Grace Robert. Advanced Blowout and Well Control
Подождите немного. Документ загружается.
16
Advanced
Blowout
and Well
Control
TKE
CHOKE MANIFOLD
THE
VALVE ARRANGEMENT
A
typical choke manifold is illustrated in Figure
1.8.
The choke
line flanges into
a
studded cross with
two
gate valves attached to each
outlet of the studded cross. Only the outboard gate valves should be
operated routinely. The inboard valves should be used
as
safety valves in
the event the outboard valves cut out. Ball valves are not recommended in
these positions because ball valves
can
be
very difficult or impossible
to
close under adverse conditions. The manifold
as
illustrated in Figure
1.8
should be considered the
minimum
requirement for any well.
As
the well becomes more complex and the probability of well
control problems increases, redundancy in the manifold becomes a
necessity. The manifold shown in Figure
1.9
was recently rigged up on a
well control problem in the South Texas Gulf Coast.
As
illustrated in
Figure
1.9,
there were positions for four chokes
on
the manifold. Options
were good. Either side
of
the manifold could be the primary side. Since
each side
was
separately manifolded to individual separators, there
was
redundancy for every system in the manifold. Failure of any single
component of the manifold would not jeopardize the operation.
THE PANIC LINE
As
illustrated in Figure
1.9,
in the center of most land manifolds
is
a
“panic line.”
This
line is usually
4
inches or larger in diameter and
goes
straight to a flare pit. The idea
is
that, if the well condition
deteriorates
to
intolerable conditions, the well can
be
vented
to
the pit. It
is
a
good
idea when properly used and
a
bad idea when misused. For
example, in one
instance
the rig crew could not get the drilling choke
to
function properly and, in an effort
to
relieve the well, the panic line was
opened. However, an
effort
was made to hold back pressure on the well
with the valve on the panic line. The valve cut out
in
less
than
30
minutes,
making
the entire manifold inoperable. There was no choice but
to
shut in the well and
let
it blow out underground until the manifold could
be repaired.
Valves are made to be open or closed. Chokes are designed to
restrict flow. If the panic line is to be used, the line must be hlly opened
Equipment
in
Well
Control
17
to the flare pit.
A
better alternative
is
the manifold system
in
Figure
1.9.
As
rigged, the chokes can be opened through the manifolds
with
some
measure of control if desired or necessary.
To
Sepaotor
-
0
4
VW-lOOOO-psi
Gate
Volve
Q
Hydrautc
DriKing
Choke
@
MaudChoke
Q
Figure
1.9
-
4-11]
6-X-lO, OOO-psi
Choke
Manifold
THE
DRILLING
CHOKE
Outboard
of
the gate valves are the drilling chokes. The drilling
choke
is
the heart of the well control operation. Well control
was
not
routinely possible prior
to
the
advent of the modern drilling choke.
Positive chokes and production chokes were not designed for well control
operations and are not tough enough for well control operations.
Production chokes and positive chokes should not
be
included in the choke
manifold unless there is
a
specific production-well testing requirement.
Undcr well control conditions, the best production choke can cut out
in
a
18
Advanced
Blowout
and
Well
Control
few minutes.
In
addition, if the manifold is
spaced for a production choke, a welder will be
required
to
install
an
additional drilling choke if
it is needed. Obviously, it is not good practice
to weld on a manifold when well control
operations are in progress. If a production
choke is used in a manifold system, it is
recommended
that
the system be spaced in
order that an additional drilling choke can
readily
fit.
Even with
this
precaution, there
remains the problem of testing newly installed
equipment with the well control operation in
progress.
In
the late 1950s
a
company known
as
Drilling Well Control was active controlling
kicks with
a
series of skid-mounted separators.
Prior
to
this
technology,
it was not possible to
hold pressure
on
the annulus to control the well.
It
was
awkward at best with the separators.
The system was normally composed of
two
to
three
separators, depending on the anticipated
annulus pressures. The annulus pressure was
stepped down through the separators in
an
effort to maintain a specific annular pressure.
