
40
Advanced
Blowout
and
Well
Control
Assume that gas
enters
at the bottom of the hole, which
is
point
1.
Figure
2.2
-
Wellbore
Schematic
-
Closed Container
Required:
1.
Determine the pressure in the gas bubble at point
1.
2.
Assuming
that the
1
cubic foot of gas migrates to the
surface
of
the closed container (point
2)
with
a
constant
volume
of
1
cubic foot, determine the pressure at the
Classic
Pressure Control Procedures
41
surface, the pressure at
2,000
feet,
and
the pressure at
10,000
feet.
Solution:
1.
The pressure of the
gas,
4,
at point
1,
which
is
the
bottom
of
the hole,
is
determined
by
multiplying the
gradient
of
the
mud
(psi./ft)
by
the depth
of
the well.
4
=
0.5
(10000)
2.
The pressure in the
1
cubic
foot of gas at the surface
(point
2)
is
determined
using
Equation
2.4:
(5000)(
1)
=
Pa(
1)
Pa&-
=
5000 psi
Determine the pressure at
2,000
feet:
pzooo
=
p2
+pm(2000)
pZooo
=
5000
+
0.5(
2000)
PZm
=
6000
psi
42
Advanced
Blowout
and Well Control
Determine the pressure
at
the bottom of the hole.
4:oooo
=
p,(
10000)
<m
=
5000
+
0.5(
10000)
As illustrated in Example 2.2, the pressures
in
the well become
excessive when the gas is not permitted to expand. The pressure at 2,000
feet
would build
to
6000
psi if the wellbore was
a
closed container.
However, the wellbore is not
d
closed container and the pressure required
to
fiacture the wellbore
at
2,000 feet is 1520 psi.
When
the pressure at
2,000
feet exceeds
1520
psi, the container will rupture, resulting
in
an
underground blowout.
The goal
in
circulating out a gas influx is to bring the gas
to
the
surfhce, allowing the
gas
to
expand to avoid rupturing the wellbore.
At
the same time, there is the need to maintain the total hydrostatic pressure
at the bottom of the hole at the reservoir pressure
in
order to prevent
additional influx
of
formation fluids.
As
will be seen, classical pressure
control procedures routinely honor the second condition
of maintaining the
total hydrostatic pressure at the bottom of the hole equal to the reservoir
pressure and ignore any consideration of the fi-acture pressure at the
shoe.
The
U
-
Tube
Model
All classical displacement procedures are based on the U-Tube
Model illustrated
in
Figure
2.3.
It is important to understand this model
and premise. Too
often,
field personnel attempt
to
apply classical well
control procedures
to
non-classical problems. If the U-Tube Model does
not accurately describe the system, classical pressure control procedures
cannot be relied upon.
As
illustrated
in
Figure 2.3, the left side of the U-Tube represents
the drillpipe while the right side
of
the U-Tube represents the annulus.
Therefore, the U-Tube Model describes a system where the bit is on
Classic
Pressure
Control
Procedures
43
bottom and
it
is
possible to circulate from bottom.
If
it
is
not possible to
circulate from bottom, classical well control concepts are meaningless and
not applicable.
This
concept
is
discussed in detail in Chapter
4.
DRILLPIPE
Figure
2.3
-
The
U-Tube
Model
As
hrther illustrated in Figure
2.3,
an
influx of formation fluids
has
entered the annulus (right side
of
the U-Tube). The well has been shut
in,
which means
that
the system has been closed. Under these shut-in
conditions, there is static pressure on the drillpipe, which is denoted by
Pdp,
and static pressure on the annulus which
is
denoted by
Pa.
The
formation fluid,
Py,
has
entered the annulus and occupies
a
volume
defined by the
area
of
the annulus and the height, h, of the influx.
An
inspection
of
Figure
2.3
indicates that the drillpipe side
of
the
U-Tube Model is more simple to analyze
since
the pressures are
only
influenced by mud of
known
density and pressure
on
the drillpipe that is
easily measured. Under static conditions, the bottomhole pressure is
easily determined utilizing Equation
2.6:
44
Advanced
Blowout
and
Well
Control
Where:
pb
=
Bottomhole pressure, psi
Pm
=
Mud &radlent, psi/ft
D
=Well depth, feet
pdp
=
Shut-in drillpipe pressure, psi
Equation
2.6
describes the shut-in bottomhole pressure in terms of
the total hydrostatic on the drillpipe side
of
the U-Tube Model. The shut-
in bottomhole pressure
can
also
be
described in
terms
of the
total
hydrostatic pressure on the annulus side of the U-Tube Model
as
illustrated by Equation
2.7:
Where:
pb
=
Bottomhole pressure, psi
Pm
=
Mud &radlent, psi/ft
D
=Well depth, feet
pa
Pf
h
=
Shut-in casing pressure, psi
=
Gradient of influx, psi/ft
=
Height of the influx, feet
Classic well control procedures, no matter what terminology
is
used, must keep the shut-in bottom hole pressure,
4,
constant
to
prevent
additional
influx
of formation fluids while displacing the initial influx to
the surfhce. Obviously, the equation for the drillpipe side (Equation
2.6)
is the simpler
and
all of the variables are
known;
therefore, the drillpipe
side is used
to
control the bottomhole pressure, 5.
With the advent
of
pressure control
technology,
the necessity
of
spreading that technology presented
an
awesome
task.
Simplicity was in
order and the classic Driller’s Method for displacing the influx
from
the
wellbore without permitting additional influx was developed.
Classic
Pressure
Control
Procedures
45
DRILLER’S
METHOD
minimal
calculations. The
recommended
procedure
is
as
follows:
The Driller’s
Method
of
displacement
is
simple and requires
Step
1
On
each
tour,
read and record the standpipe pressure at several
rates
in
strokes
per minute (spm), including the anticipated
kill
rate
for each pump.
step
2
After a kick
is
taken and prior to pumping, read and record the
drillpipe
and
casing
pressures.
Determine
the
anticipated pump
pressure at the kill rate
using
Quation
2.8:
pc=P,+P+
Where:
pc
pis
pdp
=
Circulating pressure during displacement,
psi
=
Recorded pump pressure at
the
kill
rate, psi
=
Shut-in drillpipe pressure, psi
Important!
If
in doubt at any time during the entire procedure,
shut
in the well, read and record the shut-in drillpipe pressure and
the
shut-in
casing pressure and prd accordmgly.
step
3
Bring the pump
to
a
kill
speed,
keeping the casing pressure
constant
at
the shut-in casing pressure.
This
step
should require
less
than
five
minutes.
Step
4
Once
the pump
is
at a satisfactory
kill
speed, read and record
the
drillpipe pressure. Displace the influx,
keeping
the recorded
drillpipe pressure constant.