U.S. patent application number 13/884243 was filed with the patent office on 2013-12-12 for remote operation of cementing head.
This patent application is currently assigned to WEATHERFORD/LAMB, INC.. The applicant listed for this patent is Lev Ring, Sorin Gabriel Teodorescu. Invention is credited to Lev Ring, Sorin Gabriel Teodorescu.
Application Number | 20130327532 13/884243 |
Document ID | / |
Family ID | 44999971 |
Filed Date | 2013-12-12 |
United States Patent
Application |
20130327532 |
Kind Code |
A1 |
Ring; Lev ; et al. |
December 12, 2013 |
Remote Operation of Cementing Head
Abstract
Methods and systems are provided for remotely operating a
cementing head. Remotely operating a cementing head (202) may allow
for continued rotation as well as up or down movements (e.g., of a
top drive).
Inventors: |
Ring; Lev; (Houston, TX)
; Teodorescu; Sorin Gabriel; (The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Ring; Lev
Teodorescu; Sorin Gabriel |
Houston
The Woodlands |
TX
TX |
US
US |
|
|
Assignee: |
WEATHERFORD/LAMB, INC.
Houston
TX
|
Family ID: |
44999971 |
Appl. No.: |
13/884243 |
Filed: |
November 11, 2011 |
PCT Filed: |
November 11, 2011 |
PCT NO: |
PCT/US11/60460 |
371 Date: |
July 22, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61413233 |
Nov 12, 2010 |
|
|
|
61491755 |
May 31, 2011 |
|
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Current U.S.
Class: |
166/335 ;
166/244.1; 166/381; 166/66.5; 166/72 |
Current CPC
Class: |
E21B 47/12 20130101;
E21B 41/0007 20130101; E21B 47/16 20130101; E21B 33/16 20130101;
E21B 33/05 20130101; E21B 47/13 20200501; E21B 47/09 20130101 |
Class at
Publication: |
166/335 ;
166/244.1; 166/381; 166/72; 166/66.5 |
International
Class: |
E21B 47/12 20060101
E21B047/12; E21B 33/05 20060101 E21B033/05; E21B 47/16 20060101
E21B047/16 |
Claims
1. A method for remotely operating a cementing head in a wellbore,
the method comprising: exchanging signals between a first device
and a second device via a medium in connection with the cementing
head, wherein the second device is adjacent to the cementing head;
and performing cementing head operations corresponding to the
exchanged signals.
2. The method of claim 1, wherein the medium is a metal pipe.
3. The method of claim 1, wherein the first device is located at a
rig floor of the wellbore.
4. The method of claim 1, wherein exchanging the signals comprises
transmitting a signal for actuating operations of the cementing
head, wherein the signal is transmitted from the first device to
the second device.
5. The method of claim 4, further comprising receiving a signal
confirming the operations of the cementing head, wherein the signal
is received at the first device, originating from the second
device.
6. The method of claim 5, wherein sensors confirm the operations of
the cementing head.
7. The method of claim 1, wherein the signals comprise acoustic
signals and electromagnetic (EM) signals.
8. The method of claim 7, wherein the acoustic signals are
transmitted by an acoustic transmitter that is in physical contact
with the medium.
9. The method of claim 7, wherein the acoustic signals are
transmitted longitudinally, transversely, or a combination of both
with respect to the medium.
10. The method of claim 7, wherein the EM signals are exchanged by
toroidal coils that are not in physical contact with the
medium.
11. The method of claim 10, wherein at least one toroidal coil of
the first device comprises partial toroidal coil sections mounted
to form a complete toroidal coil.
12. The method of claim 11, wherein the complete toroidal coil is
formed by disposing the partial toroidal coil sections on a hinged
frame around the medium.
13. The method of claim 7, wherein the EM signals are exchanged by
a single-wire line transmission system.
14. The method of claim 1, wherein the operations comprise dropping
plugs, darts, tool activation, and confirmation devices into the
wellbore.
15. The method of claim 1, wherein exchanging the signals comprises
exchanging signals through a body of water using sonar or an
acoustic modem.
