Note: Descriptions are shown in the official language in which they were submitted.
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 1 -
PRESSURE AND FLOW CONTROL IN DRILLING OPERATIONS
TECHNICAL FIELD
The present disclosure relates generally to equipment
utilized and operations performed in conjunction with well
drilling operations and, in an embodiment described herein,
more particularly provides for pressure and flow control in
drilling operations.
BACKGROUND
Managed pressure drilling is well known as the art of
precisely controlling bottom hole pressure during drilling
by utilizing a closed annulus and a means for regulating
pressure in the annulus. The annulus is typically closed
during drilling through use of a rotating control device
(RCD, also known as a rotating control head or rotating
blowout preventer) which seals about the drill pipe as it
rotates.
It will, therefore, be appreciated that improvements
would be beneficial in the art of controlling pressure and
flow in drilling operations.
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 2 -
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic view of a well drilling system
and method embodying principles of the present disclosure.
FIG. 2 is a schematic view of another configuration of
the well drilling system.
FIG. 3 is a schematic block diagram of a pressure and
flow control system which may be used in the well drilling
system and method.
FIG. 4 is a flowchart of a method for making a drill
string connection which may be used in the well drilling
system and method.
FIG. 5 is a schematic block diagram of another
configuration of the pressure and flow control system.
FIGS 6-8 are schematic block diagrams of various
configurations of a predictive device which may be used in
the pressure and flow control system of FIG. 5.
FIG. 9 is a schematic view of another configuration of
the well drilling system.
FIG. 10 is a schematic view of another configuration of
the well drilling system.
DETAILED DESCRIPTION
Representatively and schematically illustrated in FIG.
1 is a well drilling system 10 and associated method which
can embody principles of the present disclosure. In the
system 10, a wellbore 12 is drilled by rotating a drill bit
14 on an end of a drill string 16. Drilling fluid 18,
commonly known as mud, is circulated downward through the
drill string 16, out the drill bit 14 and upward through an
annulus 20 formed between the drill string and the wellbore
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
-3-
12, in order to cool the drill bit, lubricate the drill
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 drill string 16 (e.g., when
connections are being made in the drill string).
Control of bottom hole pressure is very important in
managed pressure drilling, and in other types of drilling
operations. Preferably, the bottom hole pressure is
precisely controlled to prevent excessive loss of fluid into
the earth formation 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 slightly greater than
a pore pressure of the formation, without exceeding a
fracture pressure of the formation. This technique is
especially useful in situations where the margin between
pore pressure and fracture is relatively small.
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. In typical overbalanced drilling,
it is desired to maintain the bottom hole pressure somewhat
greater than the pore pressure, thereby preventing (or at
least mitigating) influx of fluid from the formation.
Nitrogen or another gas, or another lighter weight
fluid, may be added to the drilling fluid 18 for pressure
control. This technique is 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
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 4 -
(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 drill string 16 above a wellhead 24.
Although not shown in FIG. 1, the drill 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 mud return lines 30, 73
to a choke manifold 32, which includes redundant chokes 34
(only one of which might be used at a time). 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, downhole pressure (e.g., pressure at the bottom of the
wellbore 12, pressure at a downhole casing shoe, pressure at
a particular formation or zone, etc.) 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 downhole
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
downhole pressure.
Pressure applied to the annulus 20 can be measured at
or near the surface via a variety of pressure sensors 36,
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
-5-
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 mud return lines
30, 73 upstream of the choke manifold 32.
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, 64, 66.
Not all of these sensors are necessary. For example,
the system 10 could include only two of the three flowmeters
62, 64, 66. However, input from all available sensors is
useful to the hydraulics model in determining what the
pressure applied to the annulus 20 should be during the
drilling operation.
Other sensor types may be used, if desired. For
example, it is not necessary for the flowmeter 58 to be a
Coriolis flowmeter, since a turbine flowmeter, acoustic
flowmeter, or another type of flowmeter could be used
instead.
In addition, the drill string 16 may include its own
sensors 60, for example, to directly measure downhole
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). These drill string sensor systems generally
provide at least pressure measurement, and may also provide
temperature measurement, detection of drill string
characteristics (such as vibration, weight on bit, stick-
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 6 -
slip, etc.), formation characteristics (such as resistivity,
density, etc.) and/or other measurements. Various forms of
wired or wireless telemetry (acoustic, pressure pulse,
electromagnetic, 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.
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 the 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 drill 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 70 to the
standpipe 26. The fluid then circulates downward through the
drill string 16, upward through the annulus 20, through the
mud return lines 30, 73, 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 downhole pressure,
unless the fluid 18 is flowing through the choke. In
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 7 -
conventional overbalanced drilling operations, a lack of
fluid 18 flow will occur, for example, whenever a connection
is made in the drill string 16 (e.g., to add another length
of drill pipe to the drill string as the wellbore 12 is
drilled deeper), and the lack of circulation will require
that downhole 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 drill string 16 and annulus 20,
while a connection is being made in the drill string. Thus,
pressure can still be applied to the annulus 20 by
restricting flow of the fluid 18 through the choke 34, even
though a separate backpressure pump may not be used.
When fluid 18 is not circulating through drill string
16 and annulus 20 (e.g., when a connection is made in the
drill string), the fluid is flowed from the pump 68 to the
choke manifold 32 via a bypass line 72, 75. Thus, the fluid
18 can bypass the standpipe line 26, drill string 16 and
annulus 20, and can flow directly from the pump 68 to the
mud return line 30, which remains in communication with the
annulus 20. Restriction of this flow by the choke 34 will
thereby cause pressure to be applied to the annulus 20 (for
example, in typical managed pressure drilling).
