U.S. patent application number 14/387174 was filed with the patent office on 2015-06-04 for pressure and flow control in continuous flow drilling operations.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Jon T. Gosney, James R. Lovorn.
Application Number | 20150152700 14/387174 |
Document ID | / |
Family ID | 53179940 |
Filed Date | 2015-06-04 |
United States Patent
Application |
20150152700 |
Kind Code |
A1 |
Lovorn; James R. ; et
al. |
June 4, 2015 |
PRESSURE AND FLOW CONTROL IN CONTINUOUS FLOW DRILLING
OPERATIONS
Abstract
A method of providing substantially continuous circulation of
fluid through a drill string and an annulus can include sealing off
the annulus from atmosphere, regulating flow of the fluid from the
annulus, thereby controlling pressure in the wellbore, and
diverting flow of the fluid from a pump to an uppermost connector
of the drill string and an inlet extending in a sidewall of the
drill string, the regulating and the diverting being performed
concurrently. A pressure and flow control system can include one or
more flow control devices which divert flow from a pump to a valve
which selectively permits and prevents communication between an
uppermost connector of the drill string and a flow passage
extending longitudinally through the drill string, and to a valve
which selectively permits and prevents communication between the
flow passage and an inlet extending in a sidewall of the drill
string.
Inventors: |
Lovorn; James R.; (Tomball,
TX) ; Gosney; Jon T.; (Bellville, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
53179940 |
Appl. No.: |
14/387174 |
Filed: |
November 21, 2013 |
PCT Filed: |
November 21, 2013 |
PCT NO: |
PCT/US13/71221 |
371 Date: |
September 22, 2014 |
Current U.S.
Class: |
175/57 ;
175/217 |
Current CPC
Class: |
E21B 47/06 20130101;
E21B 21/08 20130101; E21B 21/106 20130101; E21B 21/01 20130101 |
International
Class: |
E21B 21/01 20060101
E21B021/01; E21B 21/08 20060101 E21B021/08; E21B 21/10 20060101
E21B021/10 |
Claims
1. A method of providing substantially continuous circulation of
fluid through a drill string and an annulus between the drill
string and a wellbore, the method comprising: operating a
hydraulics model; and in response to an output from the hydraulics
model, diverting flow of the fluid from a pump to: a) an uppermost
connector of the drill string, and b) an inlet extending in a
sidewall of the drill string, wherein each of the uppermost
connector and the inlet is communicable with a flow passage
extending longitudinally through the drill string.
2. The method of claim 1, wherein the diverting further comprises
gradually decreasing the flow of the fluid from the pump to the
uppermost connector while gradually increasing the flow of the
fluid from the pump to the inlet.
3. The method of claim 1, wherein the diverting further comprises
gradually increasing the flow of the fluid from the pump to the
uppermost connector while gradually decreasing the flow of the
fluid from the pump to the inlet.
4. The method of claim 1, wherein the pressure in the wellbore is
maintained substantially constant throughout the diverting.
5. The method of claim 1, wherein the diverting further comprises
automatically operating at least one flow control device which
controls flow to the uppermost connector, and which controls flow
to the inlet.
6. The method of claim 1, wherein a substantially constant flow of
the fluid through the drill string and the annulus is maintained
throughout the diverting.
7. The method of claim 1, wherein the diverting further comprises
diverting the flow of the fluid from the pump to an outlet line via
which the fluid flows from the annulus.
8. A pressure and flow control system for providing substantially
continuous circulation of fluid from a pump through a drill string
and an annulus between the drill string and a wellbore, the system
comprising: at least one flow control device which diverts flow
from the pump to: a) a first valve which selectively permits and
prevents communication between an uppermost connector of the drill
string and a flow passage extending longitudinally through the
drill string, and b) a second valve which selectively permits and
prevents communication between the flow passage and an inlet
extending in a sidewall of the drill string; and an annular seal
device which seals off the annulus while the at least one flow
control device diverts flow between the first and second
valves.
9. The system of claim 8, wherein the at least one flow control
device comprises first and second chokes, wherein the first choke
variably regulates flow from the pump to the first valve, and
wherein the second choke variably regulates flow from the pump to
the second valve.
10. The system of claim 9, wherein the first and second chokes are
operated in response to sensor inputs to a hydraulics model.
11. The system of claim 9, wherein the first and second chokes are
operated simultaneously, whereby flow is gradually diverted between
the first and second valves.
12. The system of claim 8, wherein the first and second valves are
operated in response to sensor inputs to a hydraulics model.
13. The system of claim 8, wherein the at least one flow control
device is automatically operated and maintains a substantially
constant flow of the fluid through the drill string and the annulus
while flow is diverted between the first and second valves.
14. The system of claim 8, wherein the at least one flow control
device further diverts the flow of the fluid from the pump to an
outlet line via which the fluid flows from the annular seal
device.
15. A method of providing substantially continuous circulation of
fluid through a drill string and an annulus between the drill
string and a wellbore, the method comprising: inputting sensor
measurements to a hydraulics model; and in response to an output of
the hydraulics model, automatically operating at least one flow
control device, thereby diverting flow of the fluid from a pump to:
a) a first valve which selectively permits and prevents
communication between an uppermost connector of the drill string
and a flow passage extending longitudinally through the drill
string, and b) a second valve which selectively permits and
prevents communication between the flow passage and an inlet
extending in a sidewall of the drill string.
