TUBING PRESSURE OPERATED DOWNHOLE FLUID FLOW CONTROL SYSTEM
CROSS-REFERENCE TO RELATED APPLICATIONS
None.
FIELD OF INVENTION
[0001] This invention relates, in general, to equipment utilized in conjunction with
operations performed in subterranean wells and, in particular, to a downhole fluid flow control
system and method utilizing tubing pressure to actuate flow control devices downhole.
BACKGROUND OF INVENTION
[0002] Without limiting the scope of the present invention, its background will be
described with reference to producing fluid from a hydrocarbon bearing subterranean formation,
as an example. During the completion of a well that traverses a hydrocarbon bearing
subterranean formation, production tubing and various completion equipment are installed in the
well to enable safe and efficient production of the formation fluids. For example, to prevent the
production of particulate material from an unconsolidated or loosely consolidated subterranean
formation, certain completions include one or more sand control screen assemblies positioned
proximate the desired production interval or intervals. In other completions, to control the flow
rate of production fluids into the production tubing, it is common practice to install one or more
flow control devices within the tubing string.
[0003] Attempts have been made to utilize fluid flow control devices within completions
requiring sand control. For example, in certain sand control screen assemblies, after production
fluids flow through the filter medium, the fluids are directed into a flow control section. The flow
control section may include one or more flow control components such as flow tubes, nozzles,
labyrinths or the like. Typically, the production flow resistance or flow rate through flow control
screens is fixed prior to installation.
[0004] It has been found, however, that due to changes in formation pressure and
changes in formation fluid composition over the life of the well, it may be desirable to adjust the
flow control characteristics of the inflow control devices. In addition, for certain completions, it
would be desirable to adjust the flow control characteristics of the inflow control devices without
the requirement for well intervention.
[0005] Accordingly, a need has arisen for a downhole fluid flow control system that is
operable to control the inflow of formation fluids. In addition, a need has arisen for such
downhole inflow control devices that may be incorporated into a flow control screen. Further, a
need has arisen for such downhole inflow control devices that are operable to adjust flow
characteristics without the requirement for well intervention as the production profile of the well
changes over time.
SUMMARY OF THE INVENTION
[0006] A downhole flow control system utilizes a tubing pressure operated valve to
selectively open and close fluid flow across the system. The tubing pressure operated valve
includes a piston responsive to tubing pressure, and a valve element responsive to piston
movement. The valve element can be moved rotationally, longitudinally, or both, in response to
the piston movement. The valve is movable between a closed and at least one open position. The
piston and valve elements can be releasably attachable, such as by a one-way ratchet. The valve
element can be a rotating valve operable by a J-slot mechanism to rotate to multiple positions in
response to movement of the piston element. Further elements of the device can include
temporary holding mechanisms, such as a collet assembly, shear pins and the like. The rotatable
valve element can rotate endlessly, allowing repeated opening and closing of the valve device.
The device is responsive to tubing pressure and does not require well intervention. The device
can be used in conjunction with a sand control screen assembly, additional flow control
assemblies, etc.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] For a more complete understanding of the features and advantages of the present
invention, reference is now made to the detailed description of the invention along with the
accompanying Figures in which corresponding numerals in the different Figures refer to
corresponding parts and in which:
[0008] Figure 1 is a schematic illustration of a well system operating a plurality of
downhole inflow control devices according to an embodiment of the present invention;
[0009] Figures 2A-2B are quarter sectional views of successive axial sections of a
downhole inflow control devices embodied in a flow control screen of the present invention in a
first configuration;
[0010] Figures 3A-E are schematic, cross-sectional, partial views of an exemplary
embodiment of an inflow control device according to an aspect of the invention; and
[0011] Figures 4A-C are schematic, cross-sectional, partial views of an exemplary
embodiment of an inflow control device according to an aspect of the invention.
[0012] It should be understood by those skilled in the art that the use of directional terms
such as above, below, upper, lower, upward, downward and the like are used in relation to the
illustrative embodiments as they are depicted in the Figures, the upward direction being toward
the top of the corresponding Figure and the downward direction being toward the bottom of the
corresponding Figure. Where this is not the case and a term is being used to indicate a required
orientation, the Specification will state or make such clear.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0013] While the making and using of various embodiments of the present invention are
discussed in detail below, it should be appreciated that the present invention provides many
applicable inventive concepts which can be embodied in a wide variety of specific contexts. The
specific embodiments discussed herein are merely illustrative of specific ways to make and use
the invention, and do not delimit the scope of the present invention.