As depicted in FIG. 1, both of the bypass line 75 and
the mud return line 30 are in communication with the annulus
20 via a single line 73. However, the bypass line 75 and
the mud return line 30 could instead be separately connected
to the wellhead 24, for example, using an additional wing
valve (e.g., below the RCD 22), in which case each of the
lines 30, 75 would be directly in communication with the
annulus 20.
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 8 -
Although this might require some additional plumbing at
the rig site, the effect on the annulus pressure would be
essentially the same as connecting the bypass line 75 and
the mud return line 30 to the common line 73. Thus, it
should be appreciated that various different configurations
of the components of the system 10 may be used, without
departing from the principles of this disclosure.
Flow of the fluid 18 through the bypass line 72, 75 is
regulated by a choke or other type of flow control device
74. Line 72 is upstream of the bypass flow control device
74, and line 75 is downstream of the bypass flow control
device.
Flow of the fluid 18 through the standpipe line 26 is
substantially controlled by a valve or other type of flow
control device 76. Note that the flow control devices 74,
76 are independently controllable, which provides
substantial benefits to the system 10, as described more
fully below.
Since the rate of flow of the fluid 18 through each of
the standpipe and bypass lines 26, 72 is useful in
determining how bottom hole pressure is affected by these
flows, the flowmeters 64, 66 are depicted in FIG. 1 as being
interconnected in these lines. However, the rate of flow
through the standpipe line 26 could be determined even if
only the flowmeters 62, 64 were used, and the rate of flow
through the bypass line 72 could be determined even if only
the flowmeters 62, 66 were used. Thus, it should be
understood that it is not necessary for the system 10 to
include all of the sensors depicted in FIG. 1 and described
herein, and the system could instead include additional
sensors, different combinations and/or types of sensors,
etc.
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 9 -
In another beneficial feature of the system 10, a
bypass flow control device 78 and flow restrictor 80 may be
used for filling the standpipe line 26 and drill string 16
after a connection is made in the drill string, and for
equalizing pressure between the standpipe line and mud
return lines 30, 73 prior to opening the flow control device
76. Otherwise, sudden opening of the flow control device 76
prior to the standpipe line 26 and drill string 16 being
filled and pressurized with the fluid 18 could cause an
undesirable pressure transient in the annulus 20 (e.g., due
to flow to the choke manifold 32 temporarily being lost
while the standpipe line and drill string fill with fluid,
etc.).
By opening the standpipe bypass flow control device 78
after a connection is made, the fluid 18 is permitted to
fill the standpipe line 26 and drill string 16 while a
substantial majority of the fluid continues to flow through
the bypass line 72, thereby enabling continued controlled
application of pressure to the annulus 20. After the
pressure in the standpipe line 26 has equalized with the
pressure in the mud return lines 30, 73 and bypass line 75,
the flow control device 76 can be opened, and then the flow
control device 74 can be closed to slowly divert a greater
proportion of the fluid 18 from the bypass line 72 to the
standpipe line 26.
Before a connection is made in the drill string 16, a
similar process can be performed, except in reverse, to
gradually divert flow of the fluid 18 from the standpipe
line 26 to the bypass line 72 in preparation for adding more
drill pipe to the drill string 16. That is, the flow
control device 74 can be gradually opened to slowly divert a
greater proportion of the fluid 18 from the standpipe line
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 10 -
26 to the bypass line 72, and then the flow control device
76 can be closed.
Note that the flow control device 78 and flow
restrictor 80 could be integrated into a single element
(e.g., a flow control device having a flow restriction
therein), and the flow control devices 76, 78 could be
integrated into a single flow control device 81 (e.g., a
single choke which can gradually open to slowly fill and
pressurize the standpipe line 26 and drill string 16 after a
drill pipe connection is made, and then open fully to allow
maximum flow while drilling).
However, since typical conventional drilling rigs are
equipped with the flow control device 76 in the form of a
valve in the standpipe manifold 70, and use of the standpipe
valve is incorporated into usual drilling practices, the
individually operable flow control devices 76, 78 are
presently preferred. The flow control devices 76, 78 are at
times referred to collectively below as though they are the
single flow control device 81, but it should be understood
that the flow control device 81 can include the individual
flow control devices 76, 78.
Another alternative is representatively illustrated in
FIG. 2. In this configuration of the system 10, the flow
control device 78 is in the form of a choke, and the flow
restrictor 80 is not used. The flow control device 78
depicted in FIG. 2 enables more precise control over the
flow of the fluid 18 into the standpipe line 26 and drill
string 16 after a drill pipe connection is made.
Note that each of the flow control devices 74, 76, 78
and chokes 34 are preferably remotely and automatically
controllable to maintain a desired downhole pressure by
maintaining a desired annulus pressure at or near the
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 11 -
surface. However, any one or more of these flow control
devices 74, 76, 78 and chokes 34 could be manually
controlled without departing from the principles of this
disclosure.
A pressure and flow control system 90 which may be used
in conjunction with the system 10 and associated methods of
FIGS. 1 & 2 is representatively illustrated in FIG. 3. The
control system 90 is preferably fully automated, although
some human intervention may be used, for example, to
safeguard against 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. 3, 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 downhole 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. It is important to
appreciate that the data acquisition and control interface
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 12 -
94 operates to maintain a substantially continuous flow of
real-time data from the sensors 44, 54, 66, 62, 64, 60, 58,
46, 36, 38, 40, 56, 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, and the hydraulics model operates to supply the
data acquisition and control interface substantially
continuously with a value for the desired annulus pressure.