16. The method of claim 15, wherein the diverting further comprises
gradually decreasing the flow of the fluid from the pump to the
first valve while gradually increasing the flow of the fluid from
the pump to the second valve.
17. The method of claim 15, wherein the diverting further comprises
gradually increasing the flow of the fluid from the pump to the
first valve while gradually decreasing the flow of the fluid from
the pump to the second valve.
18. The method of claim 15, wherein the pressure in the wellbore is
maintained substantially constant throughout the diverting.
19. The method of claim 15, wherein a substantially constant flow
of the fluid through the drill string and the annulus is maintained
throughout the diverting.
20. The method of claim 15, wherein the diverting further comprises
diverting the flow of the fluid from the pump to an outlet line via
which the fluid flows from the annulus.
Description
TECHNICAL FIELD
[0001] This disclosure relates generally to equipment utilized and
operations performed in conjunction with a subterranean well and,
in an example described below, more particularly provides for
pressure and flow control in continuous flow drilling
operations.
BACKGROUND
[0002] It can be beneficial to continuously circulate fluid through
a drill string, in part because ceasing and then restarting flow
(such as, to allow a section to be added to or removed from the
drill string) can cause detrimental pressure fluctuations in a
wellbore being drilled. Therefore, it will be appreciated that
improvements are continually needed in the arts of constructing and
operating well systems which provide for continuous flow during
drilling operations.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] FIG. 1 is a representative partially cross-sectional view of
a system and a method for providing substantially continuous
circulation through a drill string and an annulus formed between
the drill string and a wellbore, which system and method can embody
principles of this disclosure.
[0004] FIGS. 2-12 are representative schematic views of various
steps of an example of the method.
[0005] FIG. 13 is a representative block diagram of a hydraulic
control system that may be used with the system and method.
[0006] FIGS. 14 & 15 are representative schematic views of
steps of another example of the method.
DETAILED DESCRIPTION
[0007] FIG. 1 is a representative partially cross-sectional view of
a system 10 and a method for providing substantially continuous
circulation through a drill string 12 and an annulus 14 formed
between the drill string and a wellbore 16, which system and method
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.
[0008] A land-based well is illustrated in FIG. 1, but it should be
clearly understood that the principles of this disclosure can be
readily applied to subsea or other water-based wells, for example,
using floating, fixed or jack-up rigs. Thus, the scope of this
disclosure is not limited to any particular details of the well
depicted in the drawings or described herein.
[0009] In the FIG. 1 example, a section 12a of the drill string 12
protrudes upwardly from an annular seal device 18 connected above a
blowout preventer stack 20. The blowout preventer stack 20 depicted
in FIG. 1 includes an annular preventer 20a, a variable ram 20b, a
blind ram 20c, a flow spool 20d and a pipe ram 20e connected above
a wellhead 22. In other examples, other or different equipment
could be used in or substituted for the annular seal device 18, the
blowout preventer stack 20 and/or the wellhead 22.
[0010] The drill string 12 is used to drill the wellbore 16. For
this purpose, a drill bit 24 is connected at a distal end of the
drill string 12. The drill bit 24 could, for example, be a rotary
cone, fixed cutter, impact or other type of drill bit.
[0011] In some examples, the drill bit 24 may be rotated by
rotating the drill string 12 at or near the earth's surface, such
as, by use of a rotary table (not shown) or a top drive (not
shown). In some examples, the drill bit 24 may be rotated by use of
a drilling motor 26 connected in the drill string 12. In other
examples, the drill bit 24 may not be rotated.
[0012] Thus, the scope of this disclosure is not limited to any
particular technique for causing the drill bit 24 to drill the
wellbore 16. Indeed, it is not necessary for the drill bit 24 to be
used at all. For example, a jet drill (which drills by means of a
fluid jet) could be used instead of, or in addition to, the drill
bit 24.
[0013] While the wellbore 16 is being drilled, a fluid 28 is pumped
through the drill string 12 into the wellbore 16. The fluid 28
exits the drill bit 24 and flows back to the surface via the
annulus 14. A non-return valve (unnumbered in FIG. 1) can be used
in the drill string to prevent reverse flow of the fluid 28 through
the drill string 12.
[0014] The fluid 28 can serve many purposes, such as, to cool and
lubricate the drill bit 24, to stabilize the wellbore 16, to
transport cuttings to the surface, to maintain a desired pressure
in the wellbore, etc. The fluid 28 can be combined with a variety
of additives, for example, to increase or decrease the fluid's
density, to provide a protective layer or "cake" lining in the
wellbore 16, etc. The fluid 28 can be known to those skilled in the
art as drilling "mud" although it could in some examples be merely
brine water. Nitrogen or another gas, or another lighter weight
fluid, may be added to the fluid 28 for pressure control. This
technique is useful, for example, in underbalanced drilling
operations. Thus, the scope of this disclosure is not limited to
use of any particular fluid in the system 10.
[0015] The annular seal device 18 seals off the annulus 14 at or
near the surface using, for example, an annular seal (not shown)
that encircles the drill string 12. The annular seal may or may not
rotate with the drill string 12 when or if the drill string
rotates.
[0016] The device 18 may be of the type known to those skilled in
the art as a rotating control device, rotating control head, rotary
diverter, rotating blowout preventer, etc. In that case, the device
18 may include bearings (not shown) which allow the annular seal to
rotate with the drill string 12 while sealing off the annulus 14
from atmosphere at or near the surface. However, it should be
clearly understood that the scope of this disclosure is not limited
to use of any particular type of annular seal device in the system
10.