[0014] Referring to Figure 1, a well system is depicted having a plurality of downhole
fluid flow control systems positioned in flow control screens embodying principles of the present
invention, generally designated 10. In the illustrated embodiment, a wellbore 12 extends through
the various earth strata. Wellbore 12 has a substantially vertical section 14, the upper portion of
which has cemented therein a casing string 16. Wellbore 12 also has a substantially horizontal
section 18 that extends through a hydrocarbon bearing subterranean formation 20. As illustrated,
substantially horizontal section 18 of wellbore 12 is open hole.
[0015] Positioned within wellbore 12 and extending from the surface is a tubing string
22. Tubing string 22 provides a conduit for formation fluids to travel from formation 20 to the
surface and for injection fluids to travel from the surface to formation 20. At its lower end,
tubing string 22 is coupled to a completions string that has been installed in wellbore 12 and
divides the completion interval into various production intervals adjacent to formation 20. The
completion string includes a plurality of flow control screens 24, each of which is positioned
between a pair of annular barriers depicted as packers 26 that provides a fluid seal between the
completion string and wellbore 12, thereby defining the production intervals. In the illustrated
embodiment, flow control screens 24 serve the function of filtering particulate matter out of the
production fluid stream. Each flow control screen 24 also has a flow control section that is
operable to control fluid flow therethrough. For example, the flow control sections may be
operable to control flow of a production fluid stream during the production phase of well
operations. Alternatively or additionally, the flow control sections may be operable to control the
flow of an injection fluid stream during a treatment phase of well operations. As explained in
greater detail below, the flow control sections are operable to control the inflow of production
fluids without the requirement for well intervention over the life of the well as the formation
pressure decreases to maximize production of a desired fluid such as oil. Additionally, the
system utilizes the operator-controlled, tubing-pressure actuated inflow control devices as
disclosed herein. That is, the system can use operator controlled inflow control devices alone or
in conjunction with autonomous flow control systems. Where the two are used in conjunction,
the flow characteristics of the production string will autonomously change in response to
changes in fluid characteristics, but the operator can still open, close, and regulate inflow using
tubing pressure changes.
[0016] Even though Figure 1 depicts the flow control screens of the present invention in
an open hole environment, it should be understood by those skilled in the art that the present
invention is equally well suited for use in cased wells. Also, even though Figure 1 depicts one
flow control screen in each production interval, it should be understood by those skilled in the art
that any number of flow control screens of the present invention may be deployed within a
production interval or within a completion interval that does not include production intervals
without departing from the principles of the present invention. In addition, even though Figure 1
depicts the flow control screens of the present invention in a horizontal section of the wellbore, it
should be understood by those skilled in the art that the present invention is equally well suited
for use in wells having other directional configurations including vertical wells, deviated wells,
slanted wells, multilateral wells and the like. Accordingly, it should be understood by those
skilled in the art that the use of directional terms such as above, below, upper, lower, upward,
downward, left, right, uphole, downhole and the like are used in relation to the illustrative
embodiments as they are depicted in the Figures, the upward direction being toward the top of
the corresponding Figure and the downward direction being toward the bottom of the
corresponding Figure, the uphole direction being toward the surface of the well and the
downhole direction being toward the toe of the well. Further, even though Figure 1 depicts the
operator controlled inflow control devices in a flow control screen, it should be understood by
those skilled in the art that the operator controlled inflow control devices of the present invention
need not be associated with a flow control screen or be part of a completion string. For example,
the operator controlled inflow control devices may be operably disposed within a drill string for
drill stem testing, within an injection string for well treatment, etc.
[0017] Referring next to Figures 2A-2B, therein is depicted successive axial sections of a
flow control screen according to the present invention that is representatively illustrated and
generally designated 100. Flow control screen 100 may be suitably coupled to other similar flow
control screens, production packers, locating nipples, production tubulars or other downhole
tools to form a completions string as described above. Flow control screen 100 includes a base
pipe 102 that has a blank pipe section 104 and a perforated section 106 including a plurality of
production ports 108 and a plurality of bypass ports 110. Positioned 30 around an uphole portion
of blank pipe section 104 is a screen element or filter medium 112, such as a wire wrap screen, a
woven wire mesh screen, a pre-packed screen or the like, with or without an outer shroud
positioned therearound, designed to allow fluids to flow therethrough but prevent particulate
matter of a predetermined size from flowing therethrough. It will be understood, however, by
those skilled in the art that the present invention does not need to have a filter medium associated
therewith, accordingly, the exact design of the filter medium is not critical to the present
invention.
