U.S. patent application number 12/587830 was filed with the patent office on 2010-04-15 for fluid logic tool for a subterranean well.
Invention is credited to Gregg W. Stout.
Application Number | 20100089587 12/587830 |
Document ID | / |
Family ID | 42097830 |
Filed Date | 2010-04-15 |
United States Patent
Application |
20100089587 |
Kind Code |
A1 |
Stout; Gregg W. |
April 15, 2010 |
Fluid logic tool for a subterranean well
Abstract
An operating tool uses programmed fluid logic provided by use of
flow paths including pre-determined spaced ports and varying
orifice sizes to provide discreet pressures and fluid flow rates
upon pressure differential sensitive devices, such as a membrane or
piston, in operative communication with an operative sleeve to
manipulate one or more secondary tools, and/or to perform a
service, such as, for example, acidzing or stimulation or injecting
proppants within the well. The tool remains "immune" to internal
well hydraulic or hydrostatic pressures, if desired, until the
fluid logic is achieved. The fluid logic is adjustable for
activation of tools sequentially by making changes in the port
spacing and fluid relief profiles so that all tools can be actuated
by a single geometry of fluid flow paths, or each tool can have its
own unique fluid flow geometry so it becomes hydraulically
coded.
Inventors: |
Stout; Gregg W.;
(Montgomery, TX) |
Correspondence
Address: |
Beirne Maynard & Parsons, L.L.P.
1300 Post Oak Blvd, Suite 2500
Houston
TX
77056
US
|
Family ID: |
42097830 |
Appl. No.: |
12/587830 |
Filed: |
October 14, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61196326 |
Oct 15, 2008 |
|
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|
61207131 |
Feb 9, 2009 |
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Current U.S.
Class: |
166/319 |
Current CPC
Class: |
E21B 41/00 20130101;
E21B 2200/06 20200501; E21B 34/10 20130101; E21B 23/06 20130101;
E21B 23/04 20130101 |
Class at
Publication: |
166/319 |
International
Class: |
E21B 34/00 20060101
E21B034/00 |
Claims
1) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source for said operating fluid to
manipulate one or more secondary tools within said well,
comprising: (1) an outer member carried into said well on a first
tubular conduit including an outer cylindrical housing and an inner
cylindrical housing, and defining a fluid chamber between said
housings; (2) an inner member positionable within said outer member
and carried into said well on a second tubular conduit; (3) an
activation sleeve disposed within said outer member and selectively
moveable therein in at least one direction to manipulate an
auxiliary device within said well; (4) a piston head in selective
operative communication with said sleeve and defining first and
second piston head surfaces; (5) a plurality of orifice means, one
of said orifice means being in communication with one of said
piston head surfaces, and another of said orifice means in
communication with the other of said piston head surfaces, each of
said orifice means including at least one orifice profile defined
on at lest one of said outer and inner members, said orifice means
providing sufficient operating fluid flow and pressure at said
piston head to manipulate said activating sleeve; and (6) a
plurality of fluid transmitting ports disposed through the inner
cylindrical housing for transmitting the programmed fluid logic in
the operating fluid at a pre-determined flow rate and pressure
delivered by the operating conduit within one of the operating tool
flow paths, through the orifice means into one of said ports and
upon one of said piston head surfaces, to move said piston head and
said activation sleeve in one direction and during said movement,
to direct fluid in said chamber adjacent the second piston head
surface out of said chamber through another of said fluid
transmitting ports, thence into the second flow path of the
operating conduit.
2) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source for said operating fluid to
manipulate a plurality of secondary tools within said well,
comprising: (1) an outer member carried into said well on a first
tubular conduit including an outer cylindrical housing and an inner
cylindrical housing, and defining a fluid chamber between said
housings; (2) an inner member positionable within said outer member
and carried into said well on a second tubular conduit; (3) a
plurality of activation sleeves disposed within said outer member,
each said sleeve being independently and selectively moveable
therein in at least one direction to manipulate an associated
auxiliary device within said well; (4) a piston head carried on
each said sleeve and defining first and second piston head
surfaces; (5) a plurality of orifice means associated with each of
said piston heads, one of each of said orifice means being in
communication with one of each of said piston head surfaces, and
another of said orifice means in communication with the other of
each of said piston head surfaces, each of said orifice means
including at least one orifice profile defined on at least one of
said outer and inner members, said orifice means providing
sufficient but varying operating fluid flows at pre-determined
pressures at each of said piston heads to manipulate said
associated activating sleeve; and (6) a plurality of fluid
transmitting ports disposed through the inner cylindrical housing
for transmitting the programmed fluid logic in the operating fluid
at specific flow rates and pressures delivered by the operating
conduit within one of the operating tool flow paths, through the
respective orifice means into one of said respective said ports and
upon one of said piston head surfaces, to move the respective said
piston head and said respective activation sleeve in one direction
and during said movement, to direct fluid in said respective
chamber adjacent a second piston head surface out of said chamber
through another of said fluid transmitting ports, thence into the
second flow path of the operating conduit.
3) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source for said operating fluid to
manipulate one or more secondary tools within said well,
comprising: (1) an outer member carried into said well on a first
tubular conduit including an outer cylindrical housing and an inner
cylindrical housing, and defining a fluid chamber between said
housings; (2) an inner member positionable within said outer member
and carried into said well on a second tubular conduit; (3) an
activation sleeve disposed within said outer member and selectively
moveable therein in at least one direction to manipulate an
auxiliary device within said well; (4) pressure differential
sensitive means in selective operative communication with said
sleeve; (5) a plurality of orifice means, each of said orifice
means being in communication with said pressure differential
sensitive means, each of said orifice means including at least one
orifice profile defined on at lest one of said outer and inner
members, said orifice means providing sufficient operating fluid
flow and pressure at said pressure differential sensitive means to
selectively manipulate said activating sleeve; and (6) a plurality
of fluid transmitting ports disposed through the inner cylindrical
housing for transmitting the programmed fluid logic in the
operating fluid at a flow rate and pressure within one of the
operating tool flow paths, through the orifice means into one of
said ports and upon said pressure differential sensitive means, to
operatively communicate said pressure differential sensitive means
with said activation sleeve to move said sleeve in one direction
and during said movement, to direct fluid in said chamber adjacent
said pressure differential sensitive means out of said chamber
through another of said fluid transmitting ports, thence into the
second flow path.
4) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of said operating tool having first and second flow paths
therein to manipulate a plurality of auxiliary devices within said
well, comprising: (1) an outer member carried into said well on a
first tubular conduit including an outer cylindrical housing and an
inner cylindrical housing, and defining a fluid chamber between
said housings; (2) an inner member positionable within said outer
member and carried into said well on a second tubular conduit; (3)
a plurality of activation sleeves disposed within said outer
member, each said sleeve being independently and selectively
moveable therein in at least one direction to manipulate an
associated auxiliary device within said well; (4) pressure
differential sensitive means in selective separate operative
communication with each said sleeve; (5) a plurality of orifice
means associated with each of said pressure differential sensitive
means, each of said orifice means including at least one orifice
profile defined on at lest one of said outer and inner members,
said orifice means providing sufficient but varying operating fluid
flow rates at pressures at each of said pressure differential
sensitive means sufficient to move an associated activating sleeve
in a direction to manipulate an associated auxiliary device in said
well; and (6) a plurality of fluid transmitting ports disposed
through the inner cylindrical housing for transmitting the
programmed fluid logic in the operating fluid at flow rates and
pressures within one of the operating tool flow paths, through the
respective orifice means into one of said respective said ports and
upon one of said pressure differential sensitive means, during
manipulation of the respective said pressure differential sensitive
means and said respective activation sleeve in one direction and
during said manipulation, to direct fluid in said respective
chamber adjacent a second pressure differential sensitive means out
of said chamber through another of said fluid transmitting ports,
thence into the second flow path.
5) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating device having first and second flow paths
therein communicating with a source for said operating fluid to
perform a service operation within said well, comprising: (1) an
outer member carried into said well on a first tubular conduit
including an outer cylindrical housing and an inner cylindrical
housing, and defining a fluid chamber between said housings; (2) an
inner member positionable within said outer member and carried into
said well on a second conduit; (3) activation means disposed within
said outer member and selectively moveable therein in at least one
direction to initiate said service operation within said well; (4)
pressure differential sensitive means in selective operative
communication with said activation means; (5) a plurality of
orifice means, each of said orifice means being in communication
with said pressure differential sensitive means, each of said
orifice means including at least one orifice profile defined on at
lest one of said outer and inner members, said orifice means
providing sufficient operating fluid flow and pressure at said
pressure differential sensitive means to selectively initiate said
service operation; and (6) a plurality of fluid transmitting ports
disposed through the inner cylindrical housing for transmitting the
programmed fluid logic in the operating fluid at a flow rate and
pressure delivered within one of the operating tool flow paths,
through the orifice means into one of said ports and upon said
pressure differential sensitive means, to operatively communicate
said pressure differential sensitive means with said activation
means to move said means in one direction and during said movement,
to direct fluid in said chamber adjacent said pressure differential
sensitive means out of said chamber through another of said fluid
transmitting ports, thence into the second flow path as the service
operation is performed.
6) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source for said operating fluid to
perform a service operation within said well, comprising: (1) an
outer member carried into said well on a first tubular conduit
including an outer cylindrical housing and an inner cylindrical
housing, and defining a fluid chamber between said housings; (2) an
inner member positionable within said outer member and carried into
said well on a second tubular conduit; (3) activation means
disposed within said outer member and selectively moveable therein
in at least one direction to initiate said service operation within
said well; (4) pressure differential sensitive means in selective
operative communication with said activation means; (5) a plurality
of orifice means, each of said orifice means being in communication
with said pressure differential sensitive means, each of said
orifice means including at least one orifice profile defined on at
lest one of said outer and inner members, said orifice means
providing sufficient operating fluid flow and pressure at said
pressure differential sensitive means to selectively initiate said
service operation; and (6) a plurality of fluid transmitting ports
disposed through the inner cylindrical housing for transmitting the
programmed fluid logic in the operating fluid at a flow rate and
pressure delivered to the operating tool and within one of the
operating tool flow paths, through the orifice means into one of
said ports and upon said pressure differential sensitive means, to
operatively communicate said pressure differential sensitive means
with said activation means to manipulate said activation means to
direct fluid in said chamber adjacent said pressure differential
sensitive means out of said chamber through another of said fluid
transmitting ports, thence into the well as the service operation
is performed.
7) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source of a second operating fluid to
perform a service operation within said well, comprising: (1) an
outer member carried into said well on a first tubular conduit
including an outer cylindrical housing and an inner cylindrical
housing, and defining a fluid chamber between said housings; (2) an
inner member positionable within said outer member and carried into
said well on a second tubular conduit; (3) activation means
disposed within said outer member and selectively moveable therein
in at least one direction to initiate said service operation using
said second operating fluid within said well; (4) pressure
differential sensitive means in selective operative communication
with said activation means; (5) a plurality of orifice means, each
of said orifice means being in communication with said pressure
differential sensitive means, each of said orifice means including
at least one orifice profile defined on at lest one of said outer
and inner members, said orifice means providing sufficient
operating fluid flow and pressure at said pressure differential
sensitive means to selectively initiate said service operation; and
(6) a plurality of fluid transmitting ports disposed through the
inner cylindrical housing for transmitting the programmed fluid
logic in the operating fluid at a flow rate and pressure delivered
to the operating tool and within one of the operating tool flow
paths, through the orifice means into one of said ports and upon
said pressure differential sensitive means, to operatively
communicate said pressure differential sensitive means with said
activation means to manipulate said activation means to direct said
operating fluid in said chamber adjacent said pressure differential
sensitive means out of said chamber through another of said fluid
transmitting ports, thence to direct said second operating fluid
through the well as the service operation is performed.
8) An operating tool using programmed fluid logic applied through
an operating fluid for use in a subterranean well and activatable
by use of an operating conduit having first and second flow paths
therein communicating with a source for said operating fluid at the
top of the well to perform a service operation within said well,
comprising: (1) an outer member carried into said well on a first
tubular conduit including an outer cylindrical housing and an inner
cylindrical housing, and defining a fluid chamber between said
housings; (2) an inner member positionable within said outer member
and carried into said well on a second tubular conduit; (3) an
activation sleeve disposed within said outer member and selectively
moveable therein in at least one direction to initiate said service
operation within said well; (4) pressure differential sensitive
means in selective operative communication with said activation
sleeve; (5) a plurality of orifice means, each of said orifice
means being in communication with said pressure differential
sensitive means, each of said orifice means including at least one
orifice profile defined on at lest one of said outer and inner
members, said orifice means providing sufficient and pre-determined
operating fluid flow and pressure at said pressure differential
sensitive means to selectively initiate said service operation; and
(6) a plurality of fluid transmitting ports disposed through the
inner cylindrical housing for transmitting the programmed fluid
logic in the operating fluid at a pre-determined flow rate and
pressure delivered through the operating conduit to the operating
tool and within one of the operating tool flow paths, through the
orifice means into one of said ports and upon said pressure
differential sensitive means, to operatively communicate said
pressure differential sensitive means with said activation sleeve
to manipulate said activation sleeve to direct operative fluid in
said chamber adjacent said pressure differential sensitive means
out of said chamber through another of said fluid transmitting
ports, thence into the well as the service operation is performed.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a utility application based upon: (1)
Provisional application Ser. No. 61196326, filed Oct. 15, 2008,
entitled "Fluid Logic Tool for a Subterranean Well", Gregg W.
Stout, inventor; and (2) Provisional application Ser. No. 61207131,
filed Feb. 9, 2009, entitled "Fluid Logic Tool", Gregg W. Stout,
inventor.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] This invention relates to downhole tools for oil and gas
wells and similar applications and more particularly to servicing
or completing wells.
[0004] 2. Brief Description of Prior Art
[0005] Many types of downhole tools are conveyed into the well for
various types of applications in order to produce oil and gas from
underground formations. As an example, typical downhole tools are
packers, sliding sleeves, ball valves, flapper valves, and
perforating guns, and gravel pack screens, to mention a few. Well
formations may have one or more producing zones where each zone may
need a series of tools such as a packer and a sliding sleeve and a
gravel pack screen. When screens are run and positioned in a zone,
this is commonly called a gravel pack completion or a frac pack
completion and many varieties of downhole tool hookups exist.
[0006] Packers are typically used to create a seal between the I.D.
of the casing to the O.D. of a production or completion string thus
isolating producing formations. Typically, completion packers are
set in the well bore by application of tubing pressure through the
inside of a work string and setting tool. A ball may be dropped
from the surface and it seats at a point below the setting tool,
workstring pressure is applied, and the setting tool strokes to set
the packer. A ball or ball seat can obstruct access the tools below
the packer. Often it is attempted to recirculate the ball out of
the hole. Sometimes a plug is set in a nipple below the packer so
setting pressure can be applied to set the packer. In this case,
the plug may have to be removed.
[0007] The current invention provides a means to maintain a full
open I.D. through the completion. Packers are also set on wireline
or electric line where a Baker E-4 generates sufficient pressure
and force to set a packer, but this method is usually limited to
setting sump packers or setting a single completion packer with
minimal weight hanging on the bottom of the packer.