[0017] The fluid 28 exits the annulus 14 via an outlet line 44
connected to the device 18 (for example, below the annular seal).
Since the annulus 14 is sealed off at or near the surface with the
device 18, a choke manifold 46 (not shown in FIG. 1, see FIGS.
2-12) can be used to variably restrict the flow of the fluid 28
from the annulus and thereby control pressure in the wellbore
16.
[0018] For example, by increasingly restricting the flow of the
fluid 28 from the annulus 14, an increased backpressure can be
applied to the annulus and, hence, to the wellbore 16. If, however,
restriction to flow of the fluid 28 from the annulus 14 is
decreased, the backpressure is also decreased, thereby decreasing
pressure in the wellbore 16.
[0019] Control of wellbore pressure is very important in managed
pressure drilling, and in other types of drilling operations.
Preferably, the wellbore pressure is accurately controlled to
prevent excessive loss of fluid into an earth formation surrounding
the wellbore 16, undesired fracturing of the formation, undesired
influx of formation fluids into the wellbore, etc. In typical
managed pressure drilling, it is desired to maintain the wellbore
pressure just 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 wellbore
pressure somewhat less than the pore pressure, thereby obtaining a
controlled influx of fluid from the formation.
[0020] Operation of the choke manifold 46 (see FIGS. 2-12) can be
automated, so that a desired pressure is maintained in the wellbore
16 at all, or substantially all, times. Suitable automated wellbore
pressure control systems are described in U.S. Publication No.
2013/0133948, and in International Application No. PCT/US12/39586,
filed on 25 May 2012. Such automated wellbore pressure control
systems can be used to automatically control operation of the choke
manifold 46, as well as other pressure and flow equipment (such as,
a standpipe manifold 48, not shown in FIG. 1, see FIGS. 2-12),
including but not limited to flow control devices (such as, valves
and chokes) and pumps, etc. However, the scope of this disclosure
is not limited to use of any particular automated wellbore pressure
control system.
[0021] While the wellbore 16 is being drilled, the fluid 28 can be
supplied to an uppermost connector 30 of the drill string 12 via a
kelly (not shown) and a standpipe line 32 (see FIGS. 2-12).
However, when it is desired to add another section 12b to, or to
remove the section 12a from, the drill string 12, the connector 30
is disconnected from the kelly and standpipe line 32, and so these
are not available for supplying the fluid 28 to the drill
string.
[0022] In the FIG. 1 example, in order to provide an alternate
means for supplying the fluid 28 to the drill string 12, each
section of the drill string is equipped with a continuous
circulation device 34. The device 34 includes flow control devices
36, 38 (such as valves or closable chokes) for providing fluid
communication between a longitudinal flow passage 40 of the drill
string 12, and the connector 30 and/or an inlet 42.
[0023] The inlet 42 provides for sealed fluid communication through
a sidewall of the device 34 to the flow passage 40. The connector
30 provides for sealed fluid communication through the flow passage
40 between sections 12a,b of the drill string 12.
[0024] The flow control device 36 selectively permits and prevents
fluid communication between the connector 30 and the flow passage
40. The flow control device 38 selectively permits and prevents
fluid communication between the inlet 42 and the flow passage
40.
[0025] Although separate flow control devices 36, 38 are depicted
in FIG. 1, any number of flow control devices could be used in
other examples. For example, a single three-way valve could be used
in place of the separate flow control devices 36, 38 if
desired.
[0026] Suitable continuous circulation devices are described in
U.S. Pat. No. 7,845,433, and in International Application No.
PCT/US13/62730, filed on 30 Sep. 2013. Such continuous circulation
devices may be automated (for example, so that operation of the
flow control devices 36, 38 is automatically controlled), or
manually operated. However, the scope of this disclosure is not
limited to use of any particular type of continuous circulation
device.
[0027] In the International Application No. PCT/US13/62730
mentioned above, the continuous circulation device includes
connection sensors that can detect when connections are properly
made (for example, at the uppermost connection 30 and at the inlet
42), so that the valves 36, 38 can be operated in response. The
valves 36, 38 can also be operated synchronously. In the system 10
described herein, the valves 36, 38 can be operated automatically
based, at least in part, on an output of a hydraulics model 122
(see FIG. 13).
[0028] The sections 12a,b of the drill string 12 depicted in FIG. 1
may be stands of drill pipe, drill collars or other equipment (such
as, the drilling motor 26, pressure-, measurement- or
logging-while-drilling (PWD, MWD or LWD) sensors 50, centralizers,
stabilizers, reamers, etc.). The continuous circulation device 34
may be separate from, or integrated as part of, each section added
to or removed from the drill string 12 in the drilling operation.
For example, each of the sections 12a,b of the drill string 12
illustrated in FIG. 1 can include the continuous circulation device
34.
[0029] As depicted in FIG. 1, the section 12b is being added to or
removed from the drill string 12. Thus, the flow control device 36
is closed and the flow control device 38 is open, thereby enabling
flow of the fluid 28 via the inlet 42 into the flow passage 40 and
preventing upward flow out of the flow passage via the connector
30.