[0018] Positioned downhole of filter medium 112 is a screen interface housing 114 that
forms an annulus 116 with base pipe 102. Securably connected to the downhole end of screen
interface housing 114 is a flow control housing 118 that forms an annulus 120 with base pipe
102. At its downhole end, flow control housing 118 is securably connected to a support assembly
122 which is securably coupled to base pipe 102. The various connections of the components of
flow control screen 100 may be made in any suitable fashion including 10 welding, threading
and the like as well as through the use of fasteners such as pins, set screws and the like.
[0019] Positioned within flow control housing 118, flow control screen 100 has a flow
control section including a plurality of flow control components 124 and a bypass section 126. In
the illustrated embodiment, flow control components 124 are circumferentially distributed about
base pipe 102 at one hundred and twenty degree intervals such that three flow control
components 124 are provided, as best seen in Figure 3 wherein flow control housing 118 has
been removed. Even though a particular arrangement of flow control components 124 has been
described, it should be understood by those skilled in the art that other numbers and
arrangements of flow control components 124 may be used. For example, either a greater or
lesser number of circumferentially distributed flow control components 124 at uniform or non
uniform intervals may be used. Additionally or alternatively, flow control components 124 may
be longitudinally distributed along base pipe 102. As illustrated, flow control components 124
are each formed from an inner flow control element 128 and an outer flow control element 130,
the outer flow control element being removed 25 from one of the flow control components 124
in Figure 3 to aid in the description of the present invention. Flow control components 124 each
have a fluid flow path 132 including a pair of fluid ports 134, a vortex chamber 136 and a port
140. In addition, flow control components 124 have a plurality of fluid guides 142 in vortex
chambers 136.
[0020] Flow control components 124 may be operable to control the flow of fluid in
either direction therethrough and may have directional dependent flow resistance wherein
production fluids may experience a greater pressure drop when passing through flow control
components 124 than do injection fluids. For example, during the treatment phase of well
operations, a treatment fluid may be pumped downhole from the surface in the interior
passageway 144 of base pipe 102. The treatment fluid then enters the flow control components
124 through ports 140 and passes through vortex chambers 136 where the desired flow resistance
is applied to the fluid flow achieving the desired pressure drop and flow rate therethrough. In the
illustrated example, the treatment fluids entering vortex chamber 136 primarily travel in a radial
direction within vortex chamber 136 before exiting through fluid ports 134 with little spiraling
within vortex chamber 136 and without experiencing the associated frictional and centrifugal
losses. Consequently, injection fluids passing through flow control components 124 encounter
little resistance and pass therethrough relatively unimpeded enabling a much higher flow rate
with significantly less pressure drop than in a production scenario. The fluid then travels into
annular region 120 between base pipe 102 and flow control housing 118 before entering annulus
116 and passing through filter medium 112 for injection into the surrounding formation.
[0021] Likewise, during the production phase of well operations, fluid flows from the
formation into the production tubing through fluid flow control system 100. The production
fluid, after being filtered by filter medium 112, if present, flows into annulus 116. The fluid then
travels into annular region 120 between base pipe 102 and flow control housing 118 before
entering the flow control section. The fluid then enters fluid ports 134 of flow control
components 124 and passes through vortex chambers 136 where the desired flow resistance is
applied to the fluid flow achieving the desired pressure drop and flow rate therethrough. In the
illustrated example, the production fluids entering vortex chamber 136 travel primarily in a
tangentially direction and will spiral around vortex chamber 136 with the aid of fluid guides 142
before eventually exiting through ports 140. Fluid spiraling around vortex chamber 136 will
suffer from frictional losses. Further, the tangential velocity produces centrifugal force that
impedes radial flow. Consequently, production fluids passing through flow control components
124 encounter significant resistance. Thereafter, the fluid is discharged through openings 108 to
the interior passageway 144 of base pipe 102 for production to the surface. Even though a
particular flow control components 124 has been depicted and described, those skilled in the art
will recognize that other flow control components having alternate designs may be used without
departing from the principles of the present invention including, but not limited to, inflow control
devices, fluidic devices, venturi devices, fluid diodes and the like.
[0022] For further disclosure regarding sand control screens, flow control components,
and their use, see, for example, the international patent application PCT/US20 12/27463, which is
hereby incorporated herein in its entirety for all purposes.
