Grace Robert. Advanced Blowout and Well Control
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216
severe erosion is
certain.
Plusging and bridging are probable in some
areas and
cm
result
in
flow
outside the casing
and
in cratering. Advances
in
diverters
and
diverter system design have improved surface diverting
operations substantially.
Advanced
Blowout
and
Well Control
Special
Conditions, Problems
and
Pmedures in Well
Control
217
References
1.
Grace,
Robert
D., “Further Discussion
of
Application
of
Oil
Muds,” SPE Drilling Engineering, September 1987, page 286.
2.
OBryan,
P.L. and Bourgoyne, A.T., “Methods for Handling
Drilled
Gas
in Oil Muds,” SPE/IADC #16159, SPE/IADC
Drilling Conference held in New
Orleans,
LA, 15-18 March,
1987.
3.
OBryan
P.L. and Bourgoyne,
A.T.,
”Swelling of Oil-based
Drilling Fluids Due to Dissolved
Gas,”
SPE 16676, presented at
the 62nd
Annual
Technical Conference and Exhibition
of
the
Society
of
Petroleum Engineers held in Dallas,
TX,
27-30
September, 1987.
4..
O’Bryan, P.L. et.
al.,
“An
Experimental Study
of
Gas Solubility
in
Oil-base
Drilling
Fluids,”
SPE #15414 presented at the 61st
Annual
Technical
Conference and Exhibition of the Society of
Petroleum Engineers held in New Orleans, LA, 5-8 October,
1986.
5.
Thomas, David C., et.
al.,
“Gas
Solubility in Oil-based Drilling
Fluids: Effects on Kick Detection,” Journal
of Petroleum
Technolom, June 1984, page 959,
CHAPTER
FIVE
FLUID DYNAMICS
IN
WELL CONTROL
The use of kill fluids in well control operations is not new.
However, one of the newest
technical
developments
in
well control is the
engineered application of fluid dynamics. The technology of fluid
dynamics is not fully utilized because most personnel involved in well
control operations do not understand the engineering applications and do
not have the capabilities to apply the technology
at
the rig in the field.
The best well control procedure is the one that has predictable results
from a technical
as
well
as
a mechanical perspective.
Fluid dynamics have an application in virtually every well control
operation. Appropriately applied, fluids can
be
used cleverly to
compensate for unreliable tubulars or inaccessibility. Often, when
blowouts occur, the tubulars are damaged beyond expectation. For
example, at a blowout in Wyoming an intermediate casing string subjected
to excessive pressure was found by survey
to
have filed in
NINE
places.'
One failure is understandable. Two failures are imaginable, but
NINE
failures in one string of casing????? After
a
blowout in South Texas, the
9 Y8-inch surface casing
was
found
to
have parted at
3,200
fect and
again at 1,600
feet.
Combine conditions such
as
just described with the
intense heat resulting
from
an oil-well fire or damage resulting
from
a
falling derrick or collapsing substructure and it is easy
to
convince the
average engineer that after
a
blowout the wellhead and tubulars could be
expected
to
have little integrity. Properly applied, fluid dynamics can
offer solutions which do not challenge the integrity of the tubulars in the
blowout.
The applications of fluid dynamics to
be
considered are:
1.
Kill-Fluid Bullheadmg
2.
Kill-Fluid Lubrication
3.
Dynamic Kill
4.
Momentum Kill
218
FIuidDynamics
in
Well
Control
219
KILL-FLUID
BULLHEADING
“Bullheading” is the pumping of the kill fluid into the well against
any pressure and regardless of any resistance the well may offer. Kill-
fluid bullheading is one of the most common misapplications of fluid
dynamics. Because bullheading challenges the integrity of the wellhead
and tubulars, the result
can
cause firther deterioration
of
the condition of
the blowout. Many times wells have
been
lost, control delayed or options
eliminated by the inappropriate bullheading of kill fluids.
Consider the following for an example
of
a
proper application of
the bullheading technique. During the development of the Ahwaz Field in
Iran in the early 1970s, classic pressure control procedures were not
possible. The producing horizon
in
the Ahwaz Field is
so
prolific that
thc
difference between circulating and loosing circulation is a few psi. The
typical wellbore schematic is presented
as
Figure
5.1.
Drilling in the pay
zone was possible by delicately balancing the hydrostatic with the
formation pore pressure.
The
slightest underbalance resulted in a
significant kick. Any classic attempt
to
control the well
was
unsuccesshl
because even the slightest back pressure at the surface caused
lost
circulation at the 9 5/8-inch casing shoe. Routinely, control was regained
by increasing the weight of two hole volumes of mud
at
the surface by
.1
to
.2
ppg and pumping down the annulus
to
displace the influx and several
hundred barrels of mud into the productive formation. Once the influx
was
displaced, routine drilling operations were resumed.
