Note: Descriptions are shown in the official language in which they were submitted.
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SEGREGATING FLOWABLE MATERIALS IN A WELL
TECHNICAL FIELD
The present disclosure relates generally to equipment
and flowable materials utilized, and operations performed,
in conjunction with a subterranean well and, in one example
described below, more particularly provides for wellbore
pressure control with segregated fluid columns.
BACKGROUND
In various different types of well operations, it can
be beneficial to be able to isolate one flowable substance
from another. In the past, this function has generally been
performed by equipment, such as, plugs, packers, etc.
It will be appreciated that improvements are
continually needed in the art of isolating flowable
substances from one another. The improvements could be used
in drilling, completion, abandonment and/or in other types
of well operations.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a representative partially cross-sectional
view of a system and associated method which can embody
principles of the present disclosure.
FIG. 2 is a representative view of a pressure and flow
control system which may be used with the system and method
of FIG. 1.
FIG. 3 is a representative cross-sectional view of the
system in which initial steps of the method have been
performed.
FIG. 4 is a representative cross-sectional view of the
well system in which further steps of the method have been
performed.
FIG. 5 is a representative view of a flowchart for the
method.
FIG. 6 is a representative cross-sectional view of
another example of the system and method.
DETAILED DESCRIPTION
Representatively and schematically illustrated in FIG.
1 is a system 10 for use with a well, and an associated
method, which system and method can embody principles of
this disclosure. The FIG. 1 example is configured for
underbalanced or managed pressure drilling, but it should be
clearly understood that this is merely one example of a well
operation which can embody principles of this disclosure.
In the system 10, a wellbore 12 is drilled by rotating
a drill bit 14 on an end of a tubular string 16. Drilling
fluid 18, commonly known as mud, is circulated downward
through the tubular string 16, out the drill bit 14 and
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upward through an annulus 20 formed between the tubular
string and the wellbore 12, in order to cool the drill bit,
lubricate the tubular string, remove cuttings and provide a
measure of bottom hole pressure control. A non-return valve
21 (typically a flapper-type check valve) prevents flow of
the drilling fluid 18 upward through the tubular string 16
(e.g., when connections are being made in the tubular
string).
Control of bottom hole pressure is very important in
managed pressure and underbalanced drilling, and in other
types of well operations. Preferably, the bottom hole
pressure is accurately controlled to prevent excessive loss
of fluid into an earth formation 64 surrounding the wellbore
12, undesired fracturing of the formation, undesired influx
of formation fluids into the wellbore, etc.
In typical managed pressure drilling, it is desired to
maintain the bottom hole pressure just greater than a pore
pressure of the formation 64, without exceeding a fracture
pressure of the formation. In typical underbalanced
drilling, it is desired to maintain the bottom hole pressure
somewhat less than the pore pressure, thereby obtaining a
controlled influx of fluid from the formation 64.
Nitrogen or another gas, or another lighter weight
fluid, may be added to the drilling fluid 18 for pressure
control. This technique is especially useful, for example,
in underbalanced drilling operations.
In the system 10, additional control over the bottom
hole pressure is obtained by closing off the annulus 20
(e.g., isolating it from communication with the atmosphere
and enabling the annulus to be pressurized at or near the
surface) using a rotating control device 22 (RCD). The RCD
22 seals about the tubular string 16 above a wellhead 24.
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Although not shown in FIG. 1, the tubular string 16 would
extend upwardly through the RCD 22 for connection to, for
example, a rotary table (not shown), a standpipe line 26,
kelley (not shown), a top drive and/or other conventional
drilling equipment.
The drilling fluid 18 exits the wellhead 24 via a wing
valve 28 in communication with the annulus 20 below the RCD
22. The fluid 18 then flows through fluid return line 30 to
a choke manifold 32, which includes redundant chokes 34.
Backpressure is applied to the annulus 20 by variably
restricting flow of the fluid 18 through the operative
choke(s) 34.
The greater the restriction to flow through the choke
34, the greater the backpressure applied to the annulus 20.