[0023] In the illustrated embodiment, bypass section 126 includes a piston depicted as an
annular sliding sleeve 142 that is slidably and sealingly positioned in an annular region 145
between support assembly 122 and base pipe 102. As illustrated, sliding sleeve 142 includes
three outer seals 146, 148, 150 that sealingly engage an interior surface of support assembly 122
and three inner seals 152, 154, 156 that sealingly engage an exterior surface of base pipe 102.
Sliding sleeve 142 also includes one or more bypass ports 158 that extend radially through
sliding sleeve 142. Bypass ports 158 may be circumferentially distributed around sliding sleeve
142 and may be circumferentially aligned with one or more of bypass ports 110 of base pipe 102.
Bypass ports 158 are positioned between outer seals 148, 150 and between inner seals 154, 156.
Also disposed within annular region 145 is a mechanical biasing element depicted as a wave
spring 160. Even though a particular mechanical biasing element is depicted, those skilled in the
art will recognize that other mechanical biasing elements such as a spiral would compression
spring may alternatively be used with departing from the principles of the present invention.
Support assembly 122 forms an annulus 162 with flow control housing 118. Support assembly
122 includes a plurality of operating ports 164 that may be circumferentially distributed around
support assembly 122 and a plurality of bypass ports 166 that may be circumferentially
distributed around support assembly 122 and may be circumferentially aligned with bypass ports
158 of sliding sleeve 142.
[0024] The operation of bypass section 126 will now be described. Early in the life of
the well, formation fluids enter the wellbore at the various production intervals at a relatively
high pressure. As described above, flow control components 124 are used to control the pressure
and flow rate of the fluids entering the completion string. At the same time, the fluid pressure
from the borehole surrounding flow control screen 100 generated by formation fluids enters
annulus 162 and pass through operating ports 164 to provide a pressure signal that acts on sliding
sleeve 142 and compresses spring 160, as best seen in Figure 2B. In this operating configuration,
bypass ports 158 of sliding sleeve 142 are not in fluid communication with bypass ports 166 of
support assembly 122 or bypass ports 110 of base pipe 102. This is considered to be the valve
closed position of sliding sleeve 142, which prevents production fluid flow therethrough. As long
as the formation pressure (also referred to herein as annulus pressure or wellbore annulus
pressure) is sufficient to overcome the bias force of spring 160, sliding sleeve 142 will remain in
the closed position. As formation pressure declines, a change occurs in the pressure signal that
acts on sliding sleeve 142. When the formation pressure reaches a predetermined level, wherein
the pressure signal is no longer sufficient to overcome the bias force of spring 160, sliding sleeve
142 will autonomously shift from the valve closed position to the valve open position. In this
operating configuration, bypass ports 158 of sliding sleeve 142 are in fluid communication with
bypass ports 166 of support assembly 122 and bypass ports 110 of base pipe 102. Formation
fluids will now flow from the annulus surrounding flow control screen 100 to the interior 144 of
flow control screen 100 predominantly through bypass section 126. In this configuration, the
resistance to flow is significantly reduced as the formation fluids will substantially bypass the
high resistance through flow control components 124. In this manner, the flow control
characteristics of flow control screen 100 can be autonomously adjusted to enable enhanced
production due to a reduction in the pressure drop experience by the formation fluids entering the
completion string.
[0025] While autonomous flow control systems provide a critical function in controlling
production fluids, it is still desirable to maintain a method and devices for operator-controlled
flow control. For example, regardless of the age of the well, the changes in formation pressure,
etc., the operator may elect to increase, decrease, cease or begin fluid flow (i.e., production
flow). Further, operator control without well intervention is desirable to save time and cost.
Consequently, herein presented are embodiments of inflow control devices, which can be used
alone or in conjunction with the autonomous flow control components, and that are operator
controlled. Where the inflow control devices are used in conjunction with autonomous flow
control components, alterations in design may be necessary, such as placement of the
autonomous elements upstream or downstream from the operator-controlled valves, use of
relatively higher tubing pressures or flow rates to operate the operator-controlled valves, etc. In
the embodiments disclosed, the operator controls the inflow control devices by increasing,
decreasing, or cycling tubing pressures.
[0026] Figures 3A-E are schematic cross-sectional illustrations of an exemplary
embodiment, generally designated as 200, of an inflow control device according to an aspect of
the invention utilizing a stepped-flow restriction mechanism in progressive positions during use.
The illustrated inflow control device is positioned about a base pipe 202 having production ports
204. Alternate numbers and arrangements of ports can be used. A screen assembly, uphole and to
the left (not shown), as is known in the art and described elsewhere herein, and appropriate flow
passageways, provide fluid communication between the wellbore annulus and the device,
especially to the inflow control device annulus 210 defined between the device housing 212 and
support assembly 216.