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
mud return choke 34. 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 resistance through the choke as needed) to
maintain the setpoint pressure in the annulus 20. The choke
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 13 -
34 can be closed more to increase flow resistance, or opened
more to decrease flow resistance.
Maintenance of the setpoint pressure 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 decreasing flow resistance through the
choke 34 if the measured pressure is greater than the
setpoint pressure, and increasing flow resistance 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 standpipe flow control devices 76, 78 and the bypass
flow control device 74. The controller 96 can, thus, be
used to automate the processes of diverting flow of the
fluid 18 from the standpipe line 26 to the bypass line 72
prior to making a connection in the drill string 16, then
diverting flow from the bypass line to the standpipe line
after the connection is made, and then resuming normal
circulation of the fluid 18 for drilling. Again, no human
intervention may be required in these automated processes,
although human intervention may be used if desired, for
example, to initiate each process in turn, to manually
operate a component of the system, etc.
Referring additionally now to FIG. 4, a schematic
flowchart is provided for a method 100 for making a drill
pipe connection in the well drilling system 10 using the
control system 90. Of course, the method 100 may be used in
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 14 -
other well drilling systems, and with other control systems,
in keeping with the principles of this disclosure.
The drill pipe connection process begins at step 102,
in which the process is initiated. A drill pipe connection
is typically made when the wellbore 12 has been drilled far
enough that the drill string 16 must be elongated in order
to drill further.
In step 104, the flow rate output of the pump 68 may be
decreased. By decreasing the flow rate of the fluid 18
output from the pump 68, it is more convenient to maintain
the choke 34 within its most effective operating range
(typically, from about 30% to about 70% of maximum opening)
during the connection process. However, this step is not
necessary if, for example, the choke 34 would otherwise
remain within its effective operating range.
In step 106, the setpoint pressure changes due to the
reduced flow of the fluid 18 (e.g., to compensate for
decreased fluid friction in the annulus 20 between the bit
14 and the wing valve 28 resulting in reduced equivalent
circulating density). The data acquisition and control
interface 94 receives indications (e.g., from the sensors
58, 60, 62, 66, 67) that the flow rate of the fluid 18 has
decreased, and the hydraulics model 92 in response
determines that a changed annulus pressure is desired to
maintain the desired downhole pressure, and the controller
96 uses the changed desired annulus pressure as a setpoint
to control operation of the choke 34.
In a slightly overbalanced managed pressure drilling
operation, the setpoint pressure would likely increase, due
to the reduced equivalent circulating density, in which case
flow resistance through the choke 34 would be increased in
response. However, in some operations (such as,
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 15 -
underbalanced drilling operations in which gas or another
light weight fluid is added to the drilling fluid 18 to
decrease bottom hole pressure), the setpoint pressure could
decrease (e.g., due to production of liquid downhole).
In step 108, the restriction to flow of the fluid 18
through the choke 34 is changed, due to the changed desired
annulus pressure in step 106. As discussed above, the
controller 96 controls operation of the choke 34, in this
case changing the restriction to flow through the choke to
obtain the changed setpoint pressure. Also as discussed
above, the setpoint pressure could increase or decrease.
Steps 104, 106 and 108 are depicted in the FIG. 4
flowchart as being performed concurrently, since the
setpoint pressure and mud return choke restriction can
continuously vary, whether in response to each other, in
response to the change in the mud pump output and in
response to other conditions, as discussed above.
In step 109, the bypass flow control device 74
gradually opens. This diverts a gradually increasing
proportion of the fluid 18 to flow through the bypass line
72, instead of through the standpipe line 26.
In step 110, the setpoint pressure changes due to the
reduced flow of the fluid 18 through the drill string 16
(e.g., to compensate for decreased fluid friction in the
annulus 20 between the bit 14 and the wing valve 28
resulting in reduced equivalent circulating density). Flow
through the drill string 16 is substantially reduced when
the bypass flow control device 74 is opened, since the
bypass line 72 becomes the path of least resistance to flow
and, therefore, fluid 18 flows through bypass line 72. The
data acquisition and control interface 94 receives
indications (e.g., from the sensors 58, 60, 62, 66, 67) that
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 16 -
the flow rate of the fluid 18 through the drill pipe 16 and
annulus 20 has decreased, and the hydraulics model 92 in
response determines that a changed annulus pressure is
desired to maintain the desired downhole pressure, and the
controller 96 uses the changed desired annulus pressure as a
setpoint to control operation of the choke 34.
In a slightly overbalanced managed pressure drilling
operation, the setpoint pressure would likely increase, due
to the reduced equivalent circulating density, in which case
flow restriction through the choke 34 would be increased in
response. However, in some operations (such as,
underbalanced drilling operations in which gas or another
light weight fluid is added to the drilling fluid 18 to
decrease bottom hole pressure), the setpoint pressure could
decrease (e.g., due to production of liquid downhole).
In step 111, the restriction to flow of the fluid 18
through the choke 34 is changed, due to the changed desired
annulus pressure in step 110. As discussed above, the
controller 96 controls operation of the choke 34, in this
case changing the restriction to flow through the choke to
obtain the changed setpoint pressure. Also as discussed
above, the setpoint pressure could increase or decrease.