Thus, bottom hole pressure can be conveniently regulated by
varying the backpressure applied to the annulus 20. A
hydraulics model can be used, as described more fully below,
to determine a pressure applied to the annulus 20 at or near
the surface which will result in a desired bottom hole
pressure, so that an operator (or an automated control
system) can readily determine how to regulate the pressure
applied to the annulus at or near the surface (which can be
conveniently measured) in order to obtain the desired bottom
hole pressure.
Pressure applied to the annulus 20 can be measured at
or near the surface via a variety of pressure sensors 36,
38, 40, each of which is in communication with the annulus.
Pressure sensor 36 senses pressure below the RCD 22, but
above a blowout preventer (BOP) stack 42. Pressure sensor 38
senses pressure in the wellhead below the BOP stack 42.
Pressure sensor 40 senses pressure in the fluid return line
30 upstream of the choke manifold 32.
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Another pressure sensor 44 senses pressure in the
standpipe line 26. Yet another pressure sensor 46 senses
pressure downstream of the choke manifold 32, but upstream
of a separator 48, shaker 50 and mud pit 52. Additional
sensors include temperature sensors 54, 56, Coriolis
flowmeter 58, and flowmeters 62, 66.
Not all of these sensors are necessary. For example,
the system 10 could include only one of the flowmeters 62,
66. However, input from the sensors is useful to the
hydraulics model in determining what the pressure applied to
the annulus 20 should be during the drilling operation.
In addition, the tubular string 16 may include its own
sensors 60, for example, to directly measure bottom hole
pressure. Such sensors 60 may be of the type known to those
skilled in the art as pressure while drilling (PWD),
measurement while drilling (MWD) and/or logging while
drilling (LWD) sensor systems. These tubular string sensor
systems generally provide at least pressure measurement, and
may also provide temperature measurement, detection of
tubular string characteristics (such as vibration, weight on
bit, stick-slip, etc.), formation characteristics (such as
resistivity, density, etc.) and/or other measurements.
Various forms of telemetry (acoustic, pressure pulse,
electromagnetic, optical, wired, etc.) may be used to
transmit the downhole sensor measurements to the surface.
Additional sensors could be included in the system 10,
if desired. For example, another flowmeter 67 could be used
to measure the rate of flow of the fluid 18 exiting the
wellhead 24, another Coriolis flowmeter (not shown) could be
interconnected directly upstream or downstream of a rig mud
pump 68, etc.
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Fewer sensors could be included in the system 10, if
desired. For example, the output of the rig mud pump 68
could be determined by counting pump strokes, instead of by
using flowmeter 62 or any other flowmeters.
Note that the separator 48 could be a 3 or 4 phase
separator, or a mud gas separator (sometimes referred to as
a "poor boy degasser"). However, the separator 48 is not
necessarily used in the system 10.
The drilling fluid 18 is pumped through the standpipe
line 26 and into the interior of the tubular string 16 by
the rig mud pump 68. The pump 68 receives the fluid 18 from
the mud pit 52 and flows it via a standpipe manifold (not
shown) to the standpipe line 26, the fluid then circulates
downward through the tubular string 16, upward through the
annulus 20, through the mud return line 30, through the
choke manifold 32, and then via the separator 48 and shaker
50 to the mud pit 52 for conditioning and recirculation.
Note that, in the system 10 as so far described above,
the choke 34 cannot be used to control backpressure applied
to the annulus 20 for control of the bottom hole pressure,
unless the fluid 18 is flowing through the choke. In
conventional overbalanced drilling operations, a lack of
circulation can occur whenever a connection is made in the
tubular string 16 (e.g., to add another length of drill pipe
to the tubular string as the wellbore 12 is drilled deeper),
and the lack of circulation will require that bottom hole
pressure be regulated solely by the density of the fluid 18.
In the system 10, however, flow of the fluid 18 through
the choke 34 can be maintained, even though the fluid does
not circulate through the tubular string 16 and annulus 20.
Thus, pressure can still be applied to the annulus 20 by
restricting flow of the fluid 18 through the choke 34.