[0027] At its downhole end, inflow control device housing 212 is attached to a support
assembly 216 which is attached to the base pipe 202, typically by welding. The support assembly
216, at generally tubular portion 218, defines an annulus 210 between the support assembly and
the housing 212.
[0028] The inflow control device 200 includes a slidable piston 222 positioned in a valve
annulus 214 defined between the tubular portion 218 of the support assembly 216 and the base
pipe 202. The piston 222 can be an annular sliding sleeve, slidably and sealingly positioned in
the valve annulus 214, with a plurality of check valve assemblies and ports positioned therein.
Alternately, a plurality of the devices 200 can be positioned circumferentially about the base
pipe, with each device having a separate piston assembly. As illustrated, the piston 222 includes
seals 226 that sealingly engage an interior surface of support assembly 216 and an exterior
surface of sliding flow restriction mechanism 224. Longitudinal movement of the piston 222 is
limited, preferably, by stops 228. The piston is biased towards a first position, as seen in Figure
3A, by a biasing mechanism 250, shown as a spring. Other biasing mechanisms are known in the
art. The biasing mechanism 250 extends between, and is seated at either end on, a surface or
shoulder of the piston 222 and an internal shoulder 219 of the support assembly 216.
[0029] The piston 222 includes one or more check valve assemblies. The check valve
assembly has a bypass port 238 extending longitudinally through the piston 222, with a ball 240
sized to seat in the check valve to seal against flow in one direction, here, flow from the base
pipe to the wellbore. The ball 238 can be caged. Additionally, other types of check valve or one
way valve can be employed, as known in the art.
[0030] Also disposed in or on the piston 222, is one or more ratchet mechanisms 242.
The preferred ratchet mechanism includes a toothed slip member 244 captured in a slip recess
246 defined in the piston and adjacent to the flow restriction mechanism 224. The teeth of the
slip member 244 cooperate with corresponding sets of teeth 252 defined on the exterior surface
of the flow restriction mechanism 224. The slip member 244 can be a single annular slip or
comprised of multiple slip segments arranged circumferentially around the flow restriction
mechanism in corresponding slip recesses. The design and operation of slips are well known in
the art. Further, the ratchet mechanism can simply employ teeth defined on the internal piston
surface, or on an extension member of the piston, etc., which interact with cooperating teeth on
the restriction mechanism. Ratchet mechanisms are known in the art generally and an exemplary
embodiment is disclosed in the incorporated art.
[0031] A flow restriction mechanism 224 is slidably engaged in the valve annulus 214.
The flow restriction mechanism is preferably a stepped sliding sleeve, as shown, having multiple
positions. In Figure 3A, the flow restriction mechanism is in a fully closed position, where fluid
flow is blocked by sealing engagement between the flow restriction mechanism and a flow
restriction seat 221, preferably defined by a portion of the support assembly 216. A seal 227 can
be used at the surface engagement if desired and mounted to either the seat or the restriction
sleeve. The flow restriction sleeve 224 includes seals 225 engaging the base pipe 202, as
necessary. Defined on the exterior surface of the restriction sleeve are multiple sets of teeth 252,
here two sets of teeth 252a and 252b. The sets of teeth each cooperate with corresponding teeth
defined on the slip member 244. The preferred flow restrictor has a stepped flow restriction
surface 254 with multiple restriction levels 254a-c, which, when the restriction sleeve is moved
to various positions, define corresponding flow areas which allow for greater or lesser flow
through the device 200.
[0032] The operation of the inflow control device 200 will now be described with
reference to Figures 3A-E. The device is typically run-in to the hole in a first or closed position,
as seen in Figure 3A. The flow restriction sleeve 224 is in a closed position, with fluid flow
through the valve annulus 214 prevented by sealing engagement between the restriction surface
level 254a and the restriction seat 221. The piston 222 is also in a first position, maintained in
position by biasing mechanism 250 and a stop 228.
[0033] When it is desired to open the inflow control device, tubing pressure is increased
by the operator, applying a differential pressure across the piston sufficient to move the piston
longitudinally to a second position, as seen in Figure 3B. The piston compresses the biasing
mechanism 250 and its longitudinal movement is limited by either resistance from the biasing
element or a stop 228. The ratchet mechanism 242 engages a corresponding set of teeth 252a
defined on the flow restriction sleeve 242. More specifically, the slip segment 244 slides
longitudinally over the tooth set 252a, utilizing, if necessary, radial space defined in the recess
246 to move radially outward to ease passage over the teeth 252a. Flow through the device is still
blocked. Note that increased tubing pressure will operate a plurality of inflow control devices
spaced longitudinally along the wellbore simultaneously.