[0008] Intelligent well completions use some form of control line
that is strapped to the O.D. of a completion string that
hydraulically or electrically can generate force to set packers.
This process can be very expensive and control lines are always
subject to some type failure.
[0009] The present invention provides a new alternative to
hydraulically set single or multiple packers in a single run
without dropping balls or setting plugs. Additionally the same tool
that sets the packers can be configured to unset packers or actuate
other tools during a single trip into the hole.
[0010] Sliding sleeves are used to control the flow of fluid or
slurry to or from a formation into the pipe string. Sliding
sleeves, or frac sleeves, typically have profiles on the inside of
the sleeves that allow mechanical shifting tools to engage the
inside of the sleeves so they can be shifted open or closed.
Sliding sleeves may be selectively shifted with different shifting
tool key profiles such as the Otis standard and selective profiles
for the Model "B" shifting tool. Other companies have varying key
profiles for shifting sleeves and shifting tools.
[0011] The present invention allows one tool configuration to shift
all sliding sleeves selectively or only shift, or actuate, one type
of tool and not the other tools.
[0012] The problem with shifting keys is that the shifting tools
tend to jump out of the mating profiles for various reasons and
shifting force is limited as a result. Sliding sleeves that have
been downhole for extended periods of time tend to collect scale
and can become difficult to shift. The present invention provides a
means to apply a higher force to shift sliding sleeves where
conventional methods tend to fail, especially in highly deviated
wells. It is sometimes impossible to shift sliding sleeves in a
deviated well with wireline because the deviation prevents the
wireline shifting tool to reach the sliding sleeve. Also, it may be
possible to reach sliding sleeves in a deviated well with coiled
tubing and a shifting tool, but when the shifting tool engages the
sliding sleeve; the drag forces on the coiled tubing through the
bend limit the ability to shift the sliding sleeves.
[0013] The present invention does not create additional drag force
on the coiled tubing, so the ease of moving coiled tubing through
the bend is increased.
[0014] Also, the number of shifting tool key profiles and mating
sliding sleeve profiles is limited, so shifting selectivity in
multiple zones is also limited. Furthermore, shifting tool collets
or keys sometimes break leaving unwanted debris in the hole.
[0015] The present invention provides a means, without collets or
keys, to selectively shift an unlimited number of sliding sleeves,
opened and closed, in combination with the force generated by
hydraulics.
[0016] Sliding sleeves also are shifted open and closed by the use
of control lines that hydraulically, electrically or mechanically
stroke a sleeve up or down. It would be advantageous to have a
backup means to shift sliding sleeves either open or closed if the
control lines fail. It would also be very convenient, from an
operations standpoint, to shift all the sliding sleeves in the hole
either opened or closed by one continue sweep of an actuating tool
through the inside of the sliding sleeves.
[0017] The present invention also allows the option of setting
packers, or actuating other devices, during the same trip used to
shift the sliding sleeves.
[0018] Ball valves and flapper valves may be run in a completion to
control flow of well fluid through the pipe either to stop well
production or to prevent fluid loss to the formation. These devices
may be operated by application of tubing or annulus pressure or by
shifting tools stroked up or down to open or close the valves. Ball
valves can be actuated by pressuring either on the annulus side or
the tubing side. In many cases annulus pressure is not possible due
to the completion configuration. Also, if a single pressure to
actuate the ball valve is only available to open a close the valve,
then a so called "J" mechanism is used. "J` mechanisms sometimes
jam up and don't work or the operator gets confused and doesn't
know where he is at in the "J".
[0019] The present invention provides a means to open and close a
Ball Valve from the tubing pressure side without a "J" mechanism to
cause problems and no pressure needs to be applied to the annulus
side of the valve.
[0020] It would be desirable to selectively hydraulically operate,
open and close, ball valves or flapper valves or other types of
valves with the same tool that is used to set packers and operate
sliding sleeves all in the same trip.
[0021] It would also be desirable to have a tool system where tools
such as packers, sliding sleeves, and valves would not be actuated
from application of tubing or annulus pressure anywhere in the
hole. The current invention only actuates tools when the correct
fluid geometries are present, so inadvertent or unexpected
application of pressures to the tools does not affect the
tools.
[0022] Perforating guns are used to generate holes in casing or
tubing to provide flow paths for producing oil or gas. These holes
also provide flow paths to place proppant into formations from the
surface. Perforating guns are detonated a number of different ways,
i.e., electric line, jarring with wireline, impacting firing heads
with drop bars, or application of tubing or annulus pressure to
actuate a firing head that in turn detonates the perforating gun or
guns. A problem exists when it is desired to fire multiple guns at
different times in multiple zones, especially with single trip TCP
(tubing conveyed perforating) guns. The TCP guns are the more
desirable gun because of the perforating performance, i.e., large
charges with good charge stand-off, and the ability to perforated
long zones either vertical or horizontal. Methods are lacking to
selectively fire these guns in multiple zones without coming out of
the hole.
[0023] The present invention offers a means to selectively
hydraulically detonate perforating guns with the same tool that is
used to open and close ball valves or flapper valves, or other
types of valves, set packers, and operate sliding sleeves all in
the same trip whether the well is vertical or horizontal.
Furthermore, the present invention offers a solution to preventing
the pressure generated from the detonation of one gun, to
inadvertently apply pressure to a second or third gun that could
detonate the gun. The invention fires only one guns at a time only
when fluid geometry between an inner tool and an outer tool
matches.
[0024] It would be advantageous to operate many types of tools
other than those described above in a single trip into the well. A
single trip in the well equates to reduced rig time due to fewer
pipe runs in and out of the well. The simplicity of the inner tool
of the present invention and the use of hydraulics to generate
higher forces offer increased reliability downhole. It would also
be desirable to operate many tools downhole, multiple times, and
still be able to place cement, place fluids, acidize, frac multiple
formations, reverse out, and operate the above tools all in the
same trip. It would also be beneficial to be able to re-enter the
well and operate all of the above tools in one trip, while being
able to "identify" each tool to assure the correct tool is being
actuated.
SUMMARY OF THE INVENTION
[0025] An operating tool is provided using programmed fluid logic
applied through an operating fluid for use in a subterranean well.
The tool is activatable by use of an operating conduit having first
and second flow paths communicating with a source for the operating
fluid, preferably at the top of the well, to perform a service
operation within the well.
[0026] The operating tool comprises an outer member carried into
the well on a first tubular conduit including an outer cylindrical
housing and an inner cylindrical housing, and defining a fluid
chamber between the housings. The inner member is positionable
within the outer member and is carried into the well on a second
tubular conduit.
[0027] The operating tool also includes an activation means, such
as a sleeve, disposed within the outer member and is selectively
manipulatable, or moveable therein in at least one direction to
initiate the service operation within the well. Pressure
differential sensitive means, such as a piston head, a thin metal
flexible membrane, or the like, is in selective operative
communication with the activation means, such as a sleeve.
[0028] The tool further includes a plurality of orifice means, each
of said orifice means being in communication with the pressure
differential sensitive means. Each of the orifice means includes at
least one orifice profile defined on at lest one of the outer and
inner members. The orifice means provide sufficient operating fluid
flow at a pressure at the pressure differential sensitive means to
selectively initiate the service operation, such as setting a
packer, opening or closing a valve, initiating activation of a
perforating gun, transmitting proppant into the well, transmitting
acidizing fluid into a zone or zones within the well, or delivering
a stimulation fluid into the well.
[0029] The operating tool also includes a plurality of fluid
transmitting ports disposed through the inner cylindrical housing
for transmitting the programmed fluid logic in the operating fluid
at a flow rate and pressure delivered by the operating conduit
within one of the operating tool flow paths, through the orifice
means into one of the ports and upon the pressure differential
sensitive means, to selectively and operatively communicate the
pressure differential sensitive means with the activation means to
move the activation means in one direction and, during such
movement, to direct fluid in the chamber adjacent the pressure
differential sensitive means out of the chamber through another of
the fluid transmitting ports, thence into the second flow path of
the operating conduit, as the service operation is performed.