[0030] In this example, pressure in the wellbore 16 is maintained
relatively constant (e.g., with only minor fluctuations occurring)
at a desired pressure while the section 12b is added to or removed
from the drill string 12. Since continuous circulation of the fluid
28 is provided in the system 10, the choke manifold 46 (see FIGS.
2-14) can be operated to maintain a desired pressure in the
wellbore 16 while the section 12b is added to or removed from the
drill string 12.
[0031] So that the choke manifold 46 does not have to compensate
for large variations in flow while the flow control devices 36, 38
are operated, the flow of the fluid 28 through the flow passage 40
(and, hence, through the drill string 12 and annulus 14) can be
maintained substantially constant (e.g., with only minor
fluctuations occurring) while those flow control devices are
operated. For example, instead of opening one of the flow control
devices 36, 38 and then closing the other one, the flow control
devices can be gradually opened and closed, so that a total amount
of flow through the flow control devices remains substantially
constant. Suitable flow sensors (such as, the sensors 50 and
flowmeters 52, 54, not shown in FIG. 1, see FIGS. 2-12) and the
automated wellbore pressure control systems mentioned above can be
used to automatically operate the flow control devices 36, 38, so
that the flow of the fluid 28 through the drill string 12 and
annulus 14 remains substantially constant while the flow control
devices are operated.
[0032] FIGS. 2-12 are representative schematic views of various
steps of one example of the method. In the FIGS. 2-12 example, a
section is added to the drill string 12. However, it will be
readily appreciated by those skilled in the art that similar steps
can be used in removing a section from the drill string 12.
[0033] Not all of the steps depicted in FIGS. 2-12 are necessary
for performance of the method. For example, FIGS. 14 & 15
depict alternative steps that can be used with the method in
certain circumstances. Thus, it should be clearly understood that
the scope of this disclosure is not limited to any particular
number, sequence, function or type of steps in the method of
providing continuous circulation of the fluid 28 through the drill
string 12 and the annulus 14.
[0034] The method steps depicted in FIGS. 2-12 are performed with
the system 10 of FIG. 1 (including additional equipment described
more fully below). However, the method can be performed with other
systems, in keeping with the principles of this disclosure.
[0035] Turning now specifically to FIG. 2, the system 10 is
representatively illustrated while the wellbore 16 (see FIG. 1) is
being drilled with the drill string 12, a situation known to those
skilled in the art as "drilling ahead" or "making hole." In this
relatively steady state situation, the fluid 28 is pumped through
the drill string 12, into the annulus 14 (see FIG. 1), and returns
to the surface.
[0036] In the further description below, the flow of the fluid 28
through the system 10 will be described, beginning at a reservoir
56 (or "mud pit") and returning to the reservoir. However, it
should be clearly understood that a variety of different
alternatives exist for flow of the fluid 28, and so the scope of
this disclosure is not limited to any particular flow path
traversed by the fluid.
[0037] Beginning at the reservoir 56, the fluid 28 is pumped by a
pump 58 (such as, a rig mud pump) to the standpipe manifold 48. The
fluid 28 passes through a debris strainer 60 and a valve 62 in the
standpipe manifold 48. The fluid 28 then flows to the standpipe
line 32.
[0038] In this example, a kelly (not shown, but kelly valves 64a,b
are depicted in FIG. 2) can be connected between the standpipe line
32 and the section 12a of drill string 12. The kelly provides a
rotary fluid connection, so that the drill string 12 can rotate
relative to the standpipe line 32 while maintaining fluid
communication between them. However, in other examples, such a
rotary fluid connection could be provided as part of a top drive,
or a rotary fluid connection may not be used.
[0039] The fluid 28 flows from the standpipe line 32 into the flow
passage 40 of the drill string 12 via the flow control device 36,
which is open at this time. The other flow control device 38 of the
continuous circulation device 34 is closed at this time.
[0040] The fluid 28 flows through the passage 40 to the drill bit
24 (see FIG. 1). The fluid 28 then exits the drill bit 24 (such as,
via nozzles of the drill bit, not shown) and returns via the
annulus 14 (see FIG. 1). The fluid 28 is shown in dashed lines
flowing downwardly and upwardly through the blowout preventer stack
20 in FIG. 2, thereby indicating the flow of the fluid into the
wellbore 16 (see FIG. 1) via the passage 40, and return of the
fluid from the wellbore via the annulus 14.
[0041] At or near the surface, the fluid 28 exits the annular seal
device 18 and flows into the outlet line 44. The fluid 28 then
flows through the choke manifold 46, which variably restricts the
fluid flow to thereby maintain a desired pressure in the wellbore
16. In the FIG. 2 example, the fluid 28 flows through only one of
multiple redundant chokes 66 of the manifold 46. One or more of the
chokes 66 can be automatically operated using the wellbore pressure
control systems mentioned above, in order to automatically maintain
the desired wellbore pressure.
[0042] The fluid 28 then flows through a flowmeter 68. The
flowmeter 68 can be capable of relatively precise flow rate
measurements (for example, the flowmeter may be a Coriolis
flowmeter), which can assist in the automated operation of the
choke manifold 46 and the flow control devices 36, 38, 62, 74, 82,
86 (see FIGS. 3-15).
[0043] In addition, by comparing the flows into the wellbore 16
(measured, for example, by flowmeters 52, 54 and/or sensors 50) to
the flow out of the wellbore (measured, for example, by the
flowmeter 68), diagnostic techniques can detect certain
circumstances (such as, influx of formation fluid into the
wellbore, loss of fluid 28 from the wellbore, etc.), and certain
formation properties (such as, fracture pressure, pore pressure,
etc.) can be measured. Suitable diagnostic and measurement
techniques are described in International Application No.