[0034] To open the inflow control device, the operator reduces tubing pressure such that
the biasing mechanism 250 forces the piston 222 back to its original or first position, as seen in
Figure 3C. The flow restriction sleeve 242 is pulled by the piston since the ratchet teeth remain
engaged with the tooth set 252a on the sleeve. The restriction sleeve 242 is moved to a second or
intermediate position, as shown, allowing flow through the flow restriction assembly and across
the device 200. The seat 221 and flow surface level 254b cooperate to define a flow area selected
to allow a defined flow rate across the restriction assembly. Fluid flow is now allowed along a
flow path including the wellbore annulus, a screen or filter device if present, annular area 210,
support assembly port 220, across flow restriction surface 254, through check valve port 238,
base pipe ports 204, and the interior passageway of the base pipe 202.
[0035] To adjust the flow restriction mechanism to a second or, in this case, final flow
position, the tubing pressure is again increased, seating the check valve ball and moving the
piston against the biasing element, as seen in Figure 3D. The ratchet mechanism again
cooperates, this time with tooth set 252b. Tubing pressure is decreased such that the biasing
mechanism forces the piston 222 back to its original position, as seen in Figure 3E. The flow
restriction sleeve 242 is pulled by the piston, since the ratchet teeth remain engaged with the
tooth set 252b on the sleeve. The restriction sleeve 242 is moved to a fully open position, as seen
in Figure 3E. Fluid flows through the flow restriction assembly and across the device 200. The
seat 221 and flow surface level 254c cooperate to define a fully open flow area, selected to allow
a defined flow rate across the restriction assembly. Fluid flows along a flow path including the
wellbore annulus, a screen or filter device if present, annular area 210, support assembly port
220, across flow restriction surface 254, through check valve port 238, base pipe ports 204, and
the interior passageway of the base pipe 202.
[0036] Additional restriction and flow rate gradations can be used. For example, in a
stepped flow restriction mechanism, additional flow surface levels can be added, with
corresponding additional teeth sets for cooperation with the ratchet assembly. Further, flow
restriction mechanisms, such as those having a ramped, conical, or other shaped element can be
used to provide additional gradations.
[0037] Additional features, such as locking or temporary holding mechanisms can be
employed to control relative movement between parts of the assembly. For example, a temporary
holding mechanism, such as a shear pin, shear ring, snap ring, detent, etc., can be used to
maintain the piston stationary with respect to the support assembly until sufficient tubing
pressure is applied to actuate the temporary holding mechanism (e.g., shear the shear pin).
Further such mechanisms can be used to regulate movement of the flow restriction sleeve with
respect to the support assembly or base pipe. Further, the check valve in the piston could be
replaced with a flow orifice or the like, in which case the device is actuated by fluid flow rate
rather than pressure.
[0038] Figures 4A-C are schematic cross-sectional illustrations of an exemplary
embodiment, generally designated as 300, of an inflow control device according to an aspect of
the invention utilizing a j-slot actuated flow restriction mechanism. The illustrated inflow control
device can be used with or without a screen assembly, additional flow control components etc.
The embodiment described in the preferred embodiment below is simplified for purposes of
discussion.
[0039] The illustrated flow control device 300 is positioned about a base pipe 302.
Multiple devices can be attached to the base pipe at circumferentially spaced apart locations on
the base pipe. Similarly, a single housing surrounding the base pipe can be utilized to house
multiple inflow restriction devices. Other arrangements will be apparent to those of skill in the
art. The base pipe includes inflow ports 306 providing fluid communication between the interior
of the base pipe and the valve annulus 341. Further, the base pipe includes pressure ports 308
providing for pressure communication between the interior of the base pipe and the piston
annulus 314.
[0040] The inflow control device 300 includes a slidable piston 322 positioned in a
piston annulus 314 defined between in the housing 312. Seals 324 provide a fluid seal between
the piston and housing walls. The piston 322 is initially, releasably, and repeatably, held in a first
position by a holding device 326, as seen in Figure 4A. In the preferred embodiment shown, the
piston is held in position by a collet assembly 328 having a plurality of collet fingers 329
movable between a radially expanded position, seen in Figure 4A, and a radially collapsed
position, seen in Figure 4B. The collet assembly includes a plurality of locking dogs 330
extending radially from the collet fingers into cooperating one or more recesses 332 defined in
the housing walls. Operation of collet assemblies, as well as various designs for collet
assemblies, are known in the art and will not be discussed in further detail here. The holding
device can alternately be a snap ring, spring-loaded radial pin, a cooperating locking dog
extending from a spring-loaded or otherwise biased element, such as a spring arm, lever arm, etc.