Steps 109, 110 and 111 are depicted in the FIG. 4
flowchart as being performed concurrently, since the
setpoint pressure and mud return choke restriction can
continuously vary, whether in response to each other, in
response to the bypass flow control device 74 opening and in
response to other conditions, as discussed above. However,
these steps could be performed non-concurrently in other
examples.
In step 112, the pressures in the standpipe line 26 and
the annulus 20 at or near the surface (indicated by sensors
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 17 -
36, 38, 40, 44) equalize. At this point, the bypass flow
control device 74 should be fully open, and substantially
all of the fluid 18 is flowing through the bypass line 72,
75 and not through the standpipe line 26 (since the bypass
line represents the path of least resistance). Static
pressure in the standpipe line 26 should substantially
equalize with pressure in the lines 30, 73, 75 upstream of
the choke manifold 32.
In step 114, the standpipe flow control device 81 is
closed. The separate standpipe bypass flow control device
78 should already be closed, in which case only the valve 76
would be closed in step 114.
In step 116, a standpipe bleed valve 82 (see FIG. 10)
would be opened to bleed pressure and fluid from the
standpipe line 26 in preparation for breaking the connection
between the kelley or top drive and the drill string 16. At
this point, the standpipe line 26 is vented to atmosphere.
In step 118, the kelley or top drive is disconnected
from the drill string 16, another stand of drill pipe is
connected to the drill string, and the kelley or top drive
is connected to the top of the drill string. This step is
performed in accordance with conventional drilling practice,
with at least one exception, in that it is conventional
drilling practice to turn the rig pumps off while making a
connection. In the method 100, however, the rig pumps 68
preferably remain on, but the standpipe valve 76 is closed
and all flow is diverted to the choke manifold 32 for
annulus pressure control. Non-return valve 21 prevents flow
upward through the drill string 16 while making a connection
with the rig pumps 68 on.
In step 120, the standpipe bleed valve 82 is closed.
The standpipe line 26 is, thus, isolated again from
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 18 -
atmosphere, but the standpipe line and the newly added stand
of drill pipe are substantially empty (i.e., not filled with
the fluid 18) and the pressure therein is at or near ambient
pressure before the connection is made.
In step 122, the standpipe bypass flow control device
78 opens (in the case of the valve and flow restrictor
configuration of FIG. 1) or gradually opens (in the case of
the choke configuration of FIG. 2). In this manner, the
fluid 18 is allowed to fill the standpipe line 26 and the
newly added stand of drill pipe, as indicated in step 124.
Eventually, the pressure in the standpipe line 26 will
equalize with the pressure in the annulus 20 at or near the
surface, as indicated in step 126. However, substantially
all of the fluid 18 will still flow through the bypass line
72 at this point. Static pressure in the standpipe line 26
should substantially equalize with pressure in the lines 30,
73, 75 upstream of the choke manifold 32.
In step 128, the standpipe flow control device 76 is
opened in preparation for diverting flow of the fluid 18 to
the standpipe line 26 and thence through the drill string
16. The standpipe bypass flow control device 78 is then
closed. Note that, by previously filling the standpipe line
26 and drill string 16, and equalizing pressures between the
standpipe line and the annulus 20, the step of opening the
standpipe flow control device 76 does not cause any
significant undesirable pressure transients in the annulus
or mud return lines 30, 73. Substantially all of the fluid
18 still flows through the bypass line 72, instead of
through the standpipe line 26, even though the standpipe
flow control device 76 is opened.
Considering the separate standpipe flow control devices
76, 78 as a single standpipe flow control device 81, then
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 19 -
the flow control device 81 is gradually opened to slowly
fill the standpipe line 26 and drill string 16, and then
fully opened when pressures in the standpipe line and
annulus 20 are substantially equalized.
In step 130, the bypass flow control device 74 is
gradually closed, thereby diverting an increasingly greater
proportion of the fluid 18 to flow through the standpipe
line 26 and drill string 16, instead of through the bypass
line 72. During this step, circulation of the fluid 18
begins through the drill string 16 and wellbore 12.
In step 132, the setpoint pressure changes due to the
flow of the fluid 18 through the drill string 16 and annulus
(e.g., to compensate for increased fluid friction
resulting in increased equivalent circulating density). The
15 data acquisition and control interface 94 receives
indications (e.g., from the sensors 60, 64, 66, 67) that the
flow rate of the fluid 18 through the wellbore 12 has
increased, and the hydraulics model 92 in response
determines that a changed annulus pressure is desired to
20 maintain the desired downhole pressure, and the controller
96 uses the changed desired annulus pressure as a setpoint
to control operation of the choke 34. The desired annulus
pressure may either increase or decrease, as discussed above
for steps 106 and 108.
In step 134, the restriction to flow of the fluid 18
through the choke 34 is changed, due to the changed desired
annulus pressure in step 132. As discussed above, the
controller 96 controls operation of the choke 34, in this
case changing the restriction to flow through the choke to
obtain the changed setpoint pressure.
Steps 130, 132 and 134 are depicted in the FIG. 4
flowchart as being performed concurrently, since the
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 20 -
setpoint pressure and mud return choke restriction can
continuously vary, whether in response to each other, in
response to the bypass flow control device 74 closing and in
response to other conditions, as discussed above.