16. A system for remotely operating a cementing head in a wellbore,
the system comprising: a first device located at a rig floor of the
wellbore; a second device located adjacent to the cementing head;
and a control unit for remotely operating the cementing head,
wherein the control unit is configured to: exchange signals between
the first device and the second device via a medium in connection
with the cementing head; and perform cementing head operations
corresponding to the exchanged signals.
17. The system of claim 16, wherein the control unit is attached to
the second device.
18. The system of claim 17, further comprising another control unit
attached to the first device for processing the signals exchanged
between the first device and the second device.
19. The system of claim 16, further comprising sensors for
confirming the operations of the cementing head.
20. The system of claim 19, further comprising a handheld device
for controlling the first device and receiving confirmations for
the operations of the cementing head.
21. The system of claim 16, wherein the signals comprise acoustic
signals and electromagnetic (EM) signals.
22. The system of claim 21, wherein the EM signals are exchanged by
toroidal coils that are not in physical contact with the
medium.
23. The system of claim 22, wherein at least one toroidal coil of
the first device comprises partial toroidal coil sections mounted
to form a complete toroidal coil.
24. The system of claim 23, wherein the complete toroidal coil is
formed by disposing the partial toroidal coil sections on a hinged
frame around the medium.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 61/413,233, filed Nov. 12, 2010, and Ser. No.
61/491,755, filed May 31, 2011, which are herein incorporated by
reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the present invention generally relate to
remote operation of a cementing head.
[0004] 2. Description of the Related Art
[0005] A wellbore is formed to access hydrocarbon bearing
formations, e.g., crude oil and/or natural gas, by the use of
drilling. Drilling is accomplished by utilizing a drill bit that is
mounted on the end of a tubular string, such as a drill string. To
drill within the wellbore to a predetermined depth, the drill
string is often rotated by a top drive or rotary table on a surface
platform or rig, and/or by a downhole motor mounted towards the
lower end of the drill string. After drilling to a predetermined
depth, the drill string and drill bit are removed and a section of
casing is lowered into the wellbore. An annulus is thus formed
between the string of casing and the formation. The casing string
is temporarily hung from the surface of the well. The casing string
is cemented into the wellbore by circulating cement into the
annulus defined between the outer wall of the casing and the
borehole. The combination of cement and casing strengthens the
wellbore and facilitates the isolation of certain areas of the
formation behind the casing for the production of hydrocarbons.
[0006] It is common to employ more than one string of casing in a
wellbore. In this respect, the well is drilled to a first
designated depth with a drill bit on a drill string. The drill
string is removed. A first string of casing is then run into the
wellbore and set in the drilled out portion of the wellbore, and
cement is circulated into the annulus behind the casing string.
Next, the well is drilled to a second designated depth, and a
second string of casing or liner, is run into the drilled out
portion of the wellbore. If the second string is a liner string,
the liner is set at a depth such that the upper portion of the
second string of casing overlaps the lower portion of the first
string of casing. The liner string may then be fixed, or "hung" off
of the existing casing by the use of slips that utilize slip
members and cones to frictionally affix the new string of liner in
the wellbore. The second casing or liner string is then cemented.
This process is typically repeated with additional casing or liner
strings until the well has been drilled to total depth. In this
manner, wells are typically formed with two or more strings of
casing/liner of an ever-decreasing diameter.
[0007] Cementing operations have involved the use of plugs as a way
of correctly positioning the cement when setting the casing. Some
mechanisms have employed the use of pressure or vacuum to initiate
plug movement downhole for proper displacement of the cement to its
appropriate location for securing the casing properly. In addition,
confirmation of the plug movement was by line-of sight (e.g., flag
at the cementing head indicating ball drop). The early designs were
manual operations so that when it was time to release a plug for
the cementing operation, a lever was manually operated to
accomplish the dropping of the plug. This created several problems
because the plug-dropping head would not always be within easy
access of the rig floor. Frequently, depending upon the
configuration of the particular well being drilled, the dropping
head could be as much as 100 feet or more in the derrick (i.e., 100
feet from the rig floor). In order to properly actuate the plug to
drop, rig personnel would have to go up on some lift mechanism to
reach the manual handle. This process would have to be repeated if
the plug-dropping head had facilities for dropping more than one
plug. In those instances, each time another plug was to be dropped,
the operator of the handle would have to be hoisted to the proper
elevation for the operation. In situations involving foul weather,
such as high winds or low visibility, the manual operation had
numerous safety risks.