It represented
a
significant step forward in
technology but pointed to the specific need for a
drilling choke
that
could withstand the erosion
resulting from solids-laden multiphase flow.
The first effort was affectionately
known
as
the “horse’s a..” choke. The
nickname will
be
apparent
as
its working
mechanism is understood. The choke is
illustrated in Figure 1.10. Basically, it was
an
annular blowout preventer turned on its side.
The flow stream entered the rubber bladder.
The pressure on the well was maintained by
Figure
1.10
pressuring the back side of the bladder. The
solids would cut out the bladder, requiring
that
Equipment
in
Well
Control
19
the operator pay close attention
to
the pressures everywhere at the same
time, therefore
makmg
it
an
awkward choke
to
use.
In a short period of time, the technology of drilling chokes
advanced dramatically. There are several good drilling chokes available
to
the industry; however,
two
are presented in
this
text.
The first really
good choke, illustrated in Figure
1.1 1
,
was the SWACO Super Choke
with
two
polished plates
to
restrict flow. One plate is fixed
and
the other
is hydraulically rotated
to
open
or close the choke by rotating the opening
in one plate over the opening in the other plate. The choke
can
also be
operated manually in the event of loss of rig air, which is a feature not
offered by many other drilling chokes.
As
is the case with most drilling
chokes, the Super Choke is trimmed for sour environments. The polished
plates permit testing the choke
to
full working pressure
-
a feature not
offered by all drilling chokes. The SWACO Super Choke
has
a
history
of
being very reliable.
Figure
1.
I1
The Cameron Drilling Choke, illustrated in Figure
1.12,
consists
of
a
tungsten carbide cylinder and
a
tungsten carbide sleeve. Choking is
accomplished by moving the cylinder hydraulically into the sleeve. The
20
Cameron
Drilllng
Choke cannot
be
operated manually and cannot be
tested
to
full
working pressure. However, it
has
a long
history
of
reliability under the most adverse conditions.
The drilling choke is the heart of the well control operation.
This
is not the place
to
economize. There is no substitute for a good drilling
choke.
Install
it,
test
it, keep it in
good
wow order and know how it
works.
Advanced
Blowout
and Well
Control
Figure 1.12
THE
HEADER
Many equipment failures in well control operations occur between
the choke and the separator. With regard
to
the lines immediately
downstream from the chokes, the most common problem is erosion
resulting from insufficient size. They should
be
at
least
4
inches in
diameter in order
to
minimize
the velocity. Any abrupt change in the
diameter
will
cause
an
area
of
more severe erosion. These lines do not
have to be
high
pressure; however, they should have a yield strength of
80000
psi or greater in order that the
steel
will
be
harder
than
most of the
Equipment
in
Well
Control
21
particulate in the flow stream and resist erosion. Two-inch lines are too
small
for any operation and should not be used.
Consistently, a major problem is the header.
In
most manifold
assemblies, the entire system becomes inoperable when the header fails.
Consider Figures 1.13 and 1.14 which illustrate
a
header design common
to many operations.
The lines
between the choke manifold and the header were
2
inches outside diameter
which resulted in excessive velocities and the back side
of
the header was
eroded away by the jetting action of the flow stream
as
it entered the
header and expanded. Obviously, the well is out of control and must be
either vented or shut
in
to blow out underground, depending
on
the surf’e
pressure and casing design.
In
most instances, the well is shut in and an
underground blowout is the result.
Inadequate design between the chokes and the separators is
a
problem common
to
all oil fields. Conceptually, the header is intended to
connect the lines
from
the manifold to the separator. It is convenient to
manifold all the lines together into
a
header and into one line
to
the
separator.
The
result is
that
the entire operation depends upon the
integrity of
that
one header and line. In addition, that header and line
can
be subjected to severe operating conditions. In the past, the solution
attempts have been to install
a
target in the header opposite the incoming
line. Another approach
has
been
to
make the header much thicker. Many
use
a
combination of the aforementioned.
