PREEMPTIVE SETPOINT PRESSURE OFFSET FOR FLOW
DIVERSION 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 wellbore 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, rotating
blowout preventer, etc.) which seals about the drill pipe as
the wellbore is being drilled.
It will, therefore, be appreciated that improvements
would be beneficial in the arts of controlling pressure and
controlling flow in drilling operations.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a representative view of a well drilling
system and method embodying principles of the present
disclosure .
FIG. 2 is a representative view of another
configuration of the well drilling system.
FIG. 3 is a representative block diagram of a pressure
and flow control system which may be used in the well
drilling system and method.
FIG. 4 is a representative 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 representative block diagram of another
configuration of the pressure and flow control system.
FIGS. 6-8 are representative 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 representative view of another
configuration of the well drilling system.
FIG. 10 is a representative view of another
configuration of the well drilling system.
FIG. 11 is a flowchart for a method of controlling well
pressure, which method can embody principles of this
disclosure .
DETAILED DESCRIPTION
Representatively and schematically illustrated in FIG.
1 is a well drilling system 10 and associated method 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 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 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 wellbore pressure is very important in
managed pressure drilling, and in other types of drilling
operations. Preferably, the wellbore 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 wellbore pressure just slightly greater than a
pore pressure of the formation penetrated by the wellbore,
without exceeding a fracture pressure of the formation. This
technique is especially useful in situations where the
margin between pore pressure and fracture pressure is
relatively small.
In typical underbalanced drilling, it is desired to
maintain the wellbore 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 wellbore 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 wellbore
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 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,
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, stickslip,
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
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.
Although this might require some additional piping 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, and still
remain within the scope 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 wellbore 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 .
In the FIG. 1 example, 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 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 preserve
the use of the flow control device 76. 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 example, 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 7 4 , 7 6 , 7 8
and chokes 3 4 are preferably remotely and automatically
controllable to maintain a desired downhole pressure by
maintaining a desired annulus pressure at or near the
surface. However, any one or more of these flow control
devices 7 4 , 7 6 , 7 8 and chokes 3 4 could be manually
controlled, in keeping with the scope of this disclosure.
A pressure and flow control system 9 0 which may be used
in conjunction with the system 1 0 and associated methods of
FIGS. 1 & 2 is representatively illustrated in FIG. 3 . The
control system 9 0 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 9 0 includes a hydraulics model 9 2 , a
data acquisition and control interface 9 4 and a controller
9 6 (such as a programmable logic controller or PLC, a
suitably programmed computer, etc.). Although these elements
9 2 , 9 4 , 9 6 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 9 2 is used in the control system
9 0 to determine the desired annulus pressure at or near the
surface to achieve a 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 9 2 in making this
determination, as well as real-time sensor data acquired by
the data acquisition and control interface 9 4 .
Thus, there is a continual two-way transfer of data and
information between the hydraulics model 9 2 and the data
acquisition and control interface 9 4 . It is important to
appreciate that the data acquisition and control interface
9 4 operates to maintain a substantially continuous flow of
real-time data from the sensors 4 4 , 5 4 , 6 6 , 6 2 , 6 4 , 6 0 , 5 8 ,
4 6 , 3 6 , 3 8 , 4 0 , 5 6 , 6 7 to the hydraulics model 9 2 , 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 9 2 in the control system 9 0 is REAL TIME HYDRAULICS
(TM) marketed 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 9 0 in
keeping with the principles of this disclosure.
A suitable data acquisition and control interface for
use as the data acquisition and control interface 9 4 in the
control system 9 0 are SENTRY (TM) and INSITE (TM) marketed by
Halliburton Energy Services, Inc. Any suitable data
acquisition and control interface may be used in the control
system 9 0 in keeping with the principles of this disclosure.
The controller 9 6 operates to maintain a desired
setpoint annulus pressure by controlling operation of the
mud return choke 3 4 . When an updated desired annulus
pressure is transmitted from the data acquisition and
control interface 9 4 to the controller 9 6 , 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
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
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,
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
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
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
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 12 6 . 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
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
20 (e.g., to compensate for increased fluid friction
resulting in increased equivalent circulating density) . The
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
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
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
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, 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 continues to supply 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
substantially all of the other steps could be automated
(e.g., 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
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
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
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 can be output by the predictive
device 148. It will be appreciated 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, or during other processes (such as,
telemetry methods which divert flow from the drill string
16, etc.) which can cause changes in equivalent circulating
density and/or friction pressure.
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 9 6 and the hydraulics model 9 2 .