Other embodiments will be apparent to those of skill in the art.
[0041] The piston is biased toward the first position by a biasing mechanism 334, such as
a coil spring, as shown. The coil spring seats on one end of the piston and a housing shoulder
336. The coil spring is positioned around a mechanical link 338, here a simple piston rod
extending longitudinally from the piston.
[0042] Changes in the pressure signal may be used to cycle a sliding valve element 340
through a plurality of positions or an infinite series of positions. As best seen in Figure 4A, the
piston rod is attached to the valve element 340 at rotation joint 342 to allow relative rotational
movement of the rod and valve element. The piston is operable to longitudinally slide the valve
element, back and forth, in valve annulus 341. The rotatable element 340 may include a groove
344, referred to as a j-slot, defined on its surface into which one or more pins 346 extend. The
pins 346 can extend radially from the housing wall, base pipe, etc., and cooperate with the
groove. Alternately, the groove can be defined on the housing or base pipe wall while the pins
are carried on the valve element.
[0043] The housing 312 has a plurality of production ports 304a-d providing fluid
communication between the valve annulus 341 and the wellbore annulus exterior to the device.
These production ports cooperate with the valve element 340, which, depending on its rotational
position, blocks or allows fluid flow through one or more of the production ports. The valve
element may have one or more flow recesses 348 defined on its exterior surface for cooperation
with the production ports 304. The valve element is rotatable to a plurality of positions, each
defining a flow condition, such as closed, one-third open, two-thirds open, and fully open, for
example. In the closed position, seen in Figure 4A, the valve element blocks flow through the
production ports 304. In the one-third open position, a flow recess 348 of the valve element is
positioned such that flow recess 348 aligns with and allows production through, for example,
production port 304a while the other production ports remain blocked. Further positions of the
valve element allow for flow through additional production ports or combinations of production
ports.
[0044] Changes in the tubing pressure signal acting on the piston 322 cause the piston to
slide in the piston annulus 314. The increased tubing pressure acts on the collet assembly,
radially collapsing the collet at a pre-selected pressure. Additional devices spaced along the
wellbore, or spaced along an isolated length of the wellbore, are preferably all operated at the
same pressure, such that all inflow control devices are operated simultaneously. The collet
collapses as dogs 330 are moved from recesses 332. The piston 322 shifts longitudinally,
compressing biasing spring 334. Longitudinal movement of the piston and rod cause similar
longitudinal movement of the valve element 340 within valve annulus 341. Relative movement
between the pins 346 and valve element cause the pin to slide within the j-slot 344. The j-slot
causes the valve element to rotate about rotational joint 342.
[0045] Rotation of the valve element selectively aligns the flow recesses 348 of the valve
element with one or more production ports 304a-c, allowing fluid flow through the ports at a pre
selected flow rate. At other rotational positions, flow is blocked through the production ports
304. The j-slot can be designed to require multiple pressure signals to rotate the valve element
from a closed position to an open position. In this case, pin 346 may have to travel through
several sections of j-slot 344 before the valve element is rotated to an aligned position with the
ports 304. Alternatively or additionally, j-slot 344 may be used to prevent further rotation of
valve element 340 once placed in a particular position, such as the fully open position. That is,
the j-slot mechanism can be used to lock the valve in a position. In addition, the j-slot may
enable the valve element to be configured in various choking or partial- flow positions between
the closed position and the fully open position. The j-slot can be infinite, such that rotation can
be caused through an infinite repetition of closed and open positions by continued pressure
cycling.
[0046] The operation of the inflow control device 300 will be described with reference to
Figures 4A-B. The device is typically run-in to the hole in a first or closed position. Flow
through the production ports is prevented by the valve element. The piston 322 is also in a first
position, maintained in position by biasing mechanism 334 and holding mechanism or collet
assembly 326.
[0047] When it is desired to open the inflow control device, tubing pressure is increased
by the operator, applying a differential pressure across the piston sufficient to collapse the collet
assembly 326 and move the piston 322 longitudinally from a first position, as seen in Figure 4A,
to a second position, as seen in Figure 4B. The collet assembly 326 collapses radially inward as
dogs 330 are pulled from recesses 332. The collet assembly 328, piston 322, rod 338, and valve
element 340 are all moved longitudinally along piston annulus 314 and valve annulus 341. The
piston movement compresses the biasing mechanism 334.