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In the system 10 as depicted in FIG. 1, a backpressure
pump 70 can be used to supply a flow of fluid to the return
line 30 upstream of the choke manifold 32 by pumping fluid
into the annulus 20 when needed. Alternatively, or in
addition, fluid could be diverted from the standpipe
manifold to the return line 30 when needed, as described in
International Application Serial No. PCT/U508/87686, and in
US Application Serial No. 12/638,012. Restriction by the
choke 34 of such fluid flow from the rig pump 68 and/or the
backpressure pump 70 will thereby cause pressure to be
applied to the annulus 20.
Although the example of FIG. 1 is depicted as if a
drilling operation is being performed, it should be clearly
understood that the principles of this disclosure may be
utilized in a variety of other well operations. For example,
such other well operations could include completion
operations, logging operations, casing operations, etc.
Thus, it is not necessary for the tubular string 16 to
be a drill string, or for the fluid 18 to be a drilling
fluid. For example, the fluid 18 could instead be a
completion fluid or any other type of fluid.
Accordingly, it will be appreciated that the principles
of this disclosure are not limited to drilling operations
and, indeed, are not limited at all to any of the details of
the system 10 described herein and/or illustrated in the
accompanying drawings.
A pressure and flow control system 90 which may be used
in conjunction with the system 10 and method of FIG. 1 is
representatively illustrated in FIG. 2. The control system
90 is preferably fully automated, although some human
intervention may be used, for example, to safeguard against
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improper operation, initiate certain routines, update
parameters, etc.
The control system 90 includes a hydraulics model 92, a
data acquisition and control interface 94 and a controller
96 (such as, a programmable logic controller or PLC, a
suitably programmed computer, etc.). Although these elements
92, 94, 96 are depicted separately in FIG. 2, any or all of
them could be combined into a single element, or the
functions of the elements could be separated into additional
elements, other additional elements and/or functions could
be provided, etc.
The hydraulics model 92 is used in the control system
90 to determine the desired annulus pressure at or near the
surface to achieve the desired bottom hole pressure. Data
such as well geometry, fluid properties and offset well
information (such as geothermal gradient and pore pressure
gradient, etc.) are utilized by the hydraulics model 92 in
making this determination, as well as real-time sensor data
acquired by the data acquisition and control interface 94.
Thus, there is a continual two-way transfer of data and
information between the hydraulics model 92 and the data
acquisition and control interface 94. Preferably, the data
acquisition and control interface 94 operates to maintain a
substantially continuous flow of real-time data from the
sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67
to the hydraulics model 92, so that the hydraulics model has
the information it needs to adapt to changing circumstances
and to update the desired annulus pressure. The hydraulics
model 92 operates to supply the data acquisition and control
interface 94 substantially continuously with a value for the
desired annulus pressure.
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A greater or lesser number of sensors may provide data
to the interface 94, in keeping with the principles of this
disclosure. For example, flow rate data from a flowmeter 72
which measures an output of the backpressure pump 70 may be
input to the interface 94 for use in the hydraulics model
92.
A suitable hydraulics model for use as the hydraulics
model 92 in the control system 90 is REAL TIME HYDRAULICS
(TM) provided by Halliburton Energy Services, Inc. of
Houston, Texas USA. Another suitable hydraulics model is
provided under the trade name IRIS (TM), and yet another is
available from SINTEF of Trondheim, Norway. Any suitable
hydraulics model may be used in the control system 90 in
keeping with the principles of this disclosure.
A suitable data acquisition and control interface for
use as the data acquisition and control interface 94 in the
control system 90 are SENTRY (TM) and INSITE (TM) provided
by Halliburton Energy Services, Inc. Any suitable data
acquisition and control interface may be used in the control
system 90 in keeping with the principles of this disclosure.
The controller 96 operates to maintain a desired
setpoint annulus pressure by controlling operation of the
fluid return choke 34 and/or the backpressure pump 70. When
an updated desired annulus pressure is transmitted from the
data acquisition and control interface 94 to the controller
96, the controller uses the desired annulus pressure as a
setpoint and controls operation of the choke 34 in a manner
(e.g., increasing or decreasing flow through the choke as
needed) to maintain the setpoint pressure in the annulus 20.
