U.S. patent application number 14/380713 was filed with the patent office on 2015-03-26 for drilling operation control using multiple concurrent hydraulics models.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is Saad Saeed. Invention is credited to Saad Saeed.
Application Number | 20150083401 14/380713 |
Document ID | / |
Family ID | 49624203 |
Filed Date | 2015-03-26 |
United States Patent
Application |
20150083401 |
Kind Code |
A1 |
Saeed; Saad |
March 26, 2015 |
DRILLING OPERATION CONTROL USING MULTIPLE CONCURRENT HYDRAULICS
MODELS
Abstract
A control system for drilling a subterranean well can include
multiple concurrently running hydraulics models, each of the
hydraulics models outputting a pressure setpoint, in real time
during a drilling operation. A method of controlling a drilling
operation can comprise concurrently running multiple hydraulics
models during the drilling operation, and switching between outputs
of the multiple hydraulics models to control the drilling
operation, the switching being performed during the drilling
operation. Another method of controlling a drilling operation can
include controlling operation of at least one flow control device,
thereby maintaining a pressure at a pressure setpoint, and
selecting the pressure setpoint from among outputs of multiple
concurrently running hydraulics models.
Inventors: |
Saeed; Saad; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saeed; Saad |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
49624203 |
Appl. No.: |
14/380713 |
Filed: |
May 25, 2012 |
PCT Filed: |
May 25, 2012 |
PCT NO: |
PCT/US12/39586 |
371 Date: |
August 23, 2014 |
Current U.S.
Class: |
166/250.01 ;
166/244.1; 166/75.11; 166/91.1 |
Current CPC
Class: |
E21B 44/005 20130101;
E21B 44/00 20130101; E21B 41/0092 20130101; E21B 21/10 20130101;
E21B 21/08 20130101; E21B 34/02 20130101; E21B 47/06 20130101; E21B
33/085 20130101 |
Class at
Publication: |
166/250.01 ;
166/75.11; 166/91.1; 166/244.1 |
International
Class: |
E21B 34/02 20060101
E21B034/02; E21B 44/00 20060101 E21B044/00; E21B 41/00 20060101
E21B041/00; E21B 47/06 20060101 E21B047/06 |
Claims
1. A control system for drilling a subterranean well, the control
system comprising: multiple hydraulics models, whereby each of the
hydraulics models outputs a pressure setpoint, in real time during
a drilling operation.
2. The system of claim 1, further comprising a controller and a
selector, wherein the controller controls operation of at least one
device, and wherein the selector selects which of the multiple
pressure setpoints is input to the controller.
3. The system of claim 2, wherein the device comprises a flow
control device.
4. The system of claim 3, wherein the flow control device comprises
a choke which variably restricts flow from a wellbore.
5. The system of claim 3, wherein the flow control device controls
flow through a standpipe.
6. The system of claim 3, wherein the flow control device controls
flow between a standpipe and a mud return line.
7. The system of claim 1, wherein the multiple hydraulics models
comprise multiple instances of a same hydraulics model.
8. The system of claim 1, wherein the multiple hydraulics models
run concurrently.
9. A method of controlling a drilling operation, the method
comprising: running multiple hydraulics models during the drilling
operation; and switching between outputs of the multiple hydraulics
models to control the drilling operation, the switching being
performed during the drilling operation.
10. The method of claim 9, further comprising controlling operation
of at least one device, thereby maintaining a pressure at a
pressure setpoint output by one of the multiple concurrently
running hydraulics models.
11. The method of claim 10, wherein the device comprises a flow
control device.
12. The method of claim 11, wherein the flow control device
comprises a choke which variably restricts flow from a
wellbore.
13. The method of claim 11, wherein the flow control device
controls flow through a standpipe.
14. The method of claim 11, wherein the flow control device
controls flow between a standpipe and a mud return line.
15. The method of claim 9, wherein the switching further comprises
switching from a first hydraulics model output to a second
hydraulics model output.
16. The method of claim 9, wherein the switching is performed in
response to a change in an objective of the drilling operation.
17. The method of claim 9, wherein the switching is performed in
response to detection of an event.
18. The method of claim 9, wherein the switching is performed in
response to a comparison between a measured drilling parameter
value and the drilling parameter value as predicted by the
hydraulics models.
19. The method of claim 9, wherein the switching is performed
manually.
20. The method of claim 9, wherein the switching is performed
automatically.
21. The method of claim 9, wherein running the multiple hydraulics
models further comprises running the hydraulics models
concurrently.