[0008] Hydraulic systems involving a stationary control panel
mounted on the rig floor, with the ability to remotely operate
valves in conjunction with cementing plugs, have also been used in
the past. Some of the drawbacks of such systems are that for
unusual applications where the plug-dropping head turned out to be
a substantial distance from the rig floor, the hoses provided with
the hydraulic system would not be long enough to reach the control
panel meant to be mounted on the rig floor. Instead, in order to
make the hoses deal with these unusual placement situations, the
actual control panel itself had to be hoisted off the rig floor.
This, of course, defeated the whole purpose of remote operation.
Additionally, the portions of the dropping head to which the
hydraulic lines were connected would necessarily have to remain
stationary. This proved somewhat undesirable to operators who
wanted the flexibility to continue rotation as well as up or down
movements during the cementing operation.
[0009] Accordingly, what is needed are techniques and apparatus for
remotely operating the cementing head.
SUMMARY OF THE INVENTION
[0010] One embodiment of the present invention provides a method.
The method generally includes exchanging signals between a first
device and a second device via a medium in connection with the
cementing head, wherein the second device is adjacent to the
cementing head, and performing cementing head operations
corresponding to the exchanged signals.
[0011] Another embodiment of the present invention is a system. The
system generally includes a first device located at a rig floor of
the wellbore, a second device located adjacent to the cementing
head, and a control unit for remotely operating the cementing head.
The control unit is typically configured to exchange signals
between the first device and the second device via a medium in
connection with the cementing head and perform cementing head
operations corresponding to the exchanged signals.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0013] FIG. 1 illustrates a drilling system, according to an
embodiment of the present invention.
[0014] FIG. 2 illustrates example cementing operations that may be
performed in the drilling system after installation of an outer
casing string, according to an embodiment of the present
invention.
[0015] FIG. 3 illustrates a system for remotely operating a
cementing head, according to an embodiment of the present
invention.
[0016] FIGS. 4A-C illustrate different views of a lower device for
remotely operating a cementing head, according to certain
embodiments of the present invention.
[0017] FIG. 5 is a flow diagram of exemplary operations for
remotely operating a cementing head, according to an embodiment of
the present invention.
[0018] FIGS. 6A-B illustrate a series of schematics that show how
spacer and cement slurry may displace drilling fluid in a wellbore,
according to embodiments of the present invention.
[0019] FIG. 7 illustrates example cementing operations that may be
performed for subsea operations, according to an embodiment of the
present invention.
DETAILED DESCRIPTION
[0020] FIG. 1 illustrates a drilling system 100, according to an
embodiment of the present invention. The drilling system 100 may
include a derrick 110. The drilling system 100 may further include
drawworks 124 for supporting, for example, a top drive 142. A
workstring 102 may comprise joints of threaded drill pipe connected
together, coiled tubing, or casing. For some embodiments, the top
drive 142 may be omitted (e.g., if the workstring 102 is coiled
tubing). A rig pump 118 may pump drilling fluid, such as mud 114,
out of a pit 120, passing the mud through a stand pipe and Kelly
hose to the top drive 142. The mud 114 may continue into the
workstring 102. The drilling fluid and cuttings, collectively
returns, may flow upward along an annulus formed between the
workstring and one of the casings 119i,o, through a solids
treatment system (not shown) where the cuttings may be separated.
The treated drilling fluid may then be discharged to the mud pit
120 for recirculation. A surface controller 125 may be in data
communication with the rig pump 118, pressure sensor 128, and top
drive 142.