In step 135, the flow rate output from the pump 68 may
be increased in preparation for resuming drilling of the
wellbore 12. This increased flow rate maintains the choke
34 in its optimum operating range, but this step (as with
step 104 discussed above) may not be used if the choke is
otherwise maintained in its optimum operating range.
In step 136, the setpoint pressure changes due to the
increased flow of the fluid 18 (e.g., to compensate for
increased fluid friction in the annulus 20 between the bit
14 and the wing valve 28 resulting in increased equivalent
circulating density). The data acquisition and control
interface 94 receives indications (e.g., from the sensors
58, 60, 62, 66, 67) that the flow rate of the fluid 18 has
increased, and the hydraulics model 92 in response
determines that a changed annulus pressure is desired to
maintain the desired downhole pressure, and the controller
96 uses the changed desired annulus pressure as a setpoint
to control operation of the choke 34.
In a slightly overbalanced managed pressure drilling
operation, the setpoint pressure would likely decrease, due
to the increased equivalent circulating density, in which
case flow restriction through the choke 34 would be
decreased in response.
In step 137, the restriction to flow of the fluid 18
through the choke 34 is changed, due to the changed desired
annulus pressure in step 136. As discussed above, the
controller 96 controls operation of the choke 34, in this
case changing the restriction to flow through the choke to
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 21 -
obtain the changed setpoint pressure. Also as discussed
above, the setpoint pressure could increase or decrease.
Steps 135, 136 and 137 are depicted in the FIG. 4
flowchart as being performed concurrently, since the
setpoint pressure and mud return choke restriction can
continuously vary, whether in response to each other, in
response to the change in the mud pump output and in
response to other conditions, as discussed above.
In step 138, drilling of the wellbore 12 resumes. When
another connection is needed in the drill string 16, the
steps 102-138 can be repeated.
Steps 140 and 142 are included in the FIG. 4 flowchart
for the connection method 100 to emphasize that the control
system 90 continues to operate throughout the method. That
is, the data acquisition and control interface 94 continues
to receive data from the sensors 36, 38, 40, 44, 46, 54, 56,
58, 62, 64, 66, 67 and supplies appropriate data to the
hydraulics model 92. The hydraulics model 92 continues to
determine the desired annulus pressure corresponding to the
desired downhole pressure. The controller 96 continues to
use the desired annulus pressure as a setpoint pressure for
controlling operation of the choke 34.
It will be appreciated that all or most of the steps
described above may be conveniently automated using the
control system 90. For example, the controller 96 may be
used to control operation of any or all of the flow control
devices 34, 74, 76, 78, 81 automatically in response to
input from the data acquisition and control interface 94.
Human intervention would preferably be used to indicate
to the control system 90 when it is desired to begin the
connection process (step 102), and then to indicate when a
drill pipe connection has been made (step 118), but
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 22 -
substantially all of the other steps could be automated
(i.e., by suitably programming the software elements of the
control system 90). However, it is envisioned that all of
the steps 102-142 can be automated, for example, if a
suitable top drive drilling rig (or any other drilling rig
which enables drill pipe connections to be made without
human intervention) is used.
Referring additionally now to FIG. 5, another
configuration of the control system 90 is representatively
illustrated. The control system 90 of FIG. 5 is very
similar to the control system of FIG. 3, but differs at
least in that a predictive device 148 and a data validator
150 are included in the control system of FIG. 5.
The predictive device 148 preferably comprises one or
more neural network models for predicting various well
parameters. These parameters could include outputs of any
of the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64,
66, 67, the annulus pressure setpoint output from the
hydraulic model 92, positions of flow control devices 34,
74, 76, 78, drilling fluid 18 density, etc. Any well
parameter, and any combination of well parameters, may be
predicted by the predictive device 148.
The predictive device 148 is preferably "trained" by
inputting present and past actual values for the parameters
to the predictive device. Terms or "weights" in the
predictive device 148 may be adjusted based on derivatives
of output of the predictive device with respect to the
terms.
The predictive device 148 may be trained by inputting
to the predictive device data obtained during drilling,
while making connections in the drill string 16, and/or
during other stages of an overall drilling operation. The
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 23 -
predictive device 148 may be trained by inputting to the
predictive device data obtained while drilling at least one
prior wellbore.
The training may include inputting to the predictive
device 148 data indicative of past errors in predictions
produced by the predictive device. The predictive device
148 may be trained by inputting data generated by a computer
simulation of the well drilling system 10 (including the
drilling rig, the well, equipment utilized, etc.).
Once trained, the predictive device 148 can accurately
predict or estimate what value one or more parameters should
have in the present and/or future. The predicted parameter
values can be supplied to the data validator 150 for use in
its data validation processes.
The predictive device 148 does not necessarily comprise
one or more neural network models. Other types of
predictive devices which may be used include an artificial
intelligence device, an adaptive model, a nonlinear function
which generalizes for real systems, a genetic algorithm, a
linear system model, and/or a nonlinear system model,
combinations of these, etc.
The predictive device 148 may perform a regression
analysis, perform regression on a nonlinear function and may
utilize granular computing. An output of a first principle
model may be input to the predictive device 148 and/or a
first principle model may be included in the predictive
device.
The predictive device 148 receives the actual parameter
values from the data validator 150, which can include one or
more digital programmable processors, memory, etc. The data
validator 150 uses various pre-programmed algorithms to
determine whether sensor measurements, flow control device
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 24 -
positions, etc., received from the data acquisition &
control interface 94 are valid.