[0030] The "operating fluid" contemplated for use in the present
invention may be any of a number of fluids conventionally used in
drilling, workover, or completion operations in subterranean wells.
Such fluids may also include proppants, gravel and other additives
for various known uses in the wells.
[0031] The well may be acidized or any other operation requiring a
fluid to be transmitted, may be performed in the well using either
the operating fluid or a second or treatment fluid introduced into
the well after the service operation is performed.
[0032] The "first tubular conduit" may be casing, or a conventional
work string or production string.
[0033] The "operating conduit" or operating conduit, may be casing
(in the event that the well is uncased or "open hole", drilling,
production or workover tubing, coiled tubing, or the like.
[0034] The "pressure differential sensitive means" may be a piston
head, a thin membrane, a component which dissolves or operatively
deteriorates upon certain exposure to a particular chemical, such
as an acid solution (i.e. a fluid having a pH below 7.0).
[0035] By "programmed fluid logic" and/or "fluid flow path logic",
I mean to refer to the resultant anticipated fluid flow rate at a
given pressure resulting from the use of the orifice means and the
fluid transmitting ports at the given depth of the well upon the
pressure differential sensitive means sufficient to initiate and
complete the manipulation of an auxiliary tool or remedial or other
service operation(s) in the well.
[0036] The present invention provides a downhole tool system and
method that allows for completing or servicing a well with single
or multiple zones of production. Stated one way, an outer tool, or
series of outer tools, are run in a completion or other tubular
string positioned inside of a casing or other tubular conduit
string, or mounted in the casing, are selectively initiated to
manipulation hydraulically by an inner tool that is positioned in
close proximity to the inside of the outer tool or tools. Fluid
flow path logic between the inner and outer tools allows actuation
or manipulation of the outer tool with application or reduction of
surface pressure. The outer tools remain "immune" to internal
hydraulic or hydrostatic pressures, if desired, until the
pre-selected fluid logic is achieved by use of the inner tool. The
fluid logic between the tools is adjustable by making changes in
the port spacing and fluid relief profiles so that all tools can be
actuated by a single geometry of fluid flow paths, or each tool can
have its own unique fluid flow geometry so it becomes hydraulically
coded, so to speak. Many hydraulic codes can be used to selectively
actuate a variety of tools in single zones or multiple zones. The
inner tool also offers a well "location finder" option. The
"location finder" hydraulically identifies an outer tool and
verifies inner tool position in the well to assure the proper outer
tool is being actuated.
[0037] A large number of downhole functions can be performed in a
single trip into the well, for example, set and release packers,
open and close sliding sleeves, detonate perforating guns, open and
close flappers or ball valves. All of these procedures can be done
with significant forces generated by hydraulics. The inner tool is
very versatile in that it can be conveyed by several means, and not
only serves as an actuation tool, but can also be used for various
types of well services, such as cementing, acidizing or
fracturing.
[0038] The invention provides a tool system where an inner
through-tubing tool mates with an outer tool that can be made up in
a completion positioned inside of casing or in the casing itself,
or other tubular conduit. The inner tool actuates the outer tool by
application of hydraulic pressure through a pre-designed flow path.
The flow paths between the inner and outer tools must properly
match in order to actuate the outer tool. The inner tool also has a
large I.D. flow path that allows pumping of fluids or slurries
to/from the formation.
[0039] The inner tool can be run on work string (jointed pipe),
coiled tubing, as part of a completion or service tool hookup, with
wireline or electric-line tools with hydraulic capability, with
tractors with hydraulic capability or any other method that can
deliver hydraulic pressure the inner tool.
[0040] Many "fluid logic codes" can be generated between the inner
and outer tools by adjusting; 1) port size and spacing, 2) the
number of ports, 3) the length fluid reliefs, 4) the relative
position of the fluid reliefs to the ports, and 5) any other
related geometry. Theses adjustments can be made on both the inner
and outer tools to create unique fluid flow geometries and each
geometry can be coded as A, B, C, D, E, and on, for example.
[0041] If more than one outer tool is positioned downhole, this one
tool can be given its own fluid code so that only a pre-planned
geometry can activate it. If many tools are downhole, a single
fluid code can be used to selectively actuate all tools in a single
trip.
[0042] The outer tools are hydraulically designed, with a "balanced
piston", so that advertent or inadvertent application or existence
of hydraulic or hydrostatic pressure does not have an effect on the
tool. The outer tool stays inactive until the inner tool fluid code
matches the outer tool fluid code and pressure is applied through
or around the inner tool in order to shift the "balanced piston".
Once the "balanced piston" shifts, pressure from hydraulic fluid
acts as a trigger to begin actuating the outer tool. As an
alternative, the outer tool (CLT) can be used without the "balanced
piston" feature, if desired, and substituted with a non-balanced
piston or no piston at all. With the absence of a piston, fluid
pressure can communicate with any type of device that would actuate
a downhole tool.
[0043] The "fluid logic codes" (FLC) are analogous to a variety of
wireline locating or shifting profiles, i.e., only certain key
profiles engage and shift certain sleeve profiles. Or they (FLC)
could be analogous to the multitude of codes available with the new
technology called "RFID" HERE actuated tools. The Fluid Logic Tool
can route pressure against outer tool piston area to create
adequate force to reliably cause outer tool actuation. In contrast
to the RFID actuated tools, FLC is a non-electric approach with the
reliability of simply applying hydraulic pressure to the tool. Of
course, FLC technology could be used in conjunction with wireline
or RFID technology or other technologies for redundancy
purposes.
[0044] The outer tool has a hydraulic piston, device, or mechanism
that can supply a force needed to set or release packers, shift
sliding sleeves or frac sleeves both open and closed, open or close
flapper valves or ball valves or any type of motion actuated valve,
initiate the firing sequence of tubing conveyed (TCP) or casing
conveyed perforating guns (CCP) or perforating guns mounted in a
completion string, or other types of downhole tools.
[0045] The outer tool has a hydraulic piston that can move
mechanical devices, interface with hydraulic devices, interface
with electrical devices, optical devices, magnetic devices,
pneumatic devices, or others.
[0046] The outer tool can include a downhole positioning device or
locating device. This device is a tube attached to either the top
or bottom of the outer tool. The tube has one or more orifice
spaced lengthwise along the tube. As the inner tool moves through
the orifice while applying pump pressure from the surface, the
orifice cause changes in pressure and flow rate to create "Pressure
Blips". The orifice are sized and placed in the tube to develop a
preplanned pressure profile at the surface to tell the operator
where the tool is located. The orifice can be substituted with
changing diameters or other geometry to create pressure fluxuations
while pumping down the work string. The "orifice" creates a
calibration point from which to move the inner tool in order to
actuate an outer tool. Of course, the "orifice" is optional or any
number of orifice and orifice longitudinal spacing can be used in
the outer tool to help identify the outer tool and its position in
the well. Pressure and flow signatures of the "orifice" are
pre-determined by surface tests before the tools are run into the
well.
[0047] The inner tool can be used to "sweep" through the outer
tools to actuate the outer tools. In other words, the inner tool
can be moved, at a selected speed while accompanied by a selected
pump rate, through an outer tool to actuate the outer tool. In this
case, precise positioning of the inner tool to the outer tool is
not required. For example, if the inner tool is positioned below a
series of closed sliding sleeves, the inner tool may sweep upward
through the sliding sleeves to open all the sliding sleeves.