[0021] After a first section of a wellbore 116 has been drilled, an
outer casing string 119o may be installed in the wellbore 116 and
cemented 111o in place. The outer casing string 119o may isolate a
fluid bearing formation, such as aquifer 130a, from further
drilling and later production. Alternatively, fluid bearing
formation 130a may instead be hydrocarbon bearing and may have been
previously produced to depletion or ignored due to lack of adequate
capacity. After a second section of the wellbore 116 has been
drilled, an inner casing string 119i may be installed in the
wellbore 116 and cemented 111i in place. The inner casing string
119i may be perforated and hydrocarbon bearing formation 130b may
be produced, such as by installation of production tubing (not
shown) and a production packer.
[0022] FIG. 2 illustrates example cementing operations that may be
performed in the drilling system 100, for example, after
installation of the outer casing string 119o, according to an
embodiment of the present invention. For example, after running a
casing string (e.g., outer casing string 119o) into the wellbore
116, the cementing 111o of the casing string 119o may be carried
out so that producible oil and gas, or saltwater may not escape
from the producing formation to another formation, or pollute
freshwater sands at shallower depth. In addition to the cementing
of a casing string, the example cementing operations illustrated in
FIG. 2 may also apply at least for the cementing of liners.
[0023] The casing string 119o may be run into the wellbore 116 with
a guide shoe 212. A float collar 210 may be located one to four
joints above the guide shoe 212, wherein the float collar 210 may
function as a back flow valve that may prevent the heavier cement
slurry 204 from flowing back into the casing string 119o after the
slurry has been placed into the annulus between the outside of the
casing string 119o and the borehole wall. Centralizers 208 may be
placed along the length of the casing string 119o, wherein the
centralizers 208 may ensure that the casing string 119o is nearly
centered in the borehole, thus allowing a more uniform distribution
of cement slurry flow around the casing string 119o. This nearly
uniform flow around the casing may be necessary to remove drilling
mud in the annulus and provide an effective seal.
[0024] The casing string 119o may be lowered into the drilling mud
in the wellbore 116 using the rig drawworks 124 and elevators. The
displaced drilling mud may flow to the mud tanks 120 and be stored
there for later use. Once the entire casing string 119o is in place
in the wellbore 116, the casing string 119o may be left hanging in
the elevators through the cementing operation. This may allow the
casing string 119o to be reciprocated (i.e., moved up and down) and
possibly rotated as the cement is placed in the annulus. This
movement may assist the removal of the drilling mud. While the
casing string 119o is hanging in the elevators, a cementing head
202 may be placed along an upper end of the workstring 102.
[0025] The cementing head 202 may be connected with flow lines that
come from, for example, a pump truck 214. A blender 216 may mix dry
cement and additives with water. A cement pump on the pump truck
214 may pump cement slurry 204 to the cementing head 202, which
will eventually form the cementing 111o. For some embodiments, a
preflush or spacer may initially be pumped ahead of the cement
slurry 204, wherein the spacer may be preceded by a bottom wiper
plug 206. The spacer may be used to assist in removing the drilling
mud from the annular space between the outside of the casing string
119o and the borehole wall.
[0026] Cementing operations have involved the use of plugs as a way
of correctly positioning the cement when setting the casing. Some
mechanisms have employed the use of pressure or vacuum to initiate
plug movement downhole for proper displacement of the cement to its
appropriate location for securing the casing properly.
Traditionally, when it was time to release a plug for the cementing
operation, manual operations and hydraulic systems have been
involved in operating valves in conjunction with the cementing
plugs. However, manual operations and operations involving
hydraulic systems, as described above, may become infeasible when
the cementing head could be over 100 feet above the rig floor. This
may prove somewhat undesirable to operators who want the
flexibility to continue rotation as well as up or down movements
(e.g., of the top drive 142) during the cementing operation.
Accordingly, what is needed are techniques and apparatus for
remotely operating the cementing head while continuing rotation as
well as up or down movements.