For example, if a received actual parameter value is
outside of an acceptable range, unavailable (e.g., due to a
non-functioning sensor) or differs by more than a
predetermined maximum amount from a predicted value for that
parameter (e.g., due to a malfunctioning sensor), then the
data validator 150 may flag that actual parameter value as
being "invalid." Invalid parameter values may not be used
for training the predictive device 148, or for determining
the desired annulus pressure setpoint by the hydraulics
model 92. Valid parameter values would be used for training
the predictive device 148, for updating the hydraulics model
92, for recording to the data acquisition & control
interface 94 database and, in the case of the desired
annulus pressure setpoint, transmitted to the controller 96
for controlling operation of the flow control devices 34,
74, 76, 78.
The desired annulus pressure setpoint may be
communicated from the hydraulics model 92 to each of the
data acquisition & control interface 94, the predictive
device 148 and the controller 96. The desired annulus
pressure setpoint is communicated from the hydraulics model
92 to the data acquisition & control interface for recording
in its database, and for relaying to the data validator 150
with the other actual parameter values.
The desired annulus pressure setpoint is communicated
from the hydraulics model 92 to the predictive device 148
for use in predicting future annulus pressure setpoints.
However, the predictive device 148 could receive the desired
annulus pressure setpoint (along with the other actual
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 25 -
parameter values) from the data validator 150 in other
examples.
The desired annulus pressure setpoint is communicated
from the hydraulics model 92 to the controller 96 for use in
case the data acquisition & control interface 94 or data
validator 150 malfunctions, or output from these other
devices is otherwise unavailable. In that circumstance, the
controller 96 could continue to control operation of the
various flow control devices 34, 74, 76, 78 to
maintain/achieve the desired pressure in the annulus 20 near
the surface.
The predictive device 148 is trained in real time, and
is capable of predicting current values of one or more
sensor measurements based on the outputs of at least some of
the other sensors. Thus, if a sensor output becomes
unavailable, the predictive device 148 can supply the
missing sensor measurement values to the data validator 150,
at least temporarily, until the sensor output again becomes
available.
If, for example, during the drill string connection
process described above, one of the flowmeters 62, 64, 66
malfunctions, or its output is otherwise unavailable or
invalid, then the data validator 150 can substitute the
predicted flowmeter output for the actual (or nonexistent)
flowmeter output. It is contemplated that, in actual
practice, only one or two of the flowmeters 62, 64, 66 may
be used. Thus, if the data validator 150 ceases to receive
valid output from one of those flowmeters, determination of
the proportions of fluid 18 flowing through the standpipe
line 26 and bypass line 72 could not be readily
accomplished, if not for the predicted parameter values
output by the predictive device 148. It will be appreciated
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 26 -
that measurements of the proportions of fluid 18 flowing
through the standpipe line 26 and bypass line 72 are very
useful, for example, in calculating equivalent circulating
density and/or friction pressure by the hydraulics model 92
during the drill string connection process.
Validated parameter values are communicated from the
data validator 150 to the hydraulics model 92 and to the
controller 96. The hydraulics model 92 utilizes the
validated parameter values, and possibly other data streams,
to compute the pressure currently present downhole at the
point of interest (e.g., at the bottom of the wellbore 12,
at a problematic zone, at a casing shoe, etc.), and the
desired pressure in the annulus 20 near the surface needed
to achieve a desired downhole pressure.
The data validator 150 is programmed to examine the
individual parameter values received from the data
acquisition & control interface 94 and determine if each
falls into a predetermined range of expected values. If the
data validator 150 detects that one or more parameter values
it received from the data acquisition & control interface 94
is invalid, it may send a signal to the predictive device
148 to stop training the neural network model for the faulty
sensor, and to stop training the other models which rely
upon parameter values from the faulty sensor to train.
Although the predictive device 148 may stop training
one or more neural network models when a sensor fails, it
can continue to generate predictions for output of the
faulty sensor or sensors based on other, still functioning
sensor inputs to the predictive device. Upon identification
of a faulty sensor, the data validator 150 can substitute
the predicted sensor parameter values from the predictive
device 148 to the controller 96 and the hydraulics model 92.
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 27 -
Additionally, when the data validator 150 determines that a
sensor is malfunctioning or its output is unavailable, the
data validator can generate an alarm and/or post a warning,
identifying the malfunctioning sensor, so that an operator
can take corrective action.
The predictive device 148 is preferably also able to
train a neural network model representing the output of the
hydraulics model 92. A predicted value for the desired
annulus pressure setpoint is communicated to the data
validator 150. If the hydraulics model 92 has difficulties
in generating proper values or is unavailable, the data
validator 150 can substitute the predicted desired annulus
pressure setpoint to the controller 96.
Referring additionally now to FIG. 6, an example of the
predictive device 148 is representatively illustrated, apart
from the remainder of the control system 90. In this view,
it may be seen that the predictive device 148 includes a
neural network model 152 which outputs predicted current
(yn) and/or future (v
, _. n+1 1 y+2, ...) values for a parameter y.
Various other current and/or past values for parameters
a, b, c, ... are input to the neural network model 152 for
training the neural network model, for predicting the
parameter y values, etc. The parameters a, b, c, ..., y, ...
may be any of the sensor measurements, flow control device
positions, physical parameters (e.g., mud weight, wellbore
depth, etc.), etc. described above.
Current and/or past actual and/or predicted values for
the parameter y may also be input to the neural network
model 152. Differences between the actual and predicted
values for the parameter y can be useful in training the
neural network model 152 (e.g., in minimizing the
differences between the actual and predicted values).