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 9 2 . A predicted value for the desired
annulus pressure setpoint is communicated to the data
validator 150 . If the hydraulics model 9 2 has difficulties
in generating proper values or is unavailable, the data
validator 150 can substitute the predicted desired annulus
pressure setpoint to the controller 9 6 .
Referring additionally now to FIG. 6 , an example of the
predictive device 148 is representatively illustrated, apart
from the remainder of the control system 9 0 . In this view,
it may be seen that the predictive device 148 includes a
neural network model 152 which outputs predicted current
(y ) and/or future (y +i , ···) 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).
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
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
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 .
In the FIG. 10 example, a remotely controllable valve
or other flow control device 160 is optionally used to
divert flow of the fluid 18 from the standpipe line 26 to
the mud return line 30, in order to transmit signals, data,
commands, etc. to downhole tools (such as the FIG. 1 bottom
hole assembly including the sensors 60, other equipment,
including mud motors, deflection devices, steering controls,
etc.). The device 160 is controlled by a telemetry
controller 162, which can encode information as a sequence
of flow diversions detectable by the downhole tools (e.g., a
certain decrease in flow through a downhole tool will result
from a corresponding diversion of flow by the device 160
from the standpipe line 26 to the mud return line 30).
A suitable telemetry controller and a suitable remotely
operable flow control device are provided in the GEOSPAN(
TM) system marketed by Halliburton Energy Services,
Inc. The telemetry controller 162 can be connected to the
INSITE(TM) system or other acquisition and control interface
94 in the control system 90. However, other types of
telemetry controllers and flow control devices may be used
in keeping with the scope of this disclosure.
In a method of controlling well pressure described more
fully below, the desired annulus pressure setpoint is
adjusted in response to an instruction being transmitted to
divert flow from the standpipe line 26 to the mud return
line 30. Such an instruction could be transmitted at step
109 of the connection method 100 described above. As another
example, the instruction could be transmitted by the
telemetry controller 162 to the device 160, in order to
transmit a corresponding telemetry signal to a downhole
tool. In other examples, flow of the fluid 18 may be
diverted from the standpipe line 26 and drill string 16 for
purposes other than making a connection in the drill string
or transmitting signals.
The diversion of flow from the drill string 16 will
result in reduced friction pressure, thereby reducing
pressure in the wellbore 12. In situations where the
initiation of the flow diversion is known (e.g., an
instruction will be transmitted to divert the flow) , it
would be preferable to also initiate a change in the annulus
pressure setpoint, to mitigate any pressure changes in the
well due to the flow diversion.
This is quite different from changing the annulus
pressure setpoint in response to a measured change in
pressure downhole, in response to a measured change in flow
at the surface, etc. Instead, the change in the annulus
pressure setpoint is preferably made directly in response to
the instruction to change the flow through the drill string
16.
Thus, actual change(s) in flow or pressure, etc. do not
have to occur, do not have to be detected by sensors and do
not have to be transmitted to the control system 90 for
evaluation of whether the annulus pressure setpoint should
be changed. Instead, the annulus pressure setpoint can be
changed immediately, preferably without any significant
change in pressure occurring downhole.
In practice, it typically will be known how much of the
flow of the fluid 18 will be diverted from the drill string
16 (this flow rate can also be measured by means of a
flowmeter 164, or deduced from the measurements of other
flowmeters 58, 60, 66, etc.), and the total flow of the
fluid will be known just prior to the instruction being
given to change the flow through the drill string. In these
situations, the expected pressure reduction due to reduced
flow through the drill string 16 and annulus 20 can be
calculated, and the annulus pressure setpoint can be
adjusted accordingly (e.g., increased), so that downhole
pressure remains substantially unchanged when the diversion
begins. Of course, if flow through the drill string 16 is
instead increased, then the expected pressure increase due
to the increased flow can be calculated, and the annulus
pressure setpoint can be adjusted accordingly (e.g.,
decreased) .
In a basic example, the annulus pressure setpoint is
typically equal to the desired downhole pressure, minus
hydrostatic pressure at the downhole location, minus
friction pressure. The friction pressure is calculated by
the hydraulic model 92, and is a function of fluid 18 flow
rate through the drill string 16 and annulus 20. Thus, an
expected change in flow rate will produce an expected change
in friction pressure, which can be readily calculated by the
hydraulic model 92.
Referring additionally now to FIG. 11, a flowchart for
a method 170 for controlling pressure in a well is
representatively illustrated. The method 170 may be used
with any of the drilling systems 10 described above, or the
method may be used with any other drilling systems, in
keeping with the scope of this disclosure.