PCT/US12/59079, filed on 5 Oct. 2012, and in U.S. Publication No.
2013/0133948.
[0044] The fluid 28 then flows through a gas separator 70 and a
shaker 72 before returning to the reservoir 56. The separator 70
removes any gas that might be entrained in the fluid 28, and the
shaker 72 removes cuttings or other debris from the fluid. However,
other or additional fluid conditioning equipment may be used, in
keeping with the principles of this disclosure.
[0045] Note that the separator 70 could be a 3 or 4 phase
separator, or a mud gas separator (sometimes referred to as a "poor
boy degasser"). However, the separator 70 is not necessarily used
in the system 10.
[0046] Referring specifically now to FIG. 3, the system 10 is
representatively illustrated after a flow control device 74 (such
as, a choke) has been opened in the standpipe manifold 48. Note
that the fluid 28 flows both through the valve 62 and the flow
control device 74 at this time.
[0047] In addition, a bypass line 80 is now connected to the inlet
42 of the continuous circulation device 34. In steps described more
fully below, the flow of the fluid 28 is gradually diverted from
the standpipe line 32 to the bypass line 80, so that the fluid
flows into the passage 40 via the flow control device 38 instead of
via the flow control device 36.
[0048] Referring specifically now to FIG. 4, the system 10 is
representatively illustrated after the valve 62 has been closed.
The fluid 28 now flows through the flow control device 74, but not
the valve 62, thereby enabling the flow control device 74 to be
used to precisely vary the flow of the fluid 28 as needed.
[0049] Referring specifically now to FIG. 5, the system 10 is
representatively illustrated after a valve 76 has been opened in
preparation for regulating flow of the fluid 28 to the inlet 42 of
the continuous circulation device 34. However, at this time, the
fluid 28 does not yet flow to the inlet 42.
[0050] Another flow control device 78, which controls flow through
the bypass line 80, may be opened at this time. Alternatively, the
flow control device 78 could be opened in response to proper
connecting of the bypass line 80 to the inlet 42 (e.g., as
described in the International Application No. PCT/US13/62730
mentioned above).
[0051] Referring specifically now to FIG. 6, the system 10 is
representatively illustrated after another flow control device 82
(such as, a choke) has been opened, thereby allowing flow of the
fluid 28 from the standpipe manifold 48 to the inlet 42 of the
continuous circulation device 34. The flow control device 82 can
variably regulate this flow, so that a total flow of the fluid 28
into the drill string 12 remains substantially constant (although
it is not necessary for such flow to remain constant, since the
choke manifold 46 can be operated to compensate for flow
variations), and so that large pressure fluctuations are
avoided.
[0052] The flow control device 74 is depicted in the drawings as
being part of the standpipe manifold 48, whereas the flow control
device 82 is depicted as being separate from the standpipe
manifold. However, it is not necessary for any particular flow
control device to be a part of, or separate from, the standpipe
manifold 48.
[0053] The flow control device 38 can be gradually opened while the
flow control device 36 is gradually closed, so that fluid
communication between the passage 40 and the uppermost connector 30
(see FIG. 1) is gradually prevented and fluid communication between
the passage and the inlet 42 is gradually permitted. In addition,
the flow control devices 74, 82 can be automatically operated, so
that progressively more flow of the fluid 28 is diverted from the
standpipe line 32 to the bypass line 80.
[0054] Automation of this process can be in response to detection
of appropriate connection of the bypass line 80 to the inlet 42. A
suitable connection sensor is described in the International
Application No. PCT/US13/62730 mentioned above.
[0055] Referring specifically now to FIG. 7, the system 10 is
representatively illustrated after the flow control device 36 has
been fully closed. All of the flow of the fluid 28 from the
standpipe manifold 48 now goes to the inlet 42, and thence into the
flow passage 40. The flow control device 74 may also be fully
closed at this time. Flow into the inlet 42 can now be
automatically controlled using the flow control devices 78, 82.
[0056] Referring specifically now to FIG. 8, the system 10 is
representatively illustrated after a valve 84 in the standpipe
manifold 48 has been closed, thereby completely isolating the
standpipe line 32 from the flow of the fluid 28 from the pump 58.
The fluid 28 continues to flow to the bypass line 80 and into the
flow passage 40.
[0057] After the valve 84 has been closed, the standpipe line 32
can be bled off (e.g., via a flow control device 86). Once pressure
in the standpipe line 32 is reduced to atmospheric pressure, the
standpipe line (and the kelly, not shown) can be disconnected from
the drill string 12.
[0058] This leaves the uppermost connector 30 available for
connecting the next drill string section 12b (see FIGS. 1 & 9).
Note that FIG. 8 depicts the system 10 in a same condition as is
depicted in FIG. 1.
[0059] Referring specifically now to FIG. 9, the system 10 is
representatively illustrated after the section 12b has been
connected to the section 12a. The standpipe line 32 has also been
connected to the section 12b (for example, via an uppermost
connector 30 of the section 12b). However, the fluid 28 continues
to flow into the passage 40 exclusively via the bypass line 80,
inlet 42 and flow control device 38.