This is accomplished by comparing the setpoint pressure
to a measured annulus pressure (such as the pressure sensed
by any of the sensors 36, 38, 40), and increasing flow
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through the choke 34 if the measured pressure is greater
than the setpoint pressure, and decreasing flow through the
choke if the measured pressure is less than the setpoint
pressure. Of course, if the setpoint and measured pressures
are the same, then no adjustment of the choke 34 is
required. This process is preferably automated, so that no
human intervention is required, although human intervention
may be used if desired.
The controller 96 may also be used to control operation
of the backpressure pump 70. The controller 96 can, thus, be
used to automate the process of supplying fluid flow to the
return line 30 when needed. Again, no human intervention may
be required for this process.
Referring additionally now to FIG. 3, a somewhat
enlarged scale view of a portion of the well system 10 is
representatively illustrated apart from the remainder of the
system depicted in FIG. 1. In the FIG. 3 illustration, both
cased 12a and uncased 12b sections of the wellbore 12 are
visible.
In the example of FIG. 3, it is desired to trip the
tubular string 16 out of the wellbore 12, for example, to
change the bit 14, install additional casing, install a
completion assembly, perform a logging operation, etc.
However, it is also desired to prevent excessively increased
pressure from being applied to the uncased section 12b of
the wellbore exposed to the formation 64 (which could result
in skin damage to the formation, fracturing of the
formation, etc.), to prevent excessively reduced pressure
from being exposed to the uncased section of the wellbore
(which could result in an undesired influx of fluid into the
wellbore, instability of the wellbore, etc.), to prevent any
gas in the fluid 18 from migrating upwardly through the
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wellbore, and to prevent other fluids (such as higher
density fluids) from contacting the exposed formation.
In one unique feature of the example depicted in FIG.
3, the tubular string 16 is partially withdrawn from the
wellbore 12 (e.g., raised in the vertical wellbore shown in
FIG. 3) and a barrier substance 74 is placed in the
wellbore. The barrier substance 74 may be flowed into the
wellbore 12 by circulating it through the tubular string 16
and into the annulus 20, or the barrier substance could be
placed in the wellbore by other means (such as, via another
tubular string installed in the wellbore, by circulating the
barrier substance downward through the annulus, etc.).
As illustrated in FIG. 3, the barrier substance 74 is
placed in the wellbore 12 so that it traverses the junction
between the cased section 12a and uncased section 12b of the
wellbore (i.e., at a casing shoe 76). However, in other
examples, the barrier substance 74 could be placed entirely
in the cased section 12a or entirely in the uncased section
12b of the wellbore 12.
The barrier substance 74 is preferably of a type which
can isolate the fluid 18 exposed to the formation 64 from
other fluids in the wellbore 12. However, the barrier
substance 74 also preferably transmits pressure, so that
control over pressure in the fluid 18 exposed to the
formation 64 can be accomplished using the control system
90.
To isolate the fluid 18 exposed to the formation 64
from other fluids in the wellbore 12, the barrier substance
74 is preferably a highly viscous fluid, a highly
thixotropic gel or a high strength gel which sets in the
wellbore. However, the barrier substance 74 could be (or
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comprise) other types of materials in keeping with the
principles of this disclosure.
Suitable highly thixotropic gels for use as the barrier
substance 74 include N-SOLATE (TM) and CFS-538 (TM) marketed
by Halliburton Energy Services, Inc. A suitable preparation
is as follows:
Water (freshwater) - 0.85 bbl
Barite - 203 lb/bbl
CFS-538 (TM) - 9 lb/bbl
One suitable high strength gel for use as the barrier
substance 74 may be prepared as follows:
BARACTIVE (TM) base fluid polar activator ¨ 0.7 bbl
Water (freshwater) - 0.3 bbl
CFS-538 (TM) ¨ 10 lb/bbl
Of course, a wide variety of different formulations may
be used for the barrier substance 74. The above are only two
such formulations, and it should be clearly understood that
the principles of this disclosure are not limited at all to
these formulations.
Referring additionally now to FIG. 4, the system 10 is
representatively illustrated after the barrier substance 74
has been placed in the wellbore 12 and the tubular string 16
has been further partially withdrawn from the wellbore.
Another fluid 78 is then flowed into the wellbore 12 on an
opposite side of the barrier substance 74 from the fluid 18.