[0048] The inner tool may use any type of seal that engages
pressure wise, with the I.D. of the outer tool. For example, each
set of seals that are adjacent to the fluid flow ports may be
Labyrinth type seals, elastomer seals, non-elastomeric seals, or
any type of seal that directs fluid flow into the ports. The seal
can be as simple as two metal surfaces, the O.D. of the inner tool
and the I.D. of the outer tool, i.e., the clearance between the two
surfaces is sufficient to direct fluid into the outer tool. The
seal does not have to be a prefect seal to actuate the outer tool,
but must seal sufficiently to cause a reliable pressure
differential across the "balanced piston" in the outer tool to
actuate the outer tool. The Labyrinth seal, a series of metal
grooves, is the preferred seal due to its clearance with the I.D.
of the outer tool, its ability to restrict flow past it, and its
robustness.
[0049] The inner tool is a very versatile multi-purpose device
since it can be used to actuate single or multiple tools in single
or multiple zones without coming out of the hole. It provides
feedback to the surface as to its position in the well. It can be
used as a wash tool to clear debris away ahead of the tool while
fluid is circulated down the workstring. It can be used to place
fluids downhole or condition well fluids. It can be used to
acidize, place sand, place cement, or fracture formations. It can
be used to simply open or close a valve or it can be used in a more
complicated scheme of events such as setting a packer, opening a
sleeve, detonating a perforating gun, and closing a sleeve or any
variety of operations in any sequence. It can be used on coiled
tubing to service a live well. Other tools can be run with it,
i.e., it can be used with a pressure actuated positioning device to
hold it in place while fracing, pressure recording devices can be
attached, jarring devices can be attached, and so on.
BRIEF DESCRIPTION OF THE DRAWINGS
[0050] FIG. 1 is a longitudinal cross-sectional schematic view of
the present invention with the inner tool positioned inside of the
outer tool.
[0051] FIG. 2 is a view similar to that of FIG. 1 showing the
present invention with the inner tool in position to actuate a
sliding sleeve.
[0052] FIG. 3 is a view similar to that of FIGS. 1 and 2 with the
inner tool positioned in the outer tool for the purpose of
injecting fluid or slurry through the outer tool.
[0053] FIG. 4 is a similar view of the present invention with the
inner tool positioned to set or release a packer.
[0054] FIG. 5 is a similar schematic view of the present invention
with the inner tool positioned to actuate a flapper valve.
[0055] FIG. 6 is a similar schematic view of the present invention
with the inner tool positioned to actuate a perforating gun.
[0056] FIGS. 7a, 7b, and 7c is a similar schematic view of a two
zone completion hookup with multiple outer tools. The inner tool is
in close proximity so it can be moved to actuate each outer
tool.
[0057] FIGS. 8a, 8b, and 8c are similar schematic views of the
present invention with the inner tool positioned in a perforated
pipe and the inner tool is dressed with expandable metal pads that
have labyrinth seal grooves machined on the O.D. of the pads. The
pads are shown to be biased outward by either springs or hydraulic
pressure differential across the pads.
[0058] FIG. 9 is a similar schematic view of the present invention
with the inner tool positioned to actuate a series of TCP ("tubing
conveyed perforating") guns. The TCP guns are fired one at a time
by moving the inner tool relative to the outer tool. The outer tool
has a balanced piston that is secured sufficiently enough to
withstand shock or hydraulic forces of a detonating perforating
gun.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0059] FIG. 1 consists of a "Completion Fluid Logic Tool" (CLT,
also referred to as the outer tool) 1 with a "Service Fluid Logic
Tool" (SLT, also referred to as the inner tool) 2 positioned in the
inside bore 3 of the CLT 1. The SLT 2 and CLT 1 may take on several
forms as described later in the description. A Piston 4 is located
between an inner housing 5 and outer housing 6 with ports 7 and 8
and 9 adjacent to the piston 4. Based on the type or form of the
CLT, different porting arrangements may be used.
[0060] The objective of the porting arrangements, for example port
7 and port 8, is to allow tubing (internal) pressure 10 to act on
each side of the piston 4, on both sides of seals 11 and 12, in
order to keep the piston 4 in a pressure balanced, or near pressure
balanced, condition so that any increase in tubing pressure 10, for
any reason, does not cause the piston 4 to move. If the piston 4
does not move, the CLT 1 remains in a dormant state and does not
function. The piston 4 may be shear pinned 13, or locked in another
manner, until sufficient force, due to intentionally applied
pressure 10 with the SLT 2, causes the piston 4 to shear or
unlock.
[0061] Movement of the CLT 1 piston 4, via pressure 10 application
from the SLT 2, initiates activation of the CLT 1. The piston 4 may
be mechanically attached, via an activation sleeve 14 for example,
to a device to perform some downhole function, such as, opening and
closing a sliding sleeve, initiating the setting of a packer,
initiating a perforating gun, etc. Also, the piston 4 can be
attached to a device hydraulically, electrically, magnetically,
optically, pneumatically, etc., so when the piston 4 moves, the CLT
1 is activated.
[0062] If a configuration utilizing the activation sleeve 14 is
used, it may be necessary to have seals 15 and 16 that remains
pressure balanced, or near pressure balanced, through ports 8 and
9. If it is necessary to keep the piston closely pressure balanced,
then the SLT 2 could have an additional port, not shown, to
communicate with ports 8 and 9 simultaneously. It should also be
apparent that the piston could have the option of not being
pressure balanced in certain applications.
[0063] FIG. 1 also shows the SLT 2 with an internal flow path 16
and an adjacent flow path 17. Pressure 10 or 18 can be applied to
either of the flow paths 16 or 17. If pressure 10 is applied to
flow path 16, then fluid would enter port 8 and pressure would act
below the piston 4 biasing it upward and port 7 and flow path 17
would accept fluid from above the piston 4 to allow the piston to
move upward. Furthermore, if pressure 18 is applied to flow path
17, then fluid would enter port 7 and pressure 18 would act above
the piston 4 biasing it downward and port 8 and flow path 16 would
accept fluid from below the piston 4 to allow the piston to move
downward. Therefore, the up and down movement of piston 4 will
cause the activation sleeve 14 to simultaneously move up or down to
function a completion tool such as a sliding sleeve.
[0064] The longitudinal spacing, i.e. distances 19, 20, 21, 22, 23,
24, 25 but not limited to the number of distances, in conjunction
with diametric changes i.e. recesses 26, 27, 28, and 29 but not
limited to the number of diameters, can be altered or adjusted to
achieve different flow paths around the piston 4 or multiple
pistons, through flow paths 16, 17 or other flow paths, to actuate
one or more tools. Tools like packers or sliding sleeves can be
actuated selectively if desired. A single flow path geometry can be
used to actuate all tools. A flow path geometry can be selected so
only one tool can be actuated and any others can not be
actuated.
[0065] It should be understood that one SLT 2 can be built to
activate all CLT 1 devices located downhole, or one configuration
SLT 2, say configuration geometry "CS1", can be built to only
actuate a CLT 1 designed to match only a CLT with configuration
"CS1". Almost unlimited combinations of fluid patterns, or codes,
can be built by varying the distances or geometries mentioned
above. This is analogous, to some extent, to the wireline shifting
tool profiles where R, X, or XN profiles of shifting tools only
match R, X, or XN profiles in nipples, respectively.
[0066] FIG. 1 also shows seals arrangements on the SLT 2, i.e.,
seals 30, 31, and 32. These seals form a full or partial seal in
bore 3 on each side of flow paths 16 or 17 and on each side of
ports 7 and 8. These seals, or any combination of seals, can seal
around any combination of flow paths or porting arrangements. Flow
paths can be as simple as one port and one flow path or multiple
flow paths and ports. The recesses can be used to direct flow
around the tool as desired to achieve any flow logic desired.