22. A method of controlling a drilling operation, the method
comprising: controlling operation of at least one device, thereby
maintaining a pressure at a pressure setpoint; and selecting the
pressure setpoint from among outputs of multiple hydraulics
models.
23. The method of claim 22, wherein the selecting further comprises
switching from a first hydraulics model output to a second
hydraulics model output.
24. The method of claim 23, wherein the switching is performed in
response to a change in an objective of the drilling operation.
25. The method of claim 23, wherein the switching is performed in
response to detection of an event.
26. The method of claim 23, wherein the switching is performed in
response to a comparison between a measured drilling parameter
value and the drilling parameter value as predicted by the first
and second hydraulics models.
27. The method of claim 22, wherein the selecting is performed
manually.
28. The method of claim 22, wherein the selecting is performed
automatically.
29. The method of claim 22, wherein the hydraulics models are
concurrently running.
30. The method of claim 22, wherein the device comprises a flow
control device.
Description
TECHNICAL FIELD
[0001] This disclosure relates generally to equipment utilized and
operations performed in conjunction with a subterranean well and,
in one example described below, more particularly provides for
wellbore pressure control using multiple concurrently-running
hydraulics models.
BACKGROUND
[0002] A hydraulics model can be used to control a drilling
operation, for example, in managed pressure, underbalanced,
overbalanced or optimized pressure drilling. Typically, an
objective is to maintain wellbore pressure at a desired value
during the drilling operation. Unfortunately, such hydraulics
models are unlikely to be equally adept at outputting setpoints for
controlling the drilling operation in different circumstances
(e.g., drilling ahead, taking an influx, fluid loss, etc.).
[0003] Therefore, it will be appreciated that improvements are
continually needed in the art of controlling drilling
operations.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 is a representative partially cross-sectional view of
a well drilling system and associated method which can embody
principles of this disclosure.
[0005] FIG. 2 is a representative schematic view of another example
of the well drilling system and method.
[0006] FIG. 3 is a representative schematic view of a pressure and
flow control system which may be used with the system and method of
FIGS. 1 & 2.
[0007] FIG. 4 is a representative flowchart for a method of
controlling a drilling operation.
[0008] FIGS. 5 & 6 are representative flowcharts for further
examples of the drilling operation control method.
DETAILED DESCRIPTION
[0009] Representatively illustrated in FIG. 1 is a well drilling
system 10 and associated method which can embody principles of this
disclosure. However, it should be clearly understood that the
system 10 and method are merely one example of an application of
the principles of this disclosure in practice, and a wide variety
of other examples are possible. Therefore, the scope of this
disclosure is not limited at all to the details of the system 10
and method described herein and/or depicted in the drawings.
[0010] In the FIG. 1 example, 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).
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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. Hydraulics models 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.
[0018] 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.
[0019] 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.
[0020] 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 can be useful to the
hydraulics models in determining what the pressure applied to the
annulus 20 should be during the drilling operation.
[0021] 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.
[0022] In addition, the drill string 16 may include its own sensors
60, for example, to directly measure downhole pressure. Such
sensors 60 may be of the type known to those skilled in the art as
pressure while drilling (PWD), measurement while drilling (MWD)
and/or logging while drilling (LWD). These drill string sensor
systems generally provide at least pressure measurement, and may
also provide temperature measurement, detection of drill string
characteristics (such as vibration, weight on bit, stick-slip,
etc.), formation characteristics (such as resistivity, density,
etc.) and/or other measurements. Various forms of wired or wireless
telemetry (acoustic, pressure pulse, electromagnetic, etc.) may be
used to transmit the downhole sensor measurements to the
surface.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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 18
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.
[0027] 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.
[0028] 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.
[0029] 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).
[0030] 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.
[0031] 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.
[0032] 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.
[0033] Flow of the fluid 18 through the standpipe line 26 is
substantially controlled by a valve or other type of flow control
device 76. 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.
[0034] 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.
[0035] 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.).
[0036] 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.
[0037] 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.
[0038] 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).
[0039] 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.
[0040] Another example is representatively illustrated in FIG. 2.
In this example, 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), etc.
[0041] 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.
[0042] A specially adapted fully automated flow control device 76
(e.g., controlled automatically by the controller 96 depicted in
FIG. 3) 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.
[0043] In the FIG. 2 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
downstream of the choke manifold 32, 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).
[0044] A suitable telemetry controller and a suitable remotely
operable flow control device are provided in the GEO-SPAN(.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.
[0045] Note that each of the flow control devices 74, 76, 78 and
chokes 34 are preferably remotely and automatically controllable to
maintain a desired downhole pressure by maintaining a desired
annulus pressure at or near the surface. However, any one or more
of these flow control devices 74, 76, 78 and chokes 34 could be
manually controlled, in keeping with the scope of this
disclosure.