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The fluid 78 preferably has a density greater than a
density of the fluid 18. By flowing the fluid 78 into the
wellbore 12 above the barrier substance 74 and the fluid 18,
a desired pressure can be maintained in the fluid 18 exposed
to the formation 64, as the tubular string 16 is tripped out
of and back into the wellbore, as a completion assembly is
installed, as a logging operation is performed, as casing is
installed, etc.
The density of the fluid 78 is selected so that, after
it is flowed into the wellbore 12 (e.g., filling the
wellbore from the barrier substance 74 to the surface), an
appropriate hydrostatic pressure will be thereby applied to
the fluid 18 exposed to the formation 64. Preferably, at any
selected location along the uncased section 12b of the
wellbore 12, the pressure in the fluid 18 will be equal to,
or only marginally greater than (e.g., no more than
approximately 100 psi greater than), pore pressure in the
formation 64. However, other pressures in the fluid 18 may
be used in other examples.
While the barrier substance 74 is being placed in the
wellbore 12, and while the fluid 78 is being flowed into the
wellbore, the control system 90 preferably maintains the
pressure in the fluid 18 exposed to the formation 64
substantially constant (e.g., varying no more than a few
psi). The control system 90 can achieve this result by
automatically adjusting the choke 34 as fluid exits the
annulus 20 at the surface, as described above, so that an
appropriate backpressure is applied to the annulus at the
surface to maintain a desired pressure in the fluid 18
exposed to the formation 64.
Note that, since different density substances (e.g.,
barrier substance 74 and fluid 78) are being introduced into
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the wellbore 12, the annulus pressure setpoint will vary as
the substances are introduced into the wellbore. Preferably,
the density of the fluid 78 is selected so that, upon
completion of the step of flowing the fluid 78 into the
wellbore 12, no pressure will need to be applied to the
annulus 20 at the surface in order to maintain the desired
pressure in the fluid 18 exposed to the formation 64.
In this manner, a snubbing unit will not be necessary
for subsequent well operations (such as, running casing,
installing a completion assembly, wireline or coiled tubing
logging, etc.). However, a snubbing unit may be used, if
desired.
Preferably, the barrier fluid 74 will prevent mixing of
the fluids 18, 78, will isolate the fluids from each other,
will prevent migration of gas 80 upward through the wellbore
12, and will transmit pressure between the fluids.
Consequently, excessively increased pressure in the uncased
section 12b of the wellbore exposed to the formation 64
(which could otherwise result from opening a downhole
deployment valve, etc.) can be prevented, excessively
reduced pressure can be prevented from being exposed to the
uncased section of the wellbore, gas in the fluid 18 can be
prevented from migrating upwardly through the wellbore to
the surface, and fluids (such as higher density fluids)
other than the fluid 18 can be prevented from contacting the
exposed formation.
Referring additionally now to FIG. 5, a flowchart for
one example of a method 100 of controlling pressure in the
wellbore 12 is representatively illustrated. The method 100
may be used in conjunction with the well system 10 described
above, or the method may be used with other well systems.
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In an initial step 102 of the method 100, a first fluid
(such as the fluid 18) is present in the wellbore 12. As in
the system 10, the fluid 18 could be a drilling fluid which
is specially formulated to exert a desired hydrostatic
pressure, prevent fluid loss to the formation 64, lubricate
the bit 14, enhance wellbore stability, etc. In other
examples, the fluid 18 could be a completion fluid or
another type of fluid.
The fluid 18 may be circulated through the wellbore 12
during drilling or other operations. Various means (e.g.,
tubular string 16, a coiled tubing string, etc.) may be used
to introduce the fluid 18 into the wellbore, in keeping with
the principles of this disclosure.
In a subsequent step 104 of the method 100, pressure in
the fluid 18 exposed to the formation 64 is adjusted, if
desired. For example, if prior to beginning the procedure
depicted in FIG. 5, an underbalanced drilling operation was
being performed, then it may be desirable to increase the
pressure in the fluid 18 exposed to the formation 64, so
that the pressure in the fluid is equal to, or marginally
greater than, pore pressure in the formation.
In this manner, an influx of fluid from the formation
64 into the wellbore 12 can be avoided during the remainder
of the method 100. Of course, if the pressure in the fluid
18 exposed to the formation 64 is already at a desired
level, then this step 104 is not necessary.