[0067] FIG. 1 shows three sets of Labyrinth seals 30, 31, 32 on the
outside of the SLT 2. The Labyrinth type seal is a single groove or
multiple grooves on the O.D. of the SLT 2. The O.D. 33 of the SLT 2
can simply be a close tolerance fit in bore 3 to create a partial
seal or pressure drop in locations 34, 35, 36, and 37. The seal 33
can be of any type sufficient to allow a pressure buildup
sufficient to move the piston 4 in the CLT 1. In others words, the
seals 33 can leak and do not have to be perfect seals. If a
near-perfect or perfect seal 33 is desired, other types of seals
can be used such as elastomer or elastomers, plastics,
non-elastomers, expandable such as in FIG. 8, or retractable type
seals. Seals could be o-rings, v-rings, Chevron stacks, bonded
seals, molded seals, cup type seals, etc. It is preferable to use a
seal, such as a Labyrinth seal 33 that has clearance inside of the
CLT 1 and does not impart friction inside of the CLT 1 and does not
tend to stick inside of the CLT 1 and the type that can seal
multiple times without replacement. It is also desirable to have a
seal, like a Labyrinth seal 33 that will tolerate various types of
particles found down hole, i.e., sand, proppants, scale, etc. It is
also desirable to have a seal, like a Labyrinth seal 33, which is
not degradable by downhole temperature and various chemicals.
[0068] FIG. 1 shows the SLT 2 being conveyed into the well by work
string 38. Let it be understood that the CLT 1 can be part of the
casing string in the well or part of a completion or other tubular
string in the well, as shown in FIG. 7. An objective is to convey
the SLT 2 to sufficient proximity of the CLT 1 to activate the CLT
1.
[0069] Conveyance methods can be by use of a workstring 38 which
can be jointed pipe or coiled tubing. Also the SLT 2 can be
conveyed by electric line, wireline, or a tractor, all of which
would need special pressure generating tools that can pump fluid to
the SLT 2. Another option is to place a landing nipple above the
CLT 1 and the SLT 2 can be attached to a wireline or coiled tubing
conveyed lock or locator that positions it in the landing nipple.
The positioning would be such that the SLT 2 and CLT 1 fluid paths
line up. Once the fluid paths are lined up, pressure can be applied
down tubing or casing to activate a CLT 1.
[0070] FIG. 1 shows an orifice 39 and an orifice 40 located in
housing 41. The orifices are downhole locating devices. If fluid is
pumped through flow path 16 at a given rate and pressure through
the SLT 2 and then moved through the orifice 39 or 40, the orifice
will cause a pressure change, through 10 or 18, at the surface
because the orifice will allow flow of fluid. When seals 33 of the
SLT 2 enter the bore 42 of housing 41 the flow rate out of flow
path 16 will be restricted. When seals 33 allow fluid communication
with the orifice 40, or any combination of orifice, fluid flows
through the orifice and into annular space 43. Distance spacing 23
can be adjusted to allow a fluid return path through orifice 39 and
into annular space 18. A surface operator can detect one or more
pressure changes, based on the orifice geometric pattern, to tell
him where the SLT 2 is relative to the CLT 1. The pressure changes
can be pre-calibrated at the surface so the operator will know what
pressure change or sequence of pressure changes to expect for a
particular CLT 1. Pressure changes or patterns can be created by
changing orifice size, the number of orifices, replacing
conventional orifices with a series of bores and recesses (also
referred herein and in the claims as "orifices" or "orifice means")
or any scheme that will cause pressure changes downhole.
[0071] Once the desired location, or CLT 1, is found, the SLT 2 can
be moved up or down a given distance in order to position the SLT
seals 33 around the CLT ports 7, 8, or 9. Of course, tubing stretch
or elongation due to pressure application must be taken into
consideration at the anticipated applied pressure. If seals and
port spacing are long enough, tubing movement is less of an issue.
It should be noted that SLT 2 positioning may not be a critical
issue, because in some cases, the SLT 2 can be slowly moved through
the CLT 1 while applying pressure to activate the CLT 1.
[0072] Also shown in FIG. 1, is an optional pass-thru hole, or
holes, 117. The flow path created by hole (s)117 allows pressures
near 18 and 118 to equalize in cases where dead space 118 exists
below the SLT 2. The dead space may exist below SLT 2 when there is
no fluid communication with the formation or in the well above the
SLT 2. When fluid is pumped thru flow-path 10, fluid leakage may
occur past seals 31 and 32. Fluid leakage past seal 32 must flow
back up thru hole 117 when space 118 has no communication with its
surroundings. Hole 117 allows pressure 18 and 35 to stay balanced,
or near balanced, so an increase in pressure at either location 35
or 18, does not tend to force the SLT 2 up or down.
[0073] FIGS. 2 and 3 illustrate how an activation sleeve 14 of a
CLT 44 is activated by the SLT 2 to open a sliding sleeve 45 to
create a flow path 46 from the tubing side 10 to the annulus side
47. Applied pressure 16 builds pressure in chamber 52 to move
piston 4 upward into chamber 51 while fluid moves to low pressure
side 17. The hydraulic force on piston 4 opens the sliding sleeve
45. The annulus side 47 can communicate with an oil or gas
producing formation, or formations. This CLT 44 configuration can
be used to open or close sliding sleeves located adjacent or in
close proximity to in one or more formations, formations that are
either isolated or non-isolated, for either injection into a
formation, stimulating a formation, or producing from a formation.
Once the sleeve 45 is opened, the SLT 2 can be positioned so that
it can be used to fracture a selected zone as shown with flow path
46.
[0074] The casing 48 has holes or perforations 49 so that the flow
47 communicates with formation 50. An anchoring device can be
attached close to the SLT to hold it in position while fracturing
is taking place. The anchoring device for the SLT plays no part of
this invention. Any one of a number of conventional means known to
those skilled in the art may be utilized.
[0075] As shown in FIG. 2, the sliding sleeve 45 may be closed when
pressure direction is reversed in the SLT 2. Pressure is increased
at port 17 which moves piston 4 down into chamber 52 which closes
the sliding sleeve 45.
[0076] FIG. 4 illustrates the configuration of a CLT 53 that
interfaces with a packer 54 in order to set, or release, the packer
54. Pressure 17 is applied to stroke piston 4 downward the compress
and set the packer although pressure 10 could also be used if the
SLT 2 were moved upward to change the porting arrangement. In this
schematic the orifice locator has been moved to the top of the
completion tool and CLT. Orifice 55 and 57 are located in tubular
housing 56. This drawing is for illustration only since the
apparatus for setting the packer and the packer require more
detail. It should be noted that packers require setting loads in
the range of 50,000 pounds to fully set and the SLT 2 has hydraulic
pressure capability to generate these forces when working on piston
4 areas. In order to get additional force it is possible to attach
two or more pistons (similar to 4) and simultaneously add more
seals and ports to the SLT 2 geometry.
[0077] FIG. 5 illustrates the configuration of a CLT 58. Fluid is
pumped through path 10 to move sleeve 60 that allows a flapper
valve 59 to close when sleeve 60 moves above the flapper 61. Of
course, the flapper valve design can be modified so that the SLT
(2) can both open and close a flapper, or a ball valve, or any
other type of valve. The flow path configuration between the CLT
and SLT is such that a valve can be opened and closed in a single
trip into the well. It is also possible to build one flow
configuration that opens a valve and a second configuration that
closes a valve.