[0027] FIG. 3 illustrates a system 300 for remotely operating a
cementing head 202, according to an embodiment of the present
invention. The system 300 generally includes a lower device 304 and
an upper device 302 for exchanging signals (indicated by arrows)
via a medium in connection with the cementing head 202. An example
of a medium generally includes a metal pipe, such as the workstring
102 or the flow lines that come from the pump truck 214. As
illustrated, the upper device 302 may be adjacent to the cementing
head 202 and the lower device 304 may be located at the rig floor
306. The devices 302, 304 may include a control unit 308 and a
battery pack 310, although the devices 302, 304 may be powered by
other various sources. The lower device 304 may be controlled by a
handheld device (not shown), for example, from within a dog house
316 (i.e., a safe distance from the wellbore; outside zone zero).
The handheld device may be wired to the control unit 308.sub.1 of
the lower device 304. In order to use pneumatic lines (umbilicals)
that may be available on the cementing head 202, solenoid valves
314 may be used and controlled by the system. In addition, the
pressure for the system 300 may be provided by air cylinders 312
(e.g., pressurized gas).
[0028] For some embodiments, the system 300 may be a single-wire
line transmission system, wherein the cementing head 202 may be
used as the conductor, while both ends of the system 300 use a
common path for the return current (e.g., earth return). For
example, the cementing head 202 may be connected on the upper side
to ground through the top drive (or grounded to the derricks
ground). In addition, the lower side of the system 300, for
example, below the lower device 304, may be connected to ground
through slips, which make electrical contact with the mechanical
rig structure, ensuring another path to earth's ground.
[0029] The signals received by the upper device 302 may be
processed by the local control unit 308.sub.2 (dedicated
microcontroller) and actuate operations of the cementing head 202
(e.g., dropping plugs, darts, tool activation, and/or confirmation
devices--such as balls, RFID tags, etc.--into the wellbore). The
signals may be acoustic or electromagnetic (EM) signals. For some
embodiments, when the signals transmitted by the lower device 304
are acoustic signals (e.g., transmitted by a piezoelectric stack or
a solenoid), the upper device 302 may include piezoelectric sensors
(e.g., accelerometer) for detecting acoustic vibrations generated
along an acoustic throughpipe (e.g., workstring 102). For acoustic
signals, the devices 302, 304 may be in physical contact with the
medium (e.g., rigid contact with workstring 102). However, for EM
signals, the devices 302, 304 may not be in physical contact with
the workstring 102, allowing the workstring to rotate as well
during a cementing job. Although FIG. 3 illustrates a cementing
head, balls and/or darts may be dropped to actuate other downhole
devices (e.g., setting tool for liner hanger; packer). For some
embodiments, the devices 302, 304 may be removed, and cementing
head operations may be performed wirelessly (e.g., by radio
waves).
[0030] When the signals exchanged between the devices 302, 304 are
EM signals, the devices 302, 304 may include toroidal coils, as
will be discussed further herein. Various parameters of the
toroidal coils may be adjusted, such as the coil size, magnetic
core permeability, wire size, and the number of windings. More
specifically, each device 302, 304 may include two toroidal coils:
one for transmitting and another for receiving. A transmission
between the devices 302, 304 may be achieved by energizing the
winding of a transmission coil (e.g., the transmitting toroidal
coil of the lower device 304). As described above, the transmission
may be initiated by the handheld device. The current that flows
through the winding may produce a magnetic flux in the core, which
than induces a current in a conductor positioned in the center of
the toroid (e.g., workstring 102), which can represent various
signals. The current generated has to be high enough to overcome
potential noise, yet low enough to conserve power. If a string of
voltage pulses is applied to the coil, a corresponding string of
current pulses may be induced in the workstring 102.
[0031] The transmission may be received at the upper device 302
(e.g., by the receiving toroidal coil of the upper device 302) by
converting the current pulses flowing through the workstring 102
into voltage pulses. Confirmation of the operation may be indicated
by a signal transmitted from the upper device 302 to the lower
device 304. The handheld device may receive an indication of the
confirmation. For some embodiments, multiple confirmations may be
received. For example, acknowledgment of receipt of the command
transmitted from the lower device 304 may be received. As another
example, successful execution of the command or an error may be
indicated on the handheld device, which can lead to the ability to
troubleshoot the issue.