In the FIG. 11 example, pressure fluctuations downhole
due to changes in flow through the drill string 16 and
annulus 20 are mitigated or completely prevented. Prior to a
change in flow, relevant parameters are measured (e.g., by
the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66,
67, 164) in step 172. These measurements inform a
determination of an expected flow change in step 174.
In one suitable technique, the diverted fluid 18 flow
rate can be calculated using the following equation:
Diverted Flow = e
((S dp p -C2 C /Cl (1)
where Standpipe is the actual measured pressure in the
standpipe line 26 during diversion of the fluid 18 (such as,
during transmission of telemetry signals, etc.), and CO, C I
and C2 are constants derived from a curve fit to measured
standpipe pressure versus flow rate through the standpipe.
In another example, the predictive device 148 can be
used to predict an expected flow rate change based on
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, 164 the annulus pressure setpoint
output from the hydraulic model 92, choke 34 size(s),
positions of flow control devices 34, 74, 76, 78, drilling
fluid 18 density, etc. Any well parameter (including current
and historical data), and any combination of well
parameters, may be utilized by the predictive device 148.
From the expected flow change, the hydraulic model 92
can predict the downhole pressure change due to the flow
change, and the change to the pressure setpoint needed to
mitigate this downhole pressure change. For example, if it
is determined that the flow change will result in reduced
pressure at a downhole location, an annulus pressure or
standpipe pressure setpoint can be appropriately increased
to offset the expected downhole pressure decrease.
In step 176, an instruction is transmitted to change
the flow rate through the drill string 16 and annulus 20 by,
for example, operating the device 160 of FIG. 10 to divert
(or to cease to divert) flow from the standpipe line 26 to
the mud return line, operating the flow diversion unit 156
or device 81 of FIG. 9 to change the flow through the
standpipe line, etc. Such an instruction could be
transmitted by the controller 96 to the flow diversion unit
156, by the controller 162 to the device 160, etc. Any
instruction which will result in a change in the rate of
flow through the drill string 16 and annulus 20 may be used
in keeping with the scope of this disclosure.
In one example, the INSITE(TM) system mentioned above
can issue an instruction or command to begin a downlink
process (surface to downhole telemetry), whereby flow
through the drill string 16 and annulus 20 is periodically
reduced. Such reduction in flow can potentially cause a
decrease in pressure downhole.
In step 178, the annulus pressure setpoint is adjusted
in response to the instruction being transmitted. If
desired, this step can include a requirement for
confirmation that the instruction will be executed, or at
least that the instruction was appropriately received, prior
to the annulus pressure setpoint being adjusted. Further
adjustments can be made as needed to maintain a desired
downhole pressure, for example, by monitoring various
parameters after the instruction to change flow is
transmitted, during the change in flow, after the change in
flow, etc.
By making the adjustment to the annulus pressure
setpoint in response to the instruction being transmitted,
downhole pressure changes are mitigated or prevented. Such
downhole pressure changes could otherwise possibly result in
fluid loss, fracturing of the formation surrounding the
wellbore, or failure of a casing shoe (e.g., due to
increased downhole pressure), or an influx of fluid into the
wellbore from the formation (e.g., due to reduced downhole
pressure ).
However, in some circumstances it may be useful to
permit a limited amount of pressure fluctuation downhole,
for example, to allow for communication with downhole tools
that respond to pressure changes, etc. In those
circumstances, the adjustment to the annulus pressure
setpoint can take into account some predetermined
permissible pressure variation downhole.
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 use of the method 170 to reduce or
eliminate pressure variations downhole due to changes in
flow through the drill string 16 and annulus 20. Where a
change in flow is preceded by a known stimulus (such as an
instruction to change the flow) , pressure variation due to
the change in flow can be preempted by promptly adjusting
the annulus pressure setpoint in response to the stimulus,
rather than waiting for the effects of the change in flow to
be detected.
A method 170 of controlling pressure in a well is
described above. In one example, the method 170 can include:
transmitting an instruction to change flow through an
annulus 20 formed radially between a drill string 16 and a
wellbore 12; and adjusting a pressure setpoint in response
to the transmitting.
The adjusting can be performed prior to flow through
the annulus 20 changing, and/or while flow through the
annulus 20 changes. The adjusting may be performed prior to
the flow change being detected by sensors 36, 38, 40, 44,
46, 54, 56, 58, 60, 62, 64, 66, 67, 164.
The flow change may be caused by diversion of flow from
the drill string 16 to a mud return line 30.