CA 02832720 2013-10-08
WO 2012/154167
PCT/US2011/035751
- 28 -
During training, weights are assigned to the various
input parameters and those weights are automatically
adjusted such that the differences between the actual and
predicted parameter values are minimized. If the underlying
structure of the neural network model 152 and the input
parameters are properly chosen, training should result in
very little difference between the actual parameter values
and the predicted parameter values after a suitable (and
preferably short) training time.
It can be useful for a single neural network model 152
to output predicted parameter values for only a single
parameter. Multiple neural network models 152 can be used
to predict values for respective multiple parameters. In
this manner, if one of the neural network models 152 fails,
the others are not affected.
However, efficient utilization of resources might
dictate that a single neural network model 152 be used to
predict multiple parameter values. Such a configuration is
representatively illustrated in FIG. 7, in which the neural
network model 152 outputs predicted values for multiple
parameters w, x, y ....
If multiple neural networks are used, it is not
necessary for all of the neural networks to share the same
inputs. In an example representatively illustrated in FIG.
8, two neural network models 152, 154 are used. The neural
network models 152, 154 share some of the same input
parameters, but the model 152 has some parameter input
values which the model 154 does not share, and the model 154
has parameter input values which are not input to the model
152.
If a neural network model 152 outputs predicted values
for only a single parameter associated with a particular
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 29 -
sensor (or other source for an actual parameter value), then
if that sensor (or other actual parameter value source)
fails, the neural network model which predicts its output
can be used to supply the parameter values while operations
continue uninterrupted. Since the neural network model 152
in this situation is used only for predicting values for a
single parameter, training of the neural network model can
be conveniently stopped as soon as the failure of the sensor
(or other actual parameter value source) occurs, without
affecting any of the other neural network models being used
to predict other parameter values.
Referring additionally now to FIG. 9, another
configuration of the well drilling system 10 is
representatively and schematically illustrated. The
configuration of FIG. 9 is similar in most respects to the
configuration of FIG. 2.
However, in the FIG. 9 configuration, the flow control
device 78 and flow restrictor 80 are included with the flow
control device 74 and flowmeter 64 in a separate flow
diversion unit 156. The flow diversion unit 156 can be
supplied as a "skid" for convenient transport and
installation at a drilling rig site. The choke manifold 32,
pressure sensor 46 and flowmeter 58 may also be provided as
a separate unit.
Note that use of the flowmeters 66, 67 is optional.
For example, the flow through the standpipe line 26 can be
inferred from the outputs of the flowmeters 62, 64, and the
flow through the mud return line 73 can be inferred from the
outputs of the flowmeters 58, 64.
Referring additionally now to FIG. 10, another
configuration of the well drilling system 10 is
representatively and schematically illustrated. In this
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 30 -
configuration, the flow control device 76 is connected
upstream of the rig's standpipe manifold 70. This
arrangement has certain benefits, such as, no modifications
are needed to the rig's standpipe manifold 70 or the line
between the manifold and the kelley, the rig's standpipe
bleed valve 82 can be used to vent the standpipe 26 as in
normal drilling operations (no need to change procedure by
the rig's crew, no need for a separate venting line from the
flow diversion unit 156), etc.
The flow control device 76 can be interconnected
between the rig pump 68 and the standpipe manifold 70 using,
for example, quick connectors 84 (such as, hammer unions,
etc.). This will allow the flow control device 76 to be
conveniently adapted for interconnection in various rigs'
pump lines.
A specially adapted fully automated flow control device
76 (e.g., controlled automatically by the controller 96) can
be used for controlling flow through the standpipe line 26,
instead of using the conventional standpipe valve in a rig's
standpipe manifold 70. The entire flow control device 81
can be customized for use as described herein (e.g., for
controlling flow through the standpipe line 26 in
conjunction with diversion of fluid 18 between the standpipe
line and the bypass line 72 to thereby control pressure in
the annulus 20, etc.), rather than for conventional drilling
purposes.
It may now be fully appreciated that the above
disclosure provides substantial improvements to the art of
pressure and flow control in drilling operations. Among
these improvements is the incorporation of the predictive
device 148 and data validator 150 into the pressure and flow
control system 90, whereby outputs of sensors and the
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 31 -
hydraulic model 92 can be supplied, even if such sensor
and/or hydraulic model outputs become unavailable during a
drilling operation.
The above disclosure provides a well drilling system 10
for use with a pump 68 which pumps drilling fluid 18 through
a drill string 16 while drilling a wellbore 12. A flow
control device 81 regulates flow from the pump 68 to an
interior of the drill string 16, with the flow control
device 81 being interconnected between the pump 68 and a rig
standpipe manifold 70. Another flow control device 74
regulates flow from the pump 68 to a line 75 in
communication with an annulus 20 formed between the drill
string 16 and the wellbore 12. Flow is simultaneously
permitted through the flow control devices 74, 81.
The flow control device 81 may be operable
independently from operation of the flow control device 74.
The pump 68 may be a rig mud pump in communication via
the flow control device 81 with a standpipe line 26 for
supplying the drilling fluid 18 to the interior of the drill
string 16. The system 10 is preferably free of any other
pump which applies pressure to the annulus 20.
The system 10 can also include another flow control
device 34 which variably restricts flow from the annulus 20.
An automated control system 90 may control operation of the
flow control devices 34, 74 to maintain a desired annulus
pressure while a connection is made in the drill string 16.
