Note: Descriptions are shown in the official language in which they were submitted.
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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.
The means for regulating pressure in the annulus can
include a choke interconnected in the mud return line and,
in some applications, a backpressure pump to apply pressure
to the annulus while connections are made in the drill pipe
string. Unfortunately, use of a backpressure pump requires
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substantial capital investment, the additional pump takes up
scarce space on offshore rigs, the pump output is difficult
to control accurately and use of the pump interferes with
normal operations on a drilling rig.
Therefore, it may be seen that improvements are needed
in the art of controlling pressure and flow in drilling
operations. These improvements may include the elimination
of a separate backpressure pump in drilling operations, but
the improvements could be utilized in conjunction with a
backpressure pump, if desired.
SUMMARY
In carrying out the principles of the present
disclosure, systems and methods are provided which solve at
least one problem in the art. One example is described
below in which flow through a standpipe line and flow
through a bypass line are independently variable, thereby
enabling more accurate control over flow and pressure during
the drilling operation. Another example is described below
in which, after a drill pipe connection is made, the
standpipe line and drill pipe are filled and pressurized
prior to closing off flow through the bypass line.
In one aspect, a well drilling system is provided by
the disclosure below for use with a pump which pumps
drilling fluid through a drill string while drilling a
wellbore. The system includes a flow control device which
regulates flow from the pump to an interior of the drill
string, and another flow control device which regulates flow
from the pump through a line in communication with an
annulus formed between the drill string and the wellbore.
Flow is simultaneously permitted through the flow control
devices.
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In another aspect, a method of maintaining a desired
bottom hole pressure during a well drilling operation is
provided. The method includes the step of: dividing flow of
drilling fluid between a line in communication with an
interior of a drill string and a line in communication with
an annulus formed between the drill string and a wellbore.
The flow dividing step includes permitting flow through a
flow control device interconnected between a pump and the
interior of the drill string. The flow dividing step
further includes permitting flow through another flow
control device interconnected between the pump and the
annulus, while flow is permitted through the first flow
control device.
In yet another aspect, a method of making a connection
in a drill string, while maintaining a desired bottom hole
pressure, includes the steps of:
pumping a drilling fluid from a rig mud pump and
through a mud return choke during the entire connection
making method;
determining a desired annulus pressure which
corresponds to the desired bottom hole pressure during the
entire connection making method, the annulus being formed
between the drill string and a wellbore;
regulating flow of the drilling fluid through the mud
return choke, thereby maintaining the desired annulus
pressure, during the entire connection making method;
increasing flow through a bypass flow control device
and decreasing flow through a standpipe flow control device,
thereby diverting at least a portion of the drilling fluid
flow from a line in communication with an interior of the
drill string to a line in communication with the annulus;
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preventing flow through the standpipe flow control
device;
then making the connection in the drill string; and
then decreasing flow through the bypass flow control
device and increasing flow through the standpipe flow
control device, thereby diverting at least a portion of the
drilling fluid flow to the line in communication with the
interior of the drill string from the line in communication
with the annulus.
These and other features, advantages, benefits and
objects will become apparent to one of ordinary skill in the
art upon careful consideration of the detailed description
of representative embodiments of the disclosure hereinbelow
and the accompanying drawings, in which similar elements are
indicated in the various figures using the same reference
numbers.
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 view of a pressure and flow
control system which may be used in the well drilling system
and method; and
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.
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DETAILED DESCRIPTION
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 following description of the representative
embodiments of the 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
a direction away from the earth's surface along the
wellbore.
Representatively and schematically illustrated in FIG.
1 is a well drilling system 10 and associated method which
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
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
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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
accurately 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 greater than a pore pressure of the formation,
without exceeding a fracture pressure of the formation. In
typical underbalanced drilling, it is desired to maintain
the bottom hole pressure somewhat less than the pore
pressure, thereby obtaining a controlled influx of fluid
from the formation.
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
(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.
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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 may 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, bottom hole pressure can be conveniently regulated by
varying the backpressure applied to the annulus 20. A
hydraulics model can be used, as described more fully below,
to determine a pressure applied to the annulus 20 at or near
the surface which will result in a desired bottom hole
pressure, so that an operator (or an automated control
system) can readily determine how to regulate the pressure
applied to the annulus at or near the surface (which can be
conveniently measured) in order to obtain the desired bottom
hole pressure.
Pressure applied to the annulus 20 can be measured at
or near the surface via a variety of pressure sensors 36,
38, 40, each of which is in communication with the annulus.