[0032] For some embodiments, each device 302, 304 may include a
single toroidal coil with a first winding for transmitting signals,
and a second winding for receiving signals, wherein the windings
may have different configurations. Examples of configurations that
may differ between the windings generally include a different
number of windings and a different diameter of wiring for the
winding. The receiver may require increased sensitivity to
compensate for noise that may be received (signal-to-noise ratio
(SNR)).
[0033] FIGS. 4A-C illustrate different views of the lower device
304, according to certain embodiments of the present invention. As
described above, the lower device 304 may include two toroidal
coils 610, 612 (e.g., one transmitter and one receiver). The
toroidal coils 610, 612 may be mounted on a frame 602 comprising
one or more hinges 604, where the ferromagnetic cores of the
toroidal coils 610, 612 may be physically interrupted (e.g., open
frame toroidal coils) but the magnetic flux generated may be
continuous due to the inductive coupling at the ends of the
individual core sections (i.e., the individual core sections
substantially complete a toroidal coil due to inductive coupling at
the ends of the core sections). Although there may be varied
amounts of spacing between the different core sections, as long as
there is inductive coupling at the ends of the individual core
sections, the individual core sections may substantially complete a
toroidal coil. Therefore, the toroidal coil sections 614, 616 may
be mounted on a frame 602, as illustrated in FIG. 4C, and the
toroidal coil sections 614, 616 may move (e.g., closer and further
to the workstring 102) in the same time with the frame 602. For
some embodiments, the lower device 304 may have wheels, or other
means of displacement, as illustrated in FIG. 4C, to allow for
mobility on the rig.
[0034] The toroidal coils 610, 612 may be formed by latching the
partial toroidal coil sections 614, 616 that are mounted on the
frame by a latching mechanism 606. The hinged frame 602 may have to
be along a certain diameter of the tubular member (e.g., workstring
102) to properly latch. For some embodiments, the hinged frame 602
may comprise stands 618 for moving the frame along the workstring
102 until an outer diameter of the workstring 102 causes the
partial toroidal coil sections 614, 616 to properly latch and form
the toroidal coils 610, 612. The hinged frame 602 may further
comprise centering guides (e.g., rollers) for centralizing the
frame around the workstring 102. For example, in order to ensure
concentricity of the toroidal coils 610, 612 around the workstring
102, a set of four equally spaced rollers 608 may be utilized in
order to maintain a preset gap between the coils 610, 612 and the
workstring 102, as illustrated in FIG. 4B.
[0035] FIG. 5 illustrates example operations 500 for remotely
operating a cementing head in a wellbore, according to certain
embodiments of the present invention. Examples of cementing head
operations generally include dropping plugs, darts, tool
activation, and/or confirmation devices--such as balls,
radio-frequency identification (RFID) tags, etc.--into the
wellbore. The operations may begin at 502 by exchanging signals
between a first device (e.g., located at a rig floor) and a second
device via a medium (e.g., a metal pipe) in connection with the
cementing head, wherein the second device may be adjacent to the
cementing head. At 504, cementing head operations may be performed
that correspond to the exchanged signals. Exchanging the signals
generally includes transmitting a signal (e.g., acoustic or EM) for
actuating operations of the cementing head, wherein the signal may
be transmitted from the first device to the second device. When
using acoustic signals, the signals may be transmitted
longitudinally, transversely, or a combination of both with respect
to the medium. A signal may be received at the first device,
originating from the second device, confirming the operations of
the cementing head. For some embodiments, proximity sensors may
confirm the operations of the cementing head, for example, after a
plug has reached a pre-defined location in the wellbore.