[0060] Referring specifically now to FIG. 10, the system 10 is
representatively illustrated after the valve 84 has been opened,
allowing the flow control device 74 to variably regulate flow of
the fluid 28 from the standpipe manifold 48 to the standpipe line
32 (which is now connected to the section 12b, not shown in FIG.
10).
[0061] The flow control device 36 can now be gradually opened to
admit fluid 28 from the standpipe line 32 to the flow passage 40.
The flow control device 38 can be gradually closed, so that the
fluid 28 eventually flows into the passage 40 exclusively via the
standpipe line 32 and the flow control device 36. In addition, the
flow control devices 74, 82 can be automatically operated, so that
progressively more flow of the fluid 28 is diverted from the bypass
line 80 to the standpipe line 32.
[0062] Automation of this process can be in response to detection
of appropriate connection of the drill string section 12b to the
connector 30 of the drill string section 12a. A suitable connection
senor is described in the International Application No.
PCT/US13/62730 mentioned above.
[0063] Referring specifically now to FIG. 11, the system 10 is
representatively illustrated after the flow control device 78 has
been closed, thereby preventing flow of the fluid 28 via the bypass
line 80 to the inlet 42. A bleed valve (not shown) can be
incorporated into the inlet 42, or in conjunction with the flow
control device 78, in order to bleed the bypass line 80 between the
inlet 42 and the flow control device 78.
[0064] Note that the flow of the fluid 28 into the drill string 12
at this point is exclusively via the standpipe line 32. The flow
control device 74 can be used to variably regulate this flow as
needed.
[0065] Referring specifically now to FIG. 12, the system 10 is
representatively illustrated after the bypass line 80 has been
disconnected from the inlet 42. In addition, the valve 62 has been
opened and the valve 84 has been closed, so that the flow control
device 74 is no longer used to variably regulate the flow of the
fluid 28 through the standpipe manifold 48.
[0066] The system 10 is now returned to its condition as depicted
in FIG. 2, except that the section 12b (not shown in FIG. 12, but
connected above the section 12a) is now part of the drill string
12. Drilling of the wellbore 16 (see FIG. 1) can now resume.
[0067] Note that, at any point in the method described above, the
flow of the fluid 28 from the annulus 14 (see FIG. 1) can be
diverted to a well control choke manifold 88 (for example, by
opening a valve 90 and closing a valve 92). Flow may be diverted to
the well control choke manifold 88 for well control operations (for
example, to circulate out an otherwise uncontrolled influx of gas
into the wellbore 16). Alternatively, or in addition, the choke
manifold 46 could be used for such well control operations.
[0068] The hydraulics model 122 (see FIG. 13) can be used, as
described more fully below, to determine a pressure applied to the
annulus 14 at or near the surface which will result in a desired
wellbore 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 wellbore pressure. The
hydraulics model 122 can also be used to control various flow
control devices (such as, flow control devices 74, 82, 86 and
valves 36, 38, 62, 76, 78, 84) to maintain continuous circulation
through the drill string 12.
[0069] Pressure applied to the annulus 14 can be measured at or
near the surface via a variety of pressure sensors 100, 102, 104,
each of which is in communication with the annulus. Pressure sensor
100 senses pressure below the annular seal device 18, but above the
blowout preventer stack 20. Pressure sensor 102 senses pressure in
the wellhead 22 below the blowout preventer stack 20. Pressure
sensor 104 senses pressure in the outlet line 44 upstream of the
choke manifold 46.
[0070] Another pressure sensor 106 senses pressure in the standpipe
line 32. Yet another pressure sensor 108 senses pressure downstream
of the choke manifold 46. Additional sensors include temperature
sensors 110, 112, Coriolis flowmeter 68, and flowmeters 52, 54,
114, 116, 118.
[0071] Not all of these sensors are necessary. For example, the
system 10 could include only two of the three flowmeters 52, 54,
114. However, input from the sensors is useful to the hydraulics
model 122 in determining what the pressure applied to the annulus
14 should be during the drilling operation, and how to operate the
various flow control devices in order to maintain a desired
wellbore pressure.
[0072] In addition, the drill string 12 includes its own sensors
50, for example, to directly measure wellbore pressure. Such
sensors 50 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.
[0073] Additional sensors could be included in the system 10, if
desired. For example, another flowmeter could be used to measure
the rate of flow of the fluid 28 exiting the wellhead 22, another
Coriolis flowmeter (not shown) could be interconnected directly
upstream or downstream of the rig mud pump 58, etc.
[0074] Fewer sensors could be included in the system 10, if
desired. For example, the output of the rig mud pump 58 could be
determined by counting pump strokes, instead of by using flowmeter
114 or any other flowmeters. Thus, the scope of this disclosure is
not limited to use of any particular number, type or arrangement of
sensors in the system 10.
[0075] FIG. 13 is a representative block diagram of a pressure and
flow control system 120 that may be used with the system 10 and
method. The control system 120 is preferably fully automated,
although some human intervention may be used, for example, to
safeguard against improper operation, initiate certain routines,
update parameters, etc.
[0076] The control system 120 includes the hydraulics model 122, a
data acquisition and control interface 124 and a controller 126
(such as a programmable logic controller or PLC, a suitably
programmed computer, etc.). Although these elements 122, 124, 126
are depicted separately in FIG. 13, 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.
[0077] The hydraulics model 122 is used in the control system 120
to determine the desired annulus pressure at or near the surface to
achieve the desired wellbore 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 122 in making this determination, as well as
real-time sensor data acquired by the data acquisition and control
interface 124.