[0046] 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.
[0047] The control system 90 includes multiple hydraulics models
92, a data acquisition and control interface 94 and a controller 96
(such as a programmable logic controller or PLC, a suitably
programmed computer, etc.). Although these elements 92, 94, 96 are
depicted separately in FIG. 3, any or all of them could be combined
into a single element, or the functions of the elements could be
separated into additional elements, other additional elements
and/or functions could be provided, etc.
[0048] Three hydraulics models 92 are illustrated in FIG. 3, but
any number of hydraulics models may be used. Furthermore, the
hydraulics models 92 may be concurrently-running instances of a
hydraulics model, instead of separate hydraulics models. As used
herein, multiple hydraulics models can refer to both multiple
separate hydraulics models and multiple instances of a hydraulics
model.
[0049] The hydraulics models 92 are used in the control system 90
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 models 92 in making this determination, as well as
real-time sensor data acquired by the data acquisition and control
interface 94.
[0050] Thus, there is a continual two-way transfer of data and
information between the hydraulics models 92 and the data
acquisition and control interface 94. 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 models 92, so that the hydraulics models have the
information they need to adapt to changing circumstances and to
update the desired annulus pressure, and the hydraulics models
operate to supply the data acquisition and control interface
substantially continuously with values for the desired annulus
pressure.
[0051] A suitable hydraulics model for use as the hydraulics models
92 in the control system 90 is REAL TIME HYDRAULICS (.TM.) or GB
SETPOINT (.TM.) marketed by Halliburton Energy Services, Inc. of
Houston, Tex. 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 models may be
used in the control system 90 in keeping with the principles of
this disclosure.
[0052] 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.) marketed 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.
[0053] The controller 96 operates to maintain a desired setpoint
annulus pressure by controlling operation of the mud return choke
34 and other devices. When an updated desired annulus pressure is
transmitted from the data acquisition and control interface 94 to
the controller 96, the controller uses the desired annulus pressure
as a setpoint and controls operation of the choke 34 in a manner
(e.g., increasing or decreasing flow resistance through the choke
as needed) to maintain the setpoint pressure in the annulus 20. The
choke 34 can be closed more to increase flow resistance, or opened
more to decrease flow resistance.
[0054] 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.
[0055] 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.
[0056] Data validation and prediction techniques may be used in the
system 90 to guard against erroneous data being used, to ensure
that determined values are in line with predicted values, etc.
Suitable data validation and prediction techniques are described in
International Application No. PCT/US11/59743, although other
techniques may be used, if desired.
[0057] The hydraulics models 92 are used to generate the desired
annulus pressure setpoint, based on different considerations. The
hydraulics models 92 can have different sets of data input to them
from the data acquisition and control interface 94. The setpoint
output by one hydraulics model 92 can be different from the
setpoint output by another hydraulics model.
[0058] For example, one hydraulics model 92 could model typical
drilling ahead in a managed pressure drilling operation. Another
hydraulics model 92 could model a drill string 16 connection
process, or tripping the drill string into or out of the wellbore
12. Another hydraulics model 92 could model an influx being
received into the wellbore 12. Another hydraulics model 92 could
model a loss of fluid from the wellbore 12. Another hydraulics
model 92 could model multiphase flow in the well. Another
hydraulics model 92 could model high or low pressure, or high or
low flow, conditions. Another hydraulics model 92 could model an
optimized rate of penetration for a drilling operation. Another
hydraulics model 92 could model an optimized drill bit 14 life for
a drilling operation. Any type, number and combination of
hydraulics models 92 may be used, as desired.
[0059] When one of these circumstances occurs (e.g., an influx,
fluid loss, drill string connection, etc.), a selector 98 can be
operated to select which of the annulus pressure setpoints
generated by the multiple hydraulics models 92 is output to the
controller 96 for controlling operation of the choke 34, bypass
choke 74, standpipe valve 76, and/or standpipe flow control 78,
etc. The selector 98 is depicted separately in FIG. 3 for clarity,
but in actual practice the selector may be part of the data
acquisition and control interface 94, or another portion of the
system 90.
[0060] The selection of which annulus pressure setpoint is used by
the controller 96 can be made manually or automatically, and in
response to certain considerations. For example, if a particular
objective (e.g., optimum rate of penetration, optimum drill bit
life, etc.) is desired, then the corresponding hydraulics model 92
setpoint output may be selected manually. In this manner, the
selected hydraulics model 92 setpoint output will be used by the
controller 96 to control the drilling system 10 in a manner that
accomplishes the particular objective.