After the blowout at the Shell Cox in the Piney
Woods
of
Mississippi, a similar procedure was adopted
in
the
deep
Smackover tests.
In
these operations, bringing the formation fluids to the surface was
hazardous due to the high pressures and
high
concentrations of hydrogen
sulfide.
In
response to the challenge, casing was
set
in the top of the
Smackover. When
a
kick was
taken,
the influx was overdisplaced back
into the Smackovcr by bullheading kill-weight mud down the annulus.
The common ingredients of success
in
these two examples are
pressure, casing
seat,
and kick size. The surfice pressures required
to
pump into the formation were low because the kick sizes were always
small. In addition, it was of no consequence that the formation was
fractured
in the process and damaged by the mud pumped.
The
most
important aspect was the casing seat. The casing
that
sat at the top of the
220
productive interval in each example ensured that the
kill
mud
as
well
as
the
influx would be forced back into
the
interval
from
which the kick
occurred.
It
is
most
important
to
understand that, when bullheadmg, the
kill
fluid will almost always exit
the
wellbore at the casing
seat.
Advanced
Blowout
and
Well
Control
PROLIFIC
PRODUCTIVE:
fWRMATION
Figure
5.
I
-
Ahwaz
Field
FluidDynamics
in
Well
Control
221
Consider
an
example
of
misapplication
from
the Middle East:
Eramole
5.1
Given:
Figure
5.2
Depth,
D
=
10,OOOfeet
Mud weight,
P
=
1oPPg
Mud gradient,
Pm
=
O.O52psi/f€
Gain
=
25
bbl
Hole size,
D,,
=
8 %inches
Intermediate casing
(9
5/8-inch)
=
5,000
feet
Fracture gradient,
<
=
0.65psiJft
Fracture pressure:
@
5,000
ft,
pfiam
=
3250psi
@
10,000
ft,
~j~odoooo
=
6500psi
Shut-in annulus pressure,
Drillpipe
Internal diameter,
Drill collars:
Gas
specific
gravity,
Temperature
sent
=
4OOpsi
=
4%inch
Dj
=
3.826inch
=
800feet
=
sg
=
0.60
6 inches
x
2.25
inches
=
1.2°/100
ft
222
Advanced
Blowout
and Well Control
Ambient temperature
=
60°F
Compressibility factor,
z
=
1.00
Capacity
of
Drill collar annulus,
cd&
=
0.0352
bbVft
Drillpipe,
Cd*
=
0.0506bbVft
The decision
was
made to weight up the mud to the kill weight
and displace
down
the annulus
since
the drillpipe
was
plugged.
From Figure
5.2
and Equation
2.7:
and from Equation
3.7:
Influx
Volume
‘dcho
hb=
=
710
feet
and fiom Equation
3.5:
Fluid
Wamics
in Well Control
223
FRACTURE
GRADIENT
AT
THE
SHOE
~0.65
PSI/FT
-Pa
~400
PSI
Figure
5.2
I
-
9-5/8"
CSG
AT
5,000
FT.
-
710
FT.
OF
GAS
25
BBI.
GAW
PRODUCTIVE
JNTERVAL
-
T.D.
l0,OOO
FT.
BHP
5,300
PSI
224
Advanced
Blowout
and
Well
Control
Pf
=
53.3(1.0)(640)
(0.6)(5200)
Pf
=
0.091
pdil
Therefore:
pb
=
400+0.52(10000-710)+(0.091)(710)
pb
=
5295
psi
The kill-mud weight would then be given from Equation 2.9:
4
”
=
0.0520
5295
’‘
=
(10000)(0.052)
The annular capacity:
Capcity
=
(9200)(0.0506)
+
(800)(0.0352)
Capacity
=
494
bbls
As
a
result
of
these calculations,
500
barrels
of
mud
was
weighted up
at
the surface to
the
kill
weight
of
10.2 ppg
and
pumped down the annulus. After pumping the
500
barrels
of
10.2ppg
mud,
the well
was-shut
in
and
surface
pressure was
FIuid
Qynamics
in
Well
Control
225
observed to be
500
psi, or 100 psi more
than
the
400
psi
originally observed!
Required:
1. Explain the cause of the failure of the bullhead operation.
2.
Explain the increase in the
surfixe
pressure.
Solution:
1.
The pressure at
5,000
feet
is
given by:
psm
=
(0.052)(10.0)(5000)
+400
psm
=
3000
psi
The fracture gradient at
5,000
feet
is
3,250
psi.
Therefore the difference is
A&,
=
3250-3000
AF&
=25Opsi
The pressure
at
10,000 feet is
5,296
psi. The fracture
went
at
10,000 feet is
6,500
psi. Therefore the
difference is
gm
=
6500-5296
M,oooo
=1204psi
The pressure required to pump into the zone at the
casing
shoe
was
only
250
psi above the shut-in pressure
and
954