[0078] Thus, there is a continual two-way transfer of data and
information between the hydraulics model 122 and the data
acquisition and control interface 124. For the purposes of this
disclosure, it is important to appreciate that the data acquisition
and control interface 124 operates to maintain a substantially
continuous flow of real-time data from the sensors 50, 52, 54, 100,
102, 104, 106, 108, 110, 112, 114, 116, 118 to the hydraulics model
122, 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.
[0079] A suitable hydraulics model for use as the hydraulics model
122 in the control system 120 is REAL TIME HYDRAULICS.TM. provided
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 model may be used in the control
system 120 in keeping with the principles of this disclosure.
[0080] A suitable data acquisition and control interface for use as
the data acquisition and control interface 124 in the control
system 120 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 120 in keeping with the
principles of this disclosure.
[0081] The controller 126 operates to maintain a desired setpoint
annulus pressure by controlling operation of the mud return choke
66 while drilling. When an updated desired annulus pressure is
transmitted from the data acquisition and control interface 124 to
the controller 126, the controller uses the desired annulus
pressure as a setpoint and controls operation of the choke 66 in a
manner (e.g., increasing or decreasing flow through the choke as
needed) to maintain the setpoint pressure in the annulus 14.
[0082] This is accomplished by comparing the setpoint pressure to a
measured annulus pressure (such as the pressure sensed by any of
the sensors 100, 102, 104), and increasing flow through the choke
66 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 66
is required. This process is preferably automated, so that no human
intervention is required, although human intervention may be used
if desired.
[0083] The controller 126 may also be used to control operation of
the various standpipe, bypass and continuous circulation flow
control devices and valves 36, 38, 62, 74, 76, 80, 82, 84, 86. The
controller 126 can, thus, be used to automate the processes of
appropriately opening and closing the continuous circulation flow
control devices 36, 38 (for example, when the bypass line 80 is
properly connected to the inlet 42, etc.), and of diverting flow of
the fluid 28 from the standpipe line 32 to the bypass line 80 prior
to making a connection in the drill string 12, then diverting flow
from the bypass line to the standpipe line after the connection is
made, and then resuming normal circulation of the fluid 28 for
drilling. Again, no human intervention may be required in these
automated processes, other than to initiate each process in
turn.
[0084] Referring additionally now to FIG. 14, a step in another
example of the method is representatively illustrated. In this
step, the fluid 28 is not continuously circulated through the drill
string 12, but is instead diverted from the bypass line 80 to the
outlet line 44.
[0085] Note that FIG. 14 is similar in most respects to FIG. 8,
except that a flow control device 94 is opened, thereby allowing
the fluid 28 to flow from the standpipe manifold 48 via the flow
control device 82 to the outlet line 44. The flow control device 78
is closed, so that the fluid 28 does not flow to the inlet 42 (and
may not enter the bypass line 80 at all).
[0086] Backpressure can still be applied to the annulus 14 by
variably regulating flow of the fluid 28 through the choke manifold
46 (and through the flow control device 82 and various other flow
control devices), because the valve 92 remains open. Thus, pressure
in the wellbore 16 can be maintained at a desired level, even
though the fluid 28 does not circulate through the drill string 12
and annulus 14.
[0087] Although the flow control devices 78, 94 are depicted in
FIGS. 2-14 as being separate elements of the system 10, they can be
combined, if desired. In FIG. 15, an alternative configuration of
the system 10 is representatively illustrated, in which a single
three-way flow control device 96 is used in place of the separate
flow control devices 78, 94.
[0088] Similarly, the flow control devices 74, 82 that variably
regulate flow of the fluid 28 from the standpipe manifold 48 to the
standpipe line 32 and the bypass line 80, respectively, could be
combined into a single three-way flow control device. Thus, it will
be appreciated that the scope of this disclosure is not limited to
any particular number, arrangement or configuration of elements in
the system 10, or to any particular manner of operating those
elements in the method.
[0089] It can now be fully appreciated that the above disclosure
provides significant advancements to the art of providing
continuous circulation of fluid through a drill string and annulus
in drilling operations. The system 10 and method examples described
above provide for maintaining flow of the fluid 28 through the
drill string 12 and annulus 14, even when connections are made or
broken in the drill string, or when circulation might otherwise be
ceased. The flow control devices 74, 82 can provide for gradual
automated diversion of the fluid 28 between the standpipe line 32
and the bypass line 80, so that fluctuations in flow and/or
pressure can be avoided.
[0090] More specifically, a method of providing continuous
circulation of fluid 28 through a drill string 12 and an annulus 14
between the drill string 12 and a wellbore 16 is provided to the
art by the above disclosure. In one example, the method comprises:
sealing off the annulus 14 from atmosphere; regulating flow of the
fluid 28 from the annulus 14 while the annulus is sealed off from
the atmosphere, thereby controlling pressure in the wellbore 16;
and diverting flow of the fluid 28 from a pump 58 to: a) an
uppermost connector 30 of the drill string 12, and b) an inlet 42
extending in a sidewall of the drill string 12. Each of the
uppermost connector 30 and the inlet 42 is communicable with a flow
passage 40 extending longitudinally through the drill string 12,
and the regulating step and the diverting step are performed
concurrently.