[0036] FIGS. 6A-B illustrate a series of schematics that show how
spacer and cement slurry may displace drilling fluid in a wellbore,
according to embodiments of the present invention. Two wiper plugs
702, 704 may be used to separate the spacer and the cement slurry
from the drilling fluid in the wellbore. For some embodiments, a
different number of plugs may be used (e.g., one plug or three
plugs). The cementing head 202 may have two retainer valves that
hold the wiper plugs 702, 704 in place. When the spacer and cement
slurry are to be pumped to the inside of the casing string through
the cementing head 202, the retainer valve for the bottom wiper
plug 702 may be activated. This may release the bottom wiper plug
702 into the initial portion of the spacer flow to the well, as
illustrated in FIG. 6B. This bottom wiper plug 702 may keep the
drilling fluid from contaminating the spacer and the cement slurry
while they pass through the inside of the casing string.
[0037] As described above, activation of the retainer valve for the
bottom wiper plug 702 may be initiated by transmitting a signal via
a lower toroidal coil 706 located on the rig floor (or at the
cement pump or a convenient location) through a medium (e.g.,
workstring 102) in connection with the cementing head 202. Control
electronics associated with the upper toroidal coil 708, located
adjacent to the cementing head 202, may receive and decode the
signal, then activate the retainer valve for releasing the bottom
wiper plug 702. For some embodiments, activating the retainer valve
may involve utilizing compressed gas (e.g., air, nitrogen, etc.) to
control the retainer valve.
[0038] Upon transmitting the signal via the lower toroidal coil
706, an operator (e.g., located on the rig floor and/or at the pump
truck) may receive several confirmations. For example, the operator
may receive a first confirmation indicating that the upper toroidal
coil 708 has received and decoded the signal transmitted by the
lower toroidal coil 706. Further, the operator may receive a second
confirmation indicating that the retainer valve for the bottom
wiper plug 702 has been activated. Moreover, the operator may
receive a third confirmation indicating that the bottom wiper plug
702 has actually been released after the retainer valve has been
activated. For example, a proximity sensor 710 may be used for
indicating that the bottom wiper plug 702 has been released (as
indicated by the downward arrow in FIG. 6B after the plug 702 has
passed the sensor 710). For some embodiments, the confirmations may
be visual or audible signals (e.g., separate lights or audible
signals indicating each confirmation). For some embodiments, the
confirmations may be signals transmitted through mediums in
connection with the cementing head 202, via the upper toroidal coil
708. For example, if there are operators located at both the rig
floor and the pump truck, each operator may receive the
confirmations independently via different mediums (e.g., via the
workstring 102 and the flow lines at the pump truck 214). Also, as
described above, confirmations may be received by a handheld
device.
[0039] When a predetermined volume of cement slurry has passed
through the cementing head 202, the retainer valve for the top
wiper plug 704 may be activated, releasing the top wiper plug 704
into the flow to the well (not illustrate). Activation of the
retainer valve for the top wiper plug 704 and the confirmations may
be performed as described above. For some embodiments, parameters
of the signal transmitted by the lower toroidal coil 706 (e.g.,
frequency) may be modified in accordance with the fluid traveling
through the medium (e.g., workstring 102).
[0040] Remote Operation of Cementing Head for Subsea Operations
[0041] FIG. 7 illustrates example cementing operations that may be
performed for subsea operations, according to an embodiment of the
present invention. Communications between a vessel 824 and a well
836 that is separated by a body of water 818 may be performed by
coupling at least two means of communication. For example, to
confirm the location of a plug in the well 836, a first signal may
be transmitted through a well casing 819 of the well 836 up to the
floor 816 of the sea (i.e., mudline). From the floor 816, a second
signal may be transmitted to the surface 822 of the sea by using
sonar, as will be described further herein.
[0042] Referring to FIG. 7, there is shown a well 836 that has been
drilled into the earth beneath the sea 818 or other body of water.
A subsea wellhead structure 804 may be emplaced on the floor 816 of
the sea at the top of the well 836. Suspended in the well 836 from
the wellhead 804 may be a string of well casing 819. A riser pipe
814 may be connected to the wellhead 804 and may communicate with
the casing string 819 through passages in the wellhead 804. The
riser pipe 814 may extend up through the water to a drilling ship
or vessel 824 floating on the surface 822 of the sea directly over
the wellhead 804. The riser pipe 814 may extend up through an
opening in the ship 824, and the top of the riser pipe 814 may be
exposed above the waterline and within the vessel 824. A string of
drill pipe 802 may extend within the riser pipe 814 upwardly from
the wellhead 804 and may terminate at the top in a cementing head
820. The drilling vessel 824 may be equipped with a derrick
structure 834.