[0078] FIG. 6 illustrates a CLT 62 configuration for activating a
Tubing Conveyed or Casing Conveyed perforating gun 63. The SLT 2
can be used in vertical or horizontal wells and can selectively
detonate guns at any position in the well. In this configuration,
the geometry around the piston changes. The piston 64 is no longer
attached to an activation sleeve, but instead, has an added seal
65. Seals 65 and 66 prevent pressure from entering port 67 until
the piston 64 moves up or down to uncover port 67. Once port 67 is
uncovered, pressure 10 or 18 can be applied through the SLT 2,
through port 67, and into a timer or firing mechanism 68 to
initiate firing of the perforating guns 63. Of course firing
mechanism can be located anywhere in the perforating gun.
[0079] FIG. 6 illustrates that the piston 4 (of FIG. 1) or 64 can
be in several forms. The piston, rather than communicating with a
port 67, can act as a locking mechanism, for example. When the
piston moves, it can cam out from under a collet, or set of keys,
or a switch, or some other device that is directly or indirectly
connected to an activating device which eventually activates some
type of downhole tool, or CLT. Once again, the option exists to
have no piston at all so the SLT communicates directly with some
type of device. Also, it should be apparent that this piston
arrangement is not limited to perforating guns. Also shown in FIG.
6 is the orifice location finder 69 which is optional and may be
located anywhere relative to the CLT 62.
[0080] FIGS. 7a, 7b, and 7c illustrates a possible completion
hookup 70 inside of casing 71 in formation 72. The hookup 70
consists of multiple CLT's 73,74,75,76, 77, and 78 and more than
one zone of interest, zones 79 and 80. The hookup shows two zones
of tools with each zone having a CLT actuated packer 81, sliding
sleeve 82, and perforating gun 83. A SLT 2 attached to workstring
38 can be moved from position to position to activate each CLT as
desired. Those familiar with the state-of-the-art can readily see
that different types of CLT's can be placed in any position and as
many times as desired.
[0081] FIGS. 8a, 8b, and 8c show the SLT 84 positioned inside of a
tubular 86 and the tubular has holes 87 which may be perforations
that connect to a formation or machined holes that communicate with
a CLT.
[0082] FIG. 8A illustrates the SLT 84 with expandable labyrinth
seals 85 rather than fixed O.D. labyrinth seals as seen in the SLT
2 (of FIG. 1). The labyrinth seals 85 are one or more grooves
placed on the O.D. of the expandable pads 88. Although, the option
exists where the pads 88 have no labyrinth grooves. In this figure,
the pads 88 are biased outward by use of springs 89 under the pads
to force contact, or near contact, with the I.D. of the tubular 86.
The pads 88 approach or achieve a 360 degree contact around the
I.D. of the tubular 86. FIG. 8B shows grooves 95 between two or
more sections of pads 96 and 97. The pads 96 and 97 are blocked by
off-sets 93 and 94 built into the sides of the pads 96 and 97. The
off-sets 93 and 94 restrict fluid movement between the pads 96 and
97 when the pads are expanded to meet the I.D. of the tubular 86.
Each section of pad has a set of off-sets. The pads 88 are retained
to the SLT 84 by lips 90 on the pad 88 protruding under mating lips
91 on housing 92. The components of the pads and the body of the
SLT 84 restrict fluid flow past the pads thereby directing fluid
through flow path 16 and into CLT holes or perforations 87 in the
tubular 86.
[0083] FIG. 8B illustrates the SLT 84 in a similar manner as FIG.
8A except the pads 88 are biased outward hydraulically with
pressure from hole 16 through ports 98 and into chamber 99 located
under each set of expandable pads 96 and 97.
[0084] FIG. 8C illustrates the SLT 84 with the pads 96 and 97 fully
expanded against the I.D. 100 of the tubular 86 due to spring
loading under the pads. The hydraulic version would be similarly
expanded since pressure at 98 is higher than pressure at 101. In
either case, the expanded pads direct fluid, or slurry, into and
through the tubular holes 87.
[0085] FIG. 9 illustrates a downhole tool hookup for perforating
one or more zones with a Tubing Conveyed Perforating Gun (TCP). One
or more CLT's, 102 and 103 are positioned above one or more TCP
guns 111 and 112. When the SLT 2 is positioned inside the CLT 102,
pressure at 16 works on piston 104 and shears screw 106, or locking
device, to allow fluid from 16 to communicate with control line
107. Control line 107 either hydraulically, electrically,
optically, etc. communicates with firing head 110 and triggers
firing head 110 to detonate TCP gun 112. It may be desirable to
detonate the lowermost guns 112 first to assure that the control
line 107 is not damaged by detonation of guns 111. If a control
line 107 is damaged, it is possible to shift or bias piston 104
back to the closed position to shut off fluid communication through
the control line 107, if the control is hydraulic. Shear screws
106, or locks, are of sufficient strength to prevent a piston 104,
from another CLT 103, from moving due to TCP shock loads from TCP
gun detonation 112. After TCP gun 112 is detonated the SLT2 may be
moved to CLT 103. Pressure applied from 16 moves piston 105 so that
communication is achieved through control line 108 which activates
firing head 109 and detonates TCP gun 111. Multiple CLT's can
communicate with multiple TCP guns in any manner, i.e., CLT 102 can
only fire gun 111, CLT 102 can only fire gun 112, CLT 102 can
simultaneously fire both guns 111 and 112, CLT 103 can do the same
as CLT 102, or both CLT 102 and CLT 103 can both fire a gun or guns
to provide a means to have a backup firing method. Firing of the
guns 111 and 112 will perforate casing 113 and communicate with
formations 114 and 115. Therefore, any combination of CLT's and
guns can be used to fire guns selectively, simultaneously, or
provide redundancy in the firing system. Also, the SLT 2 may be
moved from the bottom up or the top down to fire guns in any
sequence.
[0086] Also shown in FIG. 6 is the orifice location finder 69 which
is optional and may be located anywhere relative to the CLT 62.
[0087] The TCP guns 111 and 112, or more, can be spaced out through
multiple zones 114 and 115, or more, to selectively perforate zones
without the need to move the workstring 116. Also the workstring 38
can be moved to reposition guns relative to each zone before
detonation without pulling the SLT 2 out of the well by use of
jointed pipe at the surface.
[0088] A dual string handling system can be used on the rig to move
the tubing conveyed guns up the hole along with the SLT work string
38 as joints are removed from workstring 116.
DESCRIPTION OF OPERATION
[0089] A single or series of Completion Logic Tools (CLT's), aka
the completion, may be positioned in well casing, as in FIG. 7a,
7b, or 7c, or in open hole, or may be cemented in open hole. The
objective is to activate any type of CLT, examples are shown in
FIG. 2, 3, 4, 5, 6, 7, 8 or 9, by conveying into the well a service
Fluid Logic Tool (SLT) by anyone of the above mentioned conveying
methods or by running the SLT in place with some other part of the
completion and making a connection at a later time. A particular
SLT may be run that only activates a particular type of CLT or
series of CLT's. A particular SLT may be run to activate all
CLT's.
[0090] A typical operational sequence may be conveying the SLT to
the bottom of the completion. Once the SLT is below the lowermost
CLT, fluid is circulated down the workstring and into the SLT flow
path 10, see FIG. 1. Flow rate and pressure are maintained while
moving the workstring upward to activate the first CLT. As an
option, when the SLT enters a restriction 42 between orifice 39 and
40, see FIG. 1, a pressure change and flow rate change will occur
signaling the operator of the position of the SLT relative to the
inside of the CLT. The presence of the orifice 39 or 40 will
provide increased flow, at a rate predetermined by surface tests.
Also, the longitudinal spacing between orifice and number of
orifice will provide a "finger print" that identifies the CLT to be
activated. Once it is verified that the SLT is in the proper CLT,
the SLT is moved slowly upward until the porting arrangements
between the CLT and SLT sufficiently match to create a flow path to
the piston 4, FIG. 1, of the CLT.