In step 106 of the method 100, the tubular string 16 is
partially withdrawn from the wellbore 12. This places a
lower end of the tubular string 16 at a desired lower extent
of the barrier substance 74, as depicted in FIG. 3.
If the lower end of the tubular string 16 (or another
tubular string used to place the barrier substance 74) was
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not previously below the desired lower extent of the barrier
substance, then "partially withdrawing" the tubular string
can be taken to mean, "placing the lower end of the tubular
string at a desired lower extent of the barrier substance
74." For example, a coiled tubing string could be installed
in the wellbore 12 for the purpose of placing the barrier
substance 74 above the fluid 18 exposed to the formation 64,
in which case the coiled tubing string could be considered
"partially withdrawn" from the wellbore, in that its lower
end would be positioned at a desired lower extent of the
barrier substance.
In step 108 of the method 100, the barrier substance 74
is placed in the wellbore 12. As described above, the
barrier substance could be flowed through the tubular string
16, flowed through the annulus 20 or placed in the wellbore
by any other means.
In step 110 of the method 100, the tubular string 16 is
again partially withdrawn from the wellbore 12. This time,
the lower end of the tubular string 16 is positioned at a
desired lower extent of the fluid 78. In this step 110,
"partially withdrawing" can be taken to mean, "positioning a
lower end of the tubular string at a desired lower extent of
the fluid 78."
In step 112 of the method 100, the second fluid 78 is
flowed into the wellbore 12. As described above, the fluid
78 has a selected density, so that a desired pressure is
applied to the fluid 18 by the column of the fluid 78
thereabove. It is envisioned that, in most circumstances of
underbalanced and managed pressure drilling, the density of
the fluid 78 will be greater than the density of the fluid
18 (so that the pressure in the fluid 18 is equal to or
marginally greater than the pressure in the formation 64),
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but in other examples the density of the fluid 78 could be
equal to, or less than, the density of the fluid 18.
In step 114 of the method 100, a well operation is
performed at the conclusion of the procedure depicted in
FIG. 5. The well operation could be any type, number and/or
combination of well operation(s) including, but not limited
to, drilling operation(s), completion operation(s), logging
operation(s), installation of casing, cementing operations,
abandonment operations, etc. It is not necessary for the
well operation to be managed or underbalanced drilling, or
drilling of any type, in keeping with the scope of this
disclosure. Preferably, due to the unique features of the
system and method described herein, such operation(s) can be
performed without use of a downhole deployment valve or a
surface snubbing unit, but those types of equipment may be
used, if desired, in keeping with the principles of this
disclosure.
Throughout the method 100 example, and as indicated by
steps 116 and 118 in FIG. 5, the hydraulics model 92
produces a desired surface annulus pressure setpoint as
needed to maintain a desired pressure in the fluid 18
exposed to the formation 64, and the controller 96
automatically adjusts the choke 34 as needed to achieve the
surface annulus pressure setpoint. The surface annulus
pressure setpoint can change during the method 100.
For example, if the fluid 78 has a greater density than
the fluid 18 in step 112, then the surface annulus pressure
setpoint may decrease as the fluid 78 is flowed into the
wellbore 12. As another example, in step 104, the surface
annulus pressure setpoint may be increased if the wellbore
12 was previously being drilled underbalanced, and it is now
desired to increase the pressure in the fluid 18 exposed to
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the formation 64, so that it is equal to or marginally
greater than pressure in the formation.
Again, it is not necessary for the barrier substance 74
to be used in any type of drilling operation and/or managed
pressure operation. The barrier substance 74 can separate
fluids or other flowable substances in any type of well
operation.
Note that, although in the above description only the
fluids 18, 78 are indicated as being segregated by the
barrier substance 74, in other examples more than one fluid
could be exposed to the formation 64 below the barrier
substance and/or more than one fluid may be positioned
between the barrier substance and the surface. In addition,
more than one barrier substance 74 and/or barrier substance
location could be used in the wellbore 12 to thereby
segregate any number of fluids.