The transmitting can comprise encoding information as a
sequence of flow variations. For example, the encoded
information could be data, commands, instructions, etc. for
transmission to one or more downhole tools.
The transmitting comprises initiating a connection in
the drill string 16. For example, performance of the
connection method 100 will cause changes in flow through the
annulus 20 and drill string 16.
The method 170 can include predicting a change in the
flow based on measured well parameters. The method may
include predicting a downhole pressure change due to the
predicted change in the flow.
A well drilling system 10 is also described above. In
one example, the system 10 can include a flow control device
74 or 160 which varies flow through a drill string 16. A
control system 90 changes a pressure setpoint in response to
an instruction for the flow control device 74 or 160 to
change the flow through the drill string 16.
The flow control device 74 can divert flow from a
standpipe line 26 to a mud return line 30. The flow control
device 160 can divert flow from the drill string 16.
The control system 90 may predict a pressure change
which will result from the flow change. The pressure
setpoint can be adjusted by the predicted pressure change,
in response to the instruction.
The pressure setpoint may corresponds to a desired
pressure in a wellbore 12, and/or to a desired pressure as
measured in an annulus 20 at or near the earth's surface.
Also described above is a method 170 of controlling
pressure in a well, with the method 170 in one example
comprising transmitting an instruction to divert flow from a
drill string 16, and adjusting a pressure setpoint in
response to the transmitting.
The adjusting can be performed prior to flow through
the drill string 16 being diverted, and/or while flow
through the drill string 16 is diverted. The adjusting may
be performed prior to the diverting being detected by
sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67,
164.
It is to be understood that the various embodiments of
this 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 this disclosure. The
embodiments are described merely as examples of useful
applications of the principles of the disclosure, which
principles are 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.
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.

WHAT IS CLAIMED IS:
1 . A method of controlling pressure in a well, the
method comprising:
transmitting an instruction to change flow through an
annulus formed radially between a drill string and a
wellbore; and
adjusting a pressure setpoint in response to the
transmitting .
2 . The method of claim 1 , wherein the adjusting is
performed prior to flow through the annulus changing.
3 . The method of claim 1 , wherein the adjusting is
performed while flow through the annulus changes.
4 . The method of claim 1 , wherein the flow change is
caused by diversion of flow from the drill string to a mud
return line.
5 . The method of claim 1 , wherein the transmitting
comprises encoding information as a sequence of flow
variations .
6 . The method of claim 1 , wherein the transmitting
comprises initiating a connection in the drill string.
7 . The method of claim 1 , further comprising
predicting a change in the flow based on measured well
parameters .
8 . The method of claim 7 , further comprising
predicting a downhole pressure change due to the predicted
change in the flow.
9 . The method of claim 1 , wherein the adjusting is
performed prior to the flow change being detected by
sensors .
10. A well drilling system, comprising:
a flow control device which varies flow through a drill
string; and
a control system which changes a pressure setpoint in
response to an instruction for the flow control device to
change the flow through the drill string.
11. The system of claim 10, wherein the flow control
device diverts flow from a standpipe line to a mud return
line .
12. The system of claim 10, wherein the flow control
device diverts flow from the drill string.
13. The system of claim 10, wherein the control system
predicts a pressure change which will result from the flow
change .
14. The system of claim 13, wherein the pressure
setpoint is adjusted by the predicted pressure change, in
response to the instruction.
15. The system of claim 10, wherein the pressure
setpoint corresponds to a desired pressure in a wellbore,
16. The system of claim 10, wherein the pressure
setpoint corresponds to a desired pressure as measured in an
annulus at or near the earth's surface.
17. A method of controlling pressure in a well, the
method comprising:
transmitting an instruction to divert flow from a drill
string; and
adjusting a pressure setpoint in response to the
transmitting .
18. The method of claim 17, wherein the adjusting is
performed prior to flow through the drill string being
diverted.
19. The method of claim 17, wherein the adjusting is
performed while flow through the drill string is diverted.
20. The method of claim 17, wherein the flow change
caused by diversion of flow from the drill string to a mud
return line.
21. The method of claim 17, wherein the transmitting
comprises encoding information as a sequence of flow
diversions .
22. The method of claim 17, wherein the transmitting
comprises initiating a connection in the drill string.
23. The method of claim 17, further comprising
predicting a change in the flow based on measured well
parameters .
24. The method of claim 23, further comprising
predicting a downhole pressure change due to the predicted
change in the flow.
25. The method of claim 17, wherein the adjusting is
performed prior to the diverting being detected by sensors.