[0043] The cementing head 820 may have an upper set of toroidal
coils 832 located adjacent to the cementing head 820. The upper set
of toroidal coils 832 may receive signals from a lower set of
toroidal coils 830 located on the deck 826 of the vessel 824,
wherein the lower set of toroidal coils 830 may transmit the
signals through a medium in connection with the cementing head 820.
The signals received by the upper set of toroidal coils 832 may
actuate operations of the cementing head 820 (e.g., dropping
darts). For some embodiments, the lower set of toroidal coils 830
may be attached to or wrapped around a metal pipe (e.g., drill pipe
802) and may transmit signals through the metal pipe (i.e., a metal
pipe in connection with the upper set of toroidal coils 832
attached to the cementing head 820). The signals may be acoustic or
electromagnetic signals, as described above.
[0044] When spacer fluid and cement slurry are ready to be pumped
to the inside of the drill pipe 802 through the cementing head 202
(and eventually into the well casing 819), a retainer valve for a
bottom wiper dart may be activated. This bottom wiper dart may keep
drilling fluid from contaminating the spacer fluid and the cement
slurry while they pass through the inside of the drill pipe
802.
[0045] Activation of the retainer valve for the bottom wiper dart
may be initiated by transmitting a signal via the lower set of
toroidal coils 830 located on the deck 826 through the drill pipe
802 in connection with the cementing head 820. The upper set of
toroidal coils 832, located adjacent to the cementing head 820, may
receive and decode the signal, then activate the retainer valve for
releasing the bottom wiper dart. For some embodiments, activating
the retainer valve may involve utilizing compressed gas to control
the retainer valve. After the bottom wiper dart has been released,
confirmation of the release may be indicated to an operator on the
deck 826. For some embodiments, one or more proximity sensors that
detect when the bottom wiper dart has been released may trigger on
a light to notify the operator that the bottom wiper dart has been
released. In addition, the operator may be notified in other ways,
as described above.
[0046] When a predetermined volume of cement slurry has passed
through the cementing head 820, a retainer valve for a top wiper
dart may be activated, releasing the top wiper dart into the flow
to the well 836. Activation of the retainer valve for the top wiper
dart and confirmation of the release may be performed as described
above. For some embodiments, parameters of the signal transmitted
by the lower set of toroidal coils 830 (e.g., frequency) may be
modified in accordance with the fluid traveling through the medium
(e.g., drill pipe 802).
[0047] After a dart has been dropped into the well 836, and seated
into a corresponding plug, confirmation of the location of the dart
and plug in the well 836 may be useful in determining successful
operation of the cementing head 820 using any of the
above-described methods. For example, it may be useful to determine
whether the bottom wiper dart and corresponding plug has reached a
pre-defined location, such a float collar (e.g., by a pressure
sensor or load cell). For some embodiments, a first signal may be
transmitted through the well casing 819 up to the floor 816 of the
sea. A device 806 may receive the first signal and transmit a
second signal 808 up to the surface 822 of the sea using sonar or
an acoustic modem.
[0048] Due to transmitting between multiple mediums (e.g., seawater
and within the wellbore), coupling of the first signal with the
second signal may be required for successfully determining whether
the bottom wiper dart and plug have reached the pre-defined
location. For some embodiments, the second signal may be
transmitted by a remotely operated vehicle (ROV) that is plugged in
at a convenient location (e.g., at the blowout preventer or
wellhead 804). For some embodiments, a buoy 810 may receive the
second signal 808 transmitted through the sea 818 and transmit a
signal via a transmission line 812 to a receiver located on the
deck 826. The receiver located on the deck 826 may process the
signal to confirm the location of the dart and corresponding plug.
For some embodiments, the direction of signal transmission between
the buoy 810 and the device 806 may be downwards when a signal is
transmitted from the vessel 824 to the well 836.
[0049] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
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