Figure 1.9 illustrates the best
alternative.
As
shown, each side of the manifold
has
a
separate header
and separator. With the manifold in Figure 1.9, there is redundancy in all
equipment except the choke line. If there is concern about the integrity of
the choke line, a second choke line must
be
installed
as
previously
described.
This
system failed for
two
reasons.
There are better alternatives.
22
Advanced
Blowout
and
Well
Control
b
L,
Figure
1.
I3
Figure
1.14
Equipment
in
Well
Control
23
Another
option,
which
is
illustrated
in
Figure
1.15,
is
that
the
header
is
above the lines
Coming
fiom
the choke and can be isolated by
full-opening ball valves. The
downstream
valve should be
at
least
5
diameters from the
tee.
With
this
arrangement,
the
flow
can
be
diverted
to
the header
or
to
the flare. The
wear
on
the header
is
significantly reduced
because the momentum
of
the fluid is broken by the
tee.
However, the
wall thickness
of
the header should be at least 14 inches and there should
be
flanged
targets opposite the
incoming
lines.
.
0
To
Secow3m-y
Me
Paic
Lm
to
Rm
To
Prky
chdv
(3
. .
. .
.
.
.
.
-
.
.
.
.
.
.
. .
.
t
To
%e
P&
Lim
b
*e
To
Fkrc
To
Aom
Figure
1.
IS
-
Alternative
Choke
Man
goid
In
Figure
1.15,
the primary choke
could
be
isolated
in the
event
of
a
failure by
closing
the valve in the header.
With
the valve
in
the
header
closed, the secondary choke could be utilized until the failed component in
the
primary
system
had
been repaired or replaced. The header
in
24
Advanced Blowout
and
Well Control
Figure 1.8 would be
minimally
acceptable provided that
a
valve
was
installed
in
the header to isolate one side of the choke manifold
from
the
other.
THE SEPARATOR
The
lines
from
the header to the separator and the separator itself
are areas where
problems
are
common.
The
problems begin
in
the line
Figure
1.16
-
Sepamtor
from the header to the separator.
This
line must be at
least
4
inches in
diameter, must be of constant diameter and must be straight or have
targeted
turns.
The targeted
turns
are more important in
this
section
of
Equipment
in
Well
Control
25
the manifold system than in the choke line because the velocities are
higher and erosion is
a
function of velocity. The direction of flow must be
into the target.
Rotary
hoses and other flexible hoses should not be used.
It should be at least
4
feet in
diameter and
8
feet
tall.
In
addition,
a
liquid level control valve is a
necessity.
Too
often, the separator consists of
a
piece of 30-inch casing
with
a
few baffles and no liquid level control. These “poor-boy”
separators are insufficient.
As
illustrated in the drilling report
at
the
beginning of
this
chapter, when gas comes
to
the su&ce, it is commonly
blown from around the bottom. In
a
difficult situation, gas and mud are
emitted through the gas line
as
well
as
the liquid line.
As
a
result, gas
accumulates on the mud pits and in other areas around the location,
creating
a
very hazardous condition.
The separators on most offshore operations are too small
and
poorly designed.
Gas
in the mud line offshore is particularly dangerous
since ventilation in the mud room is
often
limited.
A
good separator
design is illustrated in Figure 1.16.
Finally,
the
flare line
from
the separator
to
the flare boom, top of
the demck
or
bum pit should be straight and long enough
to
get the fire
a
comfortable distance away from the rig floor. Most flare lines are 6
inches
in diameter.
The separator must
be
BIG.
THE STABBING VALVE
On all rigs and work-over operations there should be a valve
readily accessible on the
rig
floor which is adapted to the tubulars. Such
a valve is routinely called
a
“stabbing valve.”
In
the event of
a
kick
during
a
trip, the stabbing valve is installed in the connection on the rig
floor
and
closed to prevent flow through the drill string. Ordinarily,
the
stabbing valve is a ball valve such
as
illustrated
in
Figure 1.17.