In an example representatively illustrated in FIG. 6,
the barrier substance 74 isolates the fluid 18 from cement
120 placed in the uncased section 12b of the wellbore 12.
The cement 120 is likely more dense than the fluid 18, but
the barrier substance 74 prevents the cement 120 from
penetrating the barrier substance and thereby flowing away
from its intended location.
For example, it may be intended to place the cement 120
in a particularly stable and relatively impermeable zone, so
that the cement will form an effective plug in the wellbore
12 (e.g., for abandonment of the well, for isolating a
water-producing zone, for segregating zones, etc.). The
effectiveness of the cement 120 as a plug could be
compromised if the cement is allowed to fall downward
through the fluid 18, to mix with the fluid 18, and/or to
flow away from its intended placement.
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In the system 10 as depicted in FIG. 6, the barrier
substance 74 beneficially accomplishes the desired functions
of preventing the cement 120 from falling through the fluid
18, preventing mixing of the cement and fluid 18, and
maintaining the placement of the cement. These benefits are
obtained, without a need to set an open hole bridge plug in
the uncased section 12b. Instead, the barrier substance 74
can be conveniently placed above the fluid 18 (for example,
using coiled tubing) prior to placing the cement 120 above
the barrier fluid.
In addition, the barrier substance 74 transmits
pressure between the cement 120 and the fluid 18. Thus,
there is no concern that a pressure differential rating of
an open hole bridge plug might be exceeded, and pressure in
the fluid 18 can be effectively controlled by appropriate
selection of the densities of the barrier substance 74,
cement 120 and fluid 78 during the cementing operation.
The fluid 78 placed above the cement 120 could be the
same as the fluid 18 below the barrier substance 74, and/or
it could comprise another fluid having a density selected so
that pressure in the wellbore 12 is maintained at a desired
level. For example, the fluid 78 can be selected so that
sufficient hydrostatic pressure in the wellbore 12 is
maintained for well control (e.g., hydrostatic pressure in
the wellbore is greater than pressure in the formation 64
all along the wellbore).
As another example, the fluid 78 can be selected so
that hydrostatic pressures at certain locations along the
wellbore 12 are less than respective predetermined maximum
levels (e.g., less than a pressure rating of the casing shoe
76, less than a fracture pressure of the formation 64,
etc.). The fluid 78 may be more dense or less dense as
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compared to the fluid 18. It is contemplated that, in most
actual circumstances, the fluid 78 will be less dense as
compared to the cement 120, but this is not necessary in
keeping with the scope of this disclosure.
As used herein, the term "cement" is used to indicate a
substance which is initially flowable, but which will harden
into a rigid structure having compressive strength after
being flowed into a well, thereby forming a barrier to
fluid. Cement is not necessarily cementitious, and does not
necessarily harden via hydration. Cement can comprise
polymers (such as epoxies, etc.) and/or other materials.
Although the cement 120 is depicted in FIG. 6 as being
placed entirely in the uncased section 12b, in other
examples the cement could extend above the casing shoe 76,
or could be placed entirely in the cased section 12a. Thus,
the scope of this disclosure is not limited to any
particular positions of interfaces between the fluids 18,
78, barrier substance 74 and/or cement 120.
It may now be fully appreciated that the above
description of the various examples of the well system 10
and method 100 provides several advancements to the art of
isolating flowable substances in a well. In one example
described above, cement 120 can be prevented from flowing
downward through another, lighter fluid 18.
A method of segregating flowable materials in
conjunction with a subterranean well is described above. In
one example, the method can include segregating flowable
cement 120 from a first fluid 18 by placing a flowable
barrier substance 74 between the cement 120 and the first
fluid 18. The barrier substance 74 substantially prevents
displacement of the cement 120 by force of gravity through
the barrier substance 74 and into the first fluid 18.
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The placing step can comprise flowing the barrier
substance 74 into the well while the first fluid 18 is
already present in the well. The placing step can also
comprise flowing the cement 120 into the well after the step
of flowing the barrier substance 74 into the well. The
placing step can also comprise flowing the barrier substance
74 to a position above the first fluid 18.
The method may include placing a second fluid 78 above
the cement 120. The second fluid 78 can have a density
greater than, or less than, a density of the first fluid 18.