[0061] The selection can be made automatically in other
circumstances. For example, if an event detection system detects
that an event (such as an influx or fluid loss, etc.) has occurred,
or is about to occur, then the corresponding hydraulics model 92
which models such an event can be selected automatically. In this
manner, the selected hydraulics model 92 setpoint output will be
used by the controller 96 to control the drilling system 10 in a
manner that appropriately "handles" the event.
[0062] The automatic switching from one hydraulics model 92 to
another could be performed only after authorization from an
operator, if desired. Suitable event detection systems are
described in International Application Nos. PCT/US09/52227 and
PCT/US11/42917. Of course, other event detection systems may be
used, if desired.
[0063] Manual switching from one hydraulics model 92 to another
could be done if it appears that one model is more accurately
predicting well conditions than another model. For example, one
hydraulics model 92 may be predicting wellbore pressure downhole
which does not closely match actual measurements made by the
downhole sensors 60. In that case, it may be beneficial to switch
to another hydraulics model 92 which is more accurately predicting
the wellbore pressure downhole.
[0064] Referring additionally now to FIG. 4, a method 100 which can
embody principles of this disclosure is representatively
illustrated in flowchart form. The method 100 may be used with the
system 10 described above, or it may be used with other drilling
systems.
[0065] In the FIG. 4 example, multiple hydraulics models 92 are
running concurrently in step 102. The hydraulics models 92 are
preferably running concurrently in real time (that is, while the
drilling operation is being performed).
[0066] As discussed above, the multiple hydraulics models 92 may
not be separate hydraulics models, but could be multiple instances
of a hydraulics model. It is not necessary that the hydraulics
models 92 run simultaneously, but preferably the hydraulics models
are running concurrently during the drilling operation.
[0067] In step 104, the annulus pressure setpoint output by a first
hydraulics model 92 is used by the controller 96 for controlling
wellbore pressure during the drilling operation. The setpoint
output by the first hydraulics model 92 (and any other hydraulics
models) may be subject to the data validation and prediction
techniques discussed above. The selection of the first hydraulics
model 92 setpoint for controlling the drilling operation could be
based on any considerations (e.g., an informed choice, a desired
objective, a particular circumstance, a detected event, etc.).
[0068] In step 106, the selector 98 is used to select an annulus
pressure setpoint output by another hydraulics model 92 for
controlling the drilling operation. This switch from the first
hydraulics model 92 to a second hydraulics model could be performed
manually, completely automatically, or automatically upon human
authorization, etc.
[0069] In step 108, the annulus pressure setpoint output by the
second hydraulics model 92 is used by the controller 96 for
controlling wellbore pressure during the drilling operation. The
selection of the second hydraulics model 92 setpoint for
controlling the drilling operation could be based on any
considerations (e.g., an informed choice, a change in desired
objective, a particular circumstance, a detected event, etc.).
[0070] Thus, in the method 100, a switch is made from the annulus
pressure setpoint output by the first hydraulics model 92, to the
annulus pressure setpoint output by the second hydraulics model,
for input to the controller 96 to control the drilling operation.
The switch between the hydraulics models 92 outputs is performed in
real time, during the drilling operation.
[0071] Representatively illustrated in FIG. 5 is another example of
the method 100, in which an additional step 105 is interposed
between steps 104 and 106. In step 105, a comparison is made
between drilling parameter values predicted by the hydraulics
models 92 and actual drilling parameter values measured during the
drilling operation.
[0072] A particular hydraulics model 92 may, for whatever reason,
do a better job of predicting actual drilling parameters (such as
downhole pressures, etc.) than others of the hydraulics models. In
that case, wellbore pressure may be more accurately controlled
using that particular hydraulics model 92.
[0073] Thus, the switch between the hydraulics models 92 outputs in
step 106 is based on the comparison of predicted to actual drilling
parameter values performed in step 105. The switch may be
accomplished manually, completely automatically, or automatically
upon human authorization, etc.
[0074] Representatively illustrated in FIG. 6 is another example of
the method 100, in which the step 105 interposed between steps 104
and 106 comprises an event detection. In response to detection of
the event, the selector 98 switches to the output of the hydraulics
model 92 which models that particular event. Thus, the controller
96 controls the drilling operation based on the annulus pressure
setpoint output by the hydraulics model 92 which models a detected
event.
[0075] As described in the International Application Nos.