The control system 90 may also control operation of the flow
control device 81 to maintain the desired annulus pressure
while the connection is made in the drill string 16.
The above disclosure also describes a method of
maintaining a desired bottom hole pressure during a well
drilling operation. The method includes the steps of:
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 32 -
dividing flow of drilling fluid 18 between a line 26 in
communication with an interior of a drill string 16 and a
line 75 in communication with an annulus 20 formed between
the drill string 16 and a wellbore 12; the flow dividing
step including permitting flow through a standpipe flow
control device 81 interconnected between a pump 68 and a rig
standpipe manifold 70, the standpipe manifold 70 being
interconnected between the standpipe flow control device 81
and the drill string 16.
The flow dividing step may also include permitting flow
through a bypass flow control device 74 interconnected
between the pump 68 and the annulus 20, while flow is
permitted through the standpipe flow control device 81.
The method may also include the step of closing the
standpipe flow control device 81 after pressures in the line
26 in communication with the interior of the drill string 16
and the line 75 in communication with the annulus 20
equalize.
The method may include the steps of: making a
connection in the drill string 16 after the step of closing
the standpipe flow control device 81; then permitting flow
through the standpipe flow control device 81 while
permitting flow through the bypass flow control device 74;
and then closing the bypass flow control device 74 after
pressures again equalize in the line 26 in communication
with the interior of the drill string 16 and in the line 75
in communication with the annulus 20.
The method may also include the step of permitting flow
through another flow control device (e.g., choke 34)
continuously during the flow dividing, standpipe flow
control device closing, connection making and bypass flow
control device closing steps, thereby maintaining a desired
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 33 -
annulus pressure corresponding to the desired bottom hole
pressure.
The method may also include the step of determining the
desired annulus pressure in response to input of sensor
measurements to a hydraulics model 92 during the drilling
operation. The step of maintaining the desired annulus
pressure may include automatically varying flow through the
flow control device (e.g., choke 34) in response to
comparing a measured annulus pressure with the desired
annulus pressure.
The above disclosure also describes a method 100 of
making a connection in a drill string 16 while maintaining a
desired bottom hole pressure. The method 100 includes the
steps of:
pumping a drilling fluid 18 from a rig mud pump 68 and
through a mud return choke 34 during the entire connection
making method 100;
determining a desired annulus pressure which
corresponds to the desired bottom hole pressure during the
entire connection making method 100, the annulus 20 being
formed between the drill string 16 and a wellbore 12;
regulating flow of the drilling fluid 18 through the
mud return choke 34, thereby maintaining the desired annulus
pressure, during the entire connection making method 100;
increasing flow through a bypass flow control device 74
and decreasing flow through a standpipe flow control device
81 interconnected between the rig mud pump 68 and a rig
standpipe manifold 70, thereby diverting at least a portion
of the drilling fluid flow from a line 26 in communication
with an interior of the drill string 16 to a line 75 in
communication with the annulus 20;
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 34 -
preventing flow through the standpipe flow control
device 81;
then making the connection in the drill string 16; and
then decreasing flow through the bypass flow control
device 74 and increasing flow through the standpipe flow
control device 81, thereby diverting at least another
portion of the drilling fluid flow to the line 26 in
communication with the interior of the drill string 16 from
the line 75 in communication with the annulus 20.
The steps of increasing flow through the bypass flow
control device 74 and decreasing flow through the standpipe
flow control device 81 may also include simultaneously
permitting flow through the bypass and standpipe flow
control devices 74, 81.
The steps of decreasing flow through the bypass flow
control device 74 and increasing flow through the standpipe
flow control device 81 further comprise simultaneously
permitting flow through the bypass and standpipe flow
control devices 74, 81.
The method 100 may also include the step of equalizing
pressure between the line 26 in communication with the
interior of the drill string 16 and the line 75 in
communication with the annulus 20. This pressure equalizing
step is preferably performed after the step of increasing
flow through the bypass flow control device 74, and prior to
the step of decreasing flow through the standpipe flow
control device 81.
The method 100 may also include the step of equalizing
pressure between the line 26 in communication with the
interior of the drill string 16 and the line 75 in
communication with the annulus 20. This pressure equalizing
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 35 -
step is preferably performed after the step of decreasing
flow through the bypass flow control device 74, and prior to
the step of increasing flow through the standpipe flow
control device 81.
The step of determining the desired annulus pressure
may include determining the desired annulus pressure in
response to input of sensor measurements to a hydraulics
model 92. The step of maintaining the desired annulus
pressure may include automatically varying flow through the
mud return choke 34 in response to comparing a measured
annulus pressure with the desired annulus pressure.
The steps of decreasing flow through the standpipe flow
control device 81, preventing flow through the standpipe
flow control device 81 and increasing flow through the
standpipe flow control device 81 may be automatically
controlled by a controller 96.
It is to be understood that the various embodiments of
the present disclosure 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 the present
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 foregoing description of representative
embodiments in this disclosure, directional terms, such as
"above," "below," "upper," "lower," etc., are used for
convenience in referring to the accompanying drawings. In
general, "above," "upper," "upward" and similar terms refer
to a direction toward the earth's surface along a wellbore,
and "below," "lower," "downward" and similar terms refer to
CA 02832720 2013-10-08
WO 2012/154167 PCT/US2011/035751
- 36 -
a direction away from the earth's surface along the
wellbore.
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 the present 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 present invention being
limited solely by the appended claims and their equivalents.