The barrier substance 74 may comprise a thixotropic gel
and/or a gel which sets in the wellbore 12. The barrier
substance 74 may have a viscosity greater than viscosities
of the first and second fluids 18, 78. The cement 120 can
have a density greater than a density of the first fluid 18.
Another method of segregating flowable materials in a
wellbore 12 is disclosed to the art. In an example described
above, the method can include flowing a barrier substance 74
into the wellbore 12 above a first fluid 18 already in the
wellbore 12, and then flowing cement 120 into the wellbore
12 above the barrier substance 74.
A system 10 for use in conjunction with a subterranean
well is also described above. The system 10 may include a
flowable cement 120 isolated from a first fluid 18 by a
flowable barrier substance 74 positioned between the cement
120 and the first fluid 18, whereby the barrier substance 74
substantially prevents displacement of the cement by force
of gravity through the barrier substance 74 and into the
first fluid 18.
The above disclosure describes a method 100 of
controlling pressure in a wellbore 12. The method 100 can
include placing a barrier substance 74 in the wellbore 12
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while a first fluid 18 is present in the wellbore, and
flowing a second fluid 78 into the wellbore 12 while the
first fluid 18 and the barrier substance 74 are in the
wellbore. The first and second fluids 18, 78 may have
different densities.
The barrier substance 74 may isolate the first fluid 18
from the second fluid 78, may prevent upward migration of
gas 80 in the wellbore and/or may prevent migration of gas
80 from the first fluid 18 to the second fluid 78.
Placing the barrier substance 74 in the wellbore 12 can
include automatically controlling a fluid return choke 34,
whereby pressure in the first fluid 18 is maintained
substantially constant. Similarly, flowing the second fluid
78 into the wellbore 12 can include automatically
controlling the fluid return choke 34, whereby pressure in
the first fluid 18 is maintained substantially constant.
The second fluid 78 density may be greater than the
first fluid 18 density. Pressure in the first fluid 18 may
remain substantially constant while the greater density
second fluid 78 is flowed into the wellbore 12.
The above disclosure also provides to the art a well
system 10. The well system 10 can include first and second
fluids 18, 78 in a wellbore 12, the first and second fluids
having different densities, and a barrier substance 74
separating the first and second fluids.
Although various examples have been described above,
with each example having certain features, it should be
understood that it is not necessary for a particular feature
of one example to be used exclusively with that example.
Instead, any of the features described above and/or depicted
in the drawings can be combined with any of the examples, in
addition to or in substitution for any of the other features
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of those examples. One example's features are not mutually
exclusive to another example's features. Instead, the scope
of this disclosure encompasses any combination of any of the
features.
Although each example described above includes a
certain combination of features, it should be understood
that it is not necessary for all features of an example to
be used. Instead, any of the features described above can be
used, without any other particular feature or features also
being used.
It should be understood that the various embodiments
described herein may be utilized in various orientations,
such as inclined, inverted, horizontal, vertical, etc., and
in various configurations, without departing from the
principles of this disclosure. The embodiments are described
merely as examples of useful applications of the principles
of the disclosure, which is not limited to any specific
details of these embodiments.
In the above description of the representative
examples, directional terms (such as "above," "below,"
"upper," "lower," etc.) are used for convenience in
referring to the accompanying drawings. However, it should
be clearly understood that the scope of this disclosure is
not limited to any particular directions described herein.
The terms "including," "includes," "comprising,"
"comprises," and similar terms are used in a non-limiting
sense in this specification. For example, if a system,
method, apparatus, device, etc., is described as "including"
a certain feature or element, the system, method, apparatus,
device, etc., can include that feature or element, and can
also include other features or elements. Similarly, the term
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"comprises" is considered to mean "comprises, but is not
limited to."
Of course, a person skilled in the art would, upon a
careful consideration of the above description of
representative embodiments of the disclosure, readily
appreciate that many modifications, additions,
substitutions, deletions, and other changes may be made to
the specific embodiments, and such changes are contemplated
by the principles of this disclosure. Accordingly, the
foregoing detailed description is to be clearly understood
as being given by way of illustration and example only, the
spirit and scope of the invention being limited solely by
the appended claims and their equivalents.