Pressure sensor 36 senses pressure below the RCD 22, but
above a blowout preventer (BOP) stack 42. Pressure sensor
38 senses pressure in the wellhead below the BOP stack 42.
Pressure sensor 40 senses pressure in the 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
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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 the sensors is useful to
the hydraulics model in determining what the pressure
applied to the annulus 20 should be during the drilling
operation.
In addition, the drill string 16 may include its own
sensors 60, for example, to directly measure bottom hole
pressure. Such sensors 60 may be of the type known to those
skilled in the art as pressure while drilling (PWD),
measurement while drilling (MWD) and/or logging while
drilling (LWD). 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-
slip, etc.), formation characteristics (such as resistivity,
density, etc.) and/or other measurements. Various forms of
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 flowmeter 62 or any other flowmeters.
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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 bottom hole pressure,
unless the fluid 18 is flowing through the choke.
In conventional overbalanced drilling operations, such
a situation will arise 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 bottom hole
pressure be regulated solely by the density of the fluid 18.
In the system 10, however, flow of the fluid 18 through
the choke 34 can be maintained, even though the fluid does
not circulate through the 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.
Instead, the fluid 18 is flowed from the pump 68 to the
choke manifold 32 via a bypass line 72, 75 when a connection
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is made in the drill string 16. 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.
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
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.
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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.
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, and 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
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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 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
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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 bottom hole pressure by
maintaining a desired annulus pressure at or near the
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
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additional elements, other additional elements and/or
functions could be provided, etc.
The hydraulics model 92 is used in the control system
90 to determine the desired annulus pressure at or near the
surface to achieve the desired bottom hole pressure. Data
such as well geometry, fluid properties and offset well
information (such as geothermal gradient and pore pressure
gradient, etc.) are utilized by the hydraulics model 92 in
making this determination, as well as real-time sensor data
acquired by the data acquisition and control interface 94.
Thus, there is a continual two-way transfer of data and
information between the hydraulics model 92 and the data
acquisition and control interface 94. For the purposes of
this disclosure, it is important to appreciate that the data
acquisition and control interface 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.
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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 through the choke as needed) to maintain the
setpoint pressure in the annulus 20.
This is accomplished by comparing the setpoint pressure
to a measured annulus pressure (such as the pressure sensed
by any of the sensors 36, 38, 40), and increasing flow
through the choke 34 if the measured pressure is greater
than the setpoint pressure, and decreasing flow through the
choke if the measured pressure is less than the setpoint
pressure. Of course, if the setpoint and measured pressures
are the same, then no adjustment of the choke 34 is
required. This process is preferably automated, so that no
human intervention is required, although human intervention
may be used if desired.
The controller 96 may also be used to control operation
of the 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
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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,
other than to initiate each process in turn.
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
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determines that a changed annulus pressure is desired to
maintain the desired bottom hole 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 through the choke 34 would be decreased 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
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(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 eventually ceases when the
bypass flow control device 74 is opened, since the bypass
line 72 becomes the path of least resistance to flow. 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 bottom hole 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 through the choke 34 would be decreased 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
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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.
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 (not shown) 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 broken off of
the drill string 16, another stand of drill pipe is
connected to the drill string, and the kelley or top drive
is made up to the top of the drill string. This step is
performed in accordance with conventional drilling practice.
In step 120, the standpipe bleed valve is closed. The
standpipe line 26 is, thus, isolated again from atmosphere,
but the standpipe line and the newly added stand of drill
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pipe is substantially empty (i.e., not filled with the fluid
18) and un-pressurized.
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
the flow control device is gradually opened to slowly fill
the standpipe line 26 and drill string 16, and then fully
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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
data acquisition and control interface 94 receives
indications (e.g., from the sensors 60, 64, 66, 67) that the
15 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 bottom hole pressure, and the
controller 96 uses the changed desired annulus pressure as a
20 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
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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 bottom hole 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 through the choke 34 would be increased 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.
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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 bottom hole 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
(i.e., by suitably programming the software elements of the
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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.
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 elimination of the necessity for use
of a separate backpressure pump to maintain annulus pressure
during drill pipe connections. Also among these
improvements is the coordinated gradual diversion of
drilling fluid 18 between the standpipe line 26 and bypass
line 72 in a manner which eliminates, or at least
substantially eliminates, undesirable pressure transients in
the annulus 20 when connections are made.
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. 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.
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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:
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 the
interior of the drill string 16; and the flow dividing step
including 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;
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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
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;
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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, 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;
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
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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
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.
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 scope
of the present invention being limited solely by the appended
claims.