PCT/US09/52227 and PCT/US11/42917 mentioned above, an event can be
a precursor to another event, or can indicate a likelihood that an
event is about to occur. In that case, the switching to a
corresponding hydraulics model 92 output can prevent the upcoming
event from occurring, or at least mitigate its effects on the
drilling operation.
[0076] When an event is detected, an operator may be presented with
an indication or warning of the event, at which point the operator
can determine whether to switch to a hydraulics model 92 which
models that event (or a predicted event). Alternatively, the switch
can be performed automatically, or automatically upon human
authorization.
[0077] Note that it is not necessary for the multiple hydraulics
models 92 to run simultaneously or concurrently. For example, the
hydraulics models 92 could be run sequentially (e.g.,
daisy-chained) to provide the pressure setpoints periodically.
[0078] It is also not necessary for the device controlled by the
controller 96 to be a flow control device. For example, a
backpressure pump or suction pump, or another type of device, could
be controlled to maintain the setpoint.
[0079] It can now be fully appreciated that the above disclosure
provides significant advancements to the art of controlling
drilling operations. By concurrently running multiple hydraulics
models 92, an operator or automated system can select which of the
multiple hydraulics models is appropriate for a given objective,
situation, event, etc., occurring during the drilling operation.
This enhances the ability of the pressure and flow control system
90 to adapt to changing circumstances.
[0080] A control system 90 for drilling a subterranean well is
described above. In one example, the control system 90 can include
multiple hydraulics models 92, each of the hydraulics models 92
outputting a pressure setpoint, in real time during a drilling
operation.
[0081] The system 90 can also include a controller 96 and a
selector 98. The controller 96 may control operation of at least
one device 34, 74, 76, 78, and the selector 98 may select which of
the multiple pressure setpoints is input to the controller 96.
[0082] The device can comprise a choke 34 which variably restricts
flow from a wellbore 12, the device 76 may control flow through a
standpipe 26, or the device 74 may control flow between a standpipe
26 and a mud return line 30. The types of devices, and other types
of flow control devices, may be used.
[0083] The multiple hydraulics models 92 may comprise multiple
instances of a same hydraulics model.
[0084] Also described above is a method 100 of controlling a
drilling operation. In one example, the method 100 may comprise
running multiple hydraulics models 92 during the drilling
operation; and switching between outputs of the multiple hydraulics
models 92 to control the drilling operation, the switching being
performed during the drilling operation. The hydraulics models may
run concurrently.
[0085] The method can include controlling operation of at least one
device 34, 74, 76, 78, thereby maintaining a pressure at a pressure
setpoint output by one of the multiple hydraulics models 92. The
device may comprise a flow control device.
[0086] The switching step can include switching from a first
hydraulics model 92 output to a second hydraulics model 92 output.
The switching may be performed in response to a change in an
objective of the drilling operation, in response to detection of an
event, and/or in response to a comparison between a measured
drilling parameter value and the drilling parameter value as
predicted by the hydraulics models 92.
[0087] The switching can be performed manually or
automatically.
[0088] Another method 100 of controlling a drilling operation
described above can include controlling operation of at least one
device 34, 74, 76, 78, thereby maintaining a pressure at a pressure
setpoint; and selecting the pressure setpoint from among outputs of
multiple hydraulics models 92.
[0089] Although various examples have been described above, with
each example having certain features, it should be understood that
it is not necessary for a particular feature of one example to be
used exclusively with that example. Instead, any of the features
described above and/or depicted in the drawings can be combined
with any of the examples, in addition to or in substitution for any
of the other features of those examples. One example's features are
not mutually exclusive to another example's features. Instead, the
scope of this disclosure encompasses any combination of any of the
features.
[0090] Although each example described above includes a certain
combination of features, it should be understood that it is not
necessary for all features of an example to be used. Instead, any
of the features described above can be used, without any other
particular feature or features also being used.
[0091] It should be understood that the various embodiments
described herein may be utilized in various orientations, such as
inclined, inverted, horizontal, vertical, etc., and in various
configurations, without departing from the principles of this
disclosure. The embodiments are described merely as examples of
useful applications of the principles of the disclosure, which is
not limited to any specific details of these embodiments.
[0092] 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.
[0093] The terms "including," "includes," "comprising,"
"comprises," and similar terms are used in a non-limiting sense in
this specification. For example, if a system, method, apparatus,
device, etc., is described as "including" a certain feature or
element, the system, method, apparatus, device, etc., can include
that feature or element, and can also include other features or
elements. Similarly, the term "comprises" is considered to mean
"comprises, but is not limited to."
[0094] 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. For example,
structures disclosed as being separately formed can, in other
examples, be integrally formed and vice versa. 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.
* * * * *