[0091] The diverting step can include gradually decreasing the flow
of the fluid 28 from the pump 58 to the uppermost connector 30
while gradually increasing the flow of the fluid 28 from the pump
58 to the inlet 42.
[0092] The diverting step can include gradually increasing the flow
of the fluid 28 from the pump 58 to the uppermost connector 30
while gradually decreasing the flow of the fluid 28 from the pump
58 to the inlet 42.
[0093] The pressure in the wellbore 16 may be maintained
substantially constant throughout the diverting step.
[0094] The diverting step can include automatically operating at
least one flow control device 74, 82 which controls flow to the
uppermost connector 30, and which controls flow to the inlet
42.
[0095] A substantially constant flow of the fluid 28 through the
drill string 12 and the annulus 14 may be maintained throughout the
diverting step.
[0096] The diverting step may include diverting the flow of the
fluid 28 from the pump 58 to an outlet line 44 via which the fluid
28 flows from the annulus 14.
[0097] Also provided to the art by the above disclosure is a
pressure and flow control system 10 for providing continuous
circulation of fluid 28 from a pump 58 through a drill string 12
and an annulus 14 between the drill string 12 and a wellbore 16. In
one example, the system 10 can include at least one flow control
device 74, 82 which diverts flow from the pump 58 to: a) a first
valve (e.g., flow control device 36) which selectively permits and
prevents communication between an uppermost connector 30 of the
drill string 12 and a flow passage 40 extending longitudinally
through the drill string 12, and b) a second valve (e.g., flow
control device 38) which selectively permits and prevents
communication between the flow passage 40 and an inlet 42 extending
in a sidewall of the drill string 12; and an annular seal device 18
which seals off the annulus 14 while the one or more flow control
devices 74, 82 divert flow between the first and second valves 36,
38.
[0098] The first and second valves 36, 38 can be operated in
response to sensor inputs to a hydraulics model 122.
[0099] The one or more flow control devices may comprise first and
second chokes 74, 82. The first choke 74 can variably regulate flow
from the pump 58 to the first valve 36, and the second choke 82 can
variably regulate flow from the pump 58 to the second valve 38.
[0100] Flow may be permitted through the first and second chokes
74, 82 simultaneously. The first and second chokes 74, 82 may be
operated in response to sensor 50, 52, 54, 100, 102, 104, 106, 108,
110, 112, 114, 116, 118 inputs to a hydraulics model 122. The first
and second chokes 74, 82 may be operated simultaneously, whereby
flow is gradually diverted between the first and second valves 36,
38.
[0101] The system 10 can include a choke 66 which variably
regulates flow of the fluid 28 from the annular seal device 18 and
maintains a substantially constant pressure in the wellbore 16
while the one or more flow control devices 74, 82 divert flow
between the first and second valves 36, 38.
[0102] The one or more flow control devices 74, 82 can be
automatically operated and maintain a substantially constant flow
of the fluid 28 through the drill string 12 and the annulus 14
while flow is diverted between the first and second valves 36,
38.
[0103] In the FIGS. 13 & 14 examples, the one or more flow
control devices 74, 82 can divert the flow of the fluid 28 from the
pump 58 to an outlet line 44 via which the fluid 28 flows from the
annular seal device 18.
[0104] Another method of providing continuous circulation of fluid
28 through a drill string 12 and an annulus 14 between the drill
string 12 and a wellbore 16 can comprise: sealing off the annulus
14 from atmosphere; regulating flow of the fluid 28 from the
annulus 14 while the annulus is sealed off from the atmosphere,
thereby controlling pressure in the wellbore 16; and operating at
least one flow control device 74, 82, thereby diverting flow of the
fluid 28 from a pump 58 to: a) a first valve (e.g., flow control
device 36) which selectively permits and prevents communication
between an uppermost connector 30 of the drill string 12 and a flow
passage 40 extending longitudinally through the drill string 12,
and b) a second valve (e.g., flow control device 38) which
selectively permits and prevents communication between the flow
passage 40 and an inlet 42 extending in a sidewall of the drill
string 12. The regulating step and the operating step may be
performed concurrently.
[0105] Another method of providing substantially continuous
circulation of fluid 28 through a drill string 12 and an annulus 14
between the drill string 12 and a wellbore 16 can comprise:
operating a hydraulics model 122; and in response to an output from
the hydraulics model 122, diverting flow of the fluid 28 from a
pump 58 to: a) an uppermost connector 30 of the drill string 12,
and b) an inlet 42 extending in a sidewall of the drill string 12.
Each of the uppermost connector 30 and the inlet 42 is communicable
with a flow passage 40 extending longitudinally through the drill
string 12.
[0106] Another method of providing substantially continuous
circulation of fluid 28 through a drill string 12 and an annulus 14
between the drill string 12 and a wellbore 16 can comprise:
inputting sensor measurements to a hydraulics model 122; and in
response to an output of the hydraulics model 122, automatically
operating at least one flow control device 74, 82, thereby
diverting flow of the fluid 28 from a pump 58 to: a) a first valve
36 which selectively permits and prevents communication between an
uppermost connector 30 of the drill string 12 and a flow passage 40
extending longitudinally through the drill string 12, and b) a
second valve 38 which selectively permits and prevents
communication between the flow passage 40 and an inlet 42 extending
in a sidewall of the drill string 12.
[0107] 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.
[0108] 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.
[0109] 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.
[0110] 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.
[0111] 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."
[0112] 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.
* * * * *