[0091] As shown in FIG. 1, the fluid will enter port 8, act on the
piston 4, shear and move the piston while fluid above the piston
exits port 7 allowing the piston to move and begin the actuation
process of the CLT. Of course the flow path can be reversed to
enter flow Path 7 and exit port 8 to move the piston back the other
direction if it may be desired to de-activate or re-cock a CLT. The
pressure required to move the piston will vary depending on the
piston area, frictional forces, shear screw value, etc. The piston
can be designed to completely move across port 7 to create a flow
path from port 8 to 7 to achieve return fluid up through flow path
17 so that returns can be sensed at the surface. The return fluid
can act as a tell-tale that the piston has shifted.
[0092] It should be understood that application of surface pressure
into the workstring may cause the workstring to elongate therefore
longitudinal spacing of the ports may have to be lengthened, or
adjusted, to compensate for tubing movement. Or it may be necessary
move the workstring up or down to compensate for tubing movement
due to an increase in pressure inside the workstring.
[0093] Another operational sequence may be to "sweep" the SLT
upward through the CLT or CLT's. In this case, the workstring is
slowly moved upward while pumping down the workstring at a constant
pressure and flow rate. Pressure is maintained high enough to shift
the pistons and activate the CLT's. The spacing of the ports is
such that pressure is applied long enough to the CLT's to fully
activate the CLT's while the workstring continues its motion
upward. Movement of the SLT can be either up or down, if
desired.
[0094] FIGS. 7a, 7b, and 7c show a typical completion in a zone
with a packer, a sliding sleeve, and a perforating gun. An
operational sequence may be to move the SLT to set the CLT packer,
then open the CLT sliding sleeve, then detonate the CLT perforating
gun, then move the SLT to straddle the sliding sleeve, then pump a
frac job into the formation, next reverse out, and last, close the
sliding sleeve. In this case, not shown, a sand control screen can
be positioned in close proximity to the perforating guns. The sand
control screen may be shut off with sliding sleeves to prevent
production flow and reopened at a later time.
[0095] To better understand the operation of the SLT in a CLT it is
beneficial to explain how to achieve pressure and flow rate
necessary to activate a CLT. Fluid can be pumped down the
workstring in terms of gallons per minute (GPM). The GPM is based
on the typical size of fluid pumps on rigs. Typically most rigs
have 5 BPM mud pumps so the objective is to generate at least 3000
PSI at the CLT using a mud pump. Typically packers are set or
activated with pressures in the range from 2500 PSI to 4000 PSI.
About 3000 PSI can be achieved with 105 gal/min. With 42 gallons in
a barrel, a pump rate of 2.5 BPM is needed to achieve 3000 PSI.
Further testing should show that pump rates higher than 2.5 BPM
will generate pressures up to 4000 PSI with 1/4'' diameter orifice.
This is static pressure at the tool even though fluid is leaking
around the O.D. of the SLT. In some cases, it may be necessary to
calculate surface applied pressure in combination with well
hydrostatic pressures to determine actual pressure at the tool. For
salt water, the weight of the fluid is 0.5 PSI/foot, so in a 10,000
foot well hydrostatic pressure could be 5,000 PSI. Depending on the
fluid position in the tubing and annulus, hydrostatic pressure may
have to be added or subtracted from the surface applied pressure to
get actual pressure at the CLT.
[0096] Orifice size communicating with the Piston in the CLT needs
to be of sufficient size to supply fluid volume necessary to move
the piston up or down. The smaller the orifice, the longer it will
take the piston to move due to volume displacement. A 1/4'' size
orifice was used in a test because that is a typical size of
orifice used in hydraulic set packers when the packers are set by
application of tubing pressure. Flow rate formulae, such as Flow
Rate=Orifice Area.times.Velocity, and other formulae, can be used
to calculate the flow rate required to make a piston move within a
specified time range.
[0097] Of course the piston moves when pressure is applied to a
specific area on the piston, and the piston can be shear-pinned to
shear at a specified pressure. This is important if the SLT is
sweeping through the CLT. Seal spacing is lengthened or shortened
based on the speed the SLT is moving through the CLT and also based
on tubing stretch calculations.
[0098] Seal spacing may be increased to compensate for tubing
elongation when pressure is applied to the tubing. A simple
formulae .DELTA.P=12Et.DELTA.L/[RL(0.5-v)], from "Roark's Formulas
For Stress and Strain", seventh addition, is used to calculate the
workstring movement with applied surface pressure.
[0099] If the SLT is run un-anchored, i.e., tubing movement can
occur, then the seal spacing on each side of the port in the SLT
may be increased and the bore length on each side of the receiving
port in the CLT may be increased, to assure that the SLT properly
communicates with the CLT. If the SLT has an anchoring device on
the workstring, then the seal and bore spacing can be reduced since
very little tubing movement will occur at the SLT when pressure is
applied.
[0100] Referring to FIG. 1, if pumping down the workstring, it
would be desired that the input flow area at point 16 must always
be greater than the flow area at orifice 8+the annular flow area
around the SLT and inside the CLT at seal 31, if seal point 31 is a
leaking type seal. If multiple seal location are leaking type
seals, i.e., seals 30, 31, and 32, then these flow areas plus the
orifice flow areas must be greater than the input flow area at
point 28. If pumping down the annulus at point 18, then input flow
area thru port 17 must be greater than the orifice 7 flow area+the
annular flow area past any seals or restrictions around the
SLT.
[0101] In summary, in order to build pressure on the piston 4, the
input flow areas must provide enough flow to achieve an adequate
pressure increase at the piston, or activating device, in order to
activate a CLT. For example, if the piston 4, or activating device,
requires 3,000 PSI to begin the activation process of a CLT, then
input flow area must be great enough to achieve this pressure
increase while also giving up fluid at any leak path locations
around the SLT. Of course, if the seals 30, 31, and 32 are
non-leaking type seals then the fluid input requirements at point
16 may be reduced in order to activate a CLT device.
[0102] The above formulae may be expanded if additional orifice
means at point 8 are present. For example, if there are three
pistons programmed into the fluid path geometry, each having an
orifice arrangement on each side of the pistons. Each piston
actuates a different downhole device at a single position of the
SLT. The input flow area at 28, must then be great enough to supply
multiple orifice and multiple leaking seal paths.
[0103] The above also applies to the position finding orifice 39
and 40. The input flow area at location 28 needs to be of
sufficient size to achieve a pressure change at the surface when
the SLT passes through bore 42 and crosses orifice 39 or 40.
Furthermore, the flow area through balance port 117, should be of
sufficient size to balance pressure above and below the SLT, if the
SLT is not anchored in position. Ideally flow area 117 should be
greater than input flow area 28, but may not be absolutely
necessary.
[0104] The above discussion primarily relates to activating a CLT
with a SLT. Referring to FIG. 3, where the SLT moves to a gravel
packing, acidizing, or frac position, in this case inside of a
sliding sleeve 45 (FIG. 2), flow area 10 must be of sufficient size
to handle to require fluid volume to achieve stimulation of the
well formation. For example, the flow area I.D. at 10 may have to
have a 1.5'' I.D. to allow a pump rate of 15 BPM through the tool
and into the formation 50. Of course, the flow area can be adjusted
to the size needed to achieve the required flow rate based on the
available room inside of the CLT. It should also be understood that
a SLT can be custom designed to apply pressure to the inside of any
type of completion tool other than a CLT, if the completion tool
geometry can be matched between the SLT and the completion
tool.
[0105] For those who understand the art of completing wells, it
should be apparent that many combinations of CLT's can be created
and that the SLT has great flexibility to operate in deferent types
of hookups or completions.
[0106] The invention being thus described, it will be obvious that
the same may be varied in many ways. Such variations are not to be
regarded as a departure from the spirit and scope of the invention,
and all such are intended to be included within the scope of the
non-limiting claims.
* * * * *