[0048] Although the initial condition of the production ports 304 can be set by the
operator, it is expected that in most applications the production ports will be in a closed position
upon run-in-hole. In such a preferred embodiment, flow through across the production ports 304,
valve annulus 341, and inflow ports 306 remains blocked when the piston is in the second
position, seen at Figure 4A. Note that, in such a case, increased tubing pressure will
simultaneously operate a plurality of inflow control devices spaced longitudinally along the
wellbore.
[0049] Tubing pressure is then lowered such that the biasing mechanism 334 forces the
piston 322 back to its original or first position. The valve element 340 is pulled along
longitudinally to its original or first longitudinal position, however, the valve element is rotated
about its longitudinal axis by cooperation of the groove 344 and pin 346.
[0050] As the valve element is moved longitudinally, the groove 344 and pin 346
cooperate to rotate the valve element. The valve element rotates with respect to the piston rod
338 about joint 342. The j-slot track design dictates the rotational movement of the valve element
in response to longitudinal movement of the piston. The j-slot track design will not be discussed
in detail as such mechanisms and designs are known in the art. In a preferred embodiment, the
valve element rotates, but does not open production ports 304 during an initial stroke from the
first to the second position. Upon return of the piston to its original position, the track defined by
the groove 344 will cause the valve element 340 to rotate during the longitudinal movement of
the valve element. Note that multiple pressure sequences can be required to open the production
ports as a safety measure to prevent premature or accidental opening. In a preferred embodiment,
the production valve 304a is aligned with a corresponding fluid passageway 305a defined in the
surface of valve element 340. The fluid passageway allows flow of fluid from production port
304a to the valve annulus 341. Fluid then enters the base pipe at ports 306. Thus, one tubing
pressure cycle (up-down) opens production flow to a first flow level.
[0051] Additional cycles operate in a similar manner, rotating the valve element further
and aligning additional production ports 304b-c with additional flow passageways 305b-c. At
each successive cycle, a greater total fluid flow is allowed across the valve annulus. The flow
passageways and production ports can be sized and aligned as desired. For example, all
production ports can be equally sized such that opening of a second port 304b effectively
doubles the flow from a single port 304a. Alternately, the production ports can be of different
size, allowing different fluid flow across them. The preferred embodiment provides a production
port sequence of closed, one port open, two ports open, three ports open, closed. This can be
altered, obviously, to provide a different order, different number and size of ports opened, etc.
For example, the sequence can call for two ports to be closed when any one port is open,
additional "closed" positions can be interposed between open positions, etc.
[0052] In a preferred embodiment, the valve element can be rotated to close the
production ports 304a-c and stop fluid flow between the base pipe interior and wellbore annulus.
An endless groove 344 can be utilized to provide infinite potential opening and closing cycles of
the valve. Alternately, if it is desirable to have a "final" valve element position, locking the valve
open or closed, for example, the groove can employ a "dead-end" effectively preventing any
further rotation.
[0053] Further, the device can optionally utilize a diaphragm 309 over the port 308. A
relatively non-compressible fluid fills the piston annulus 314. While the diaphragm will transmit
tubing pressure to the piston annulus 314, tubing fluids will not pass into the annulus, thereby
maintaining the collet and piston assemblies clean.
[0054] The flow rate is defined by the dimensions of the production ports, fluid
passageways, and inflow ports. These elements can be designed to provide the desired flow
areas, flow rates, etc., based on wellbore conditions and design considerations. Further, these
elements can be selected and designed based on expected wellbore fluid characteristics over the
life of the well. As an example, where it is expected that an oil well will eventually yield to a
greater percentage of (undesired) gas production, the valve element can be rotated to a position
to reduce gas production while still optimizing oil production. Fluid control components can, for
example, be defined on the surface of the valve element.
[0055] Additional features, such as locking or temporary holding mechanisms can be
employed to control relative movement between parts of the assembly. For example, a temporary
holding mechanism, such as a shear pin, shear ring, snap ring, detent, etc., can be used to
maintain the piston or valve stationary with respect to the housing until sufficient tubing pressure
is applied to actuate the temporary holding mechanism (e.g., shear the shear pin).
[0056] In the preferred and exemplary methods presented herein and in the appended
claims, various method steps are disclosed, where the steps listed are not exclusive, can
sometimes be skipped, or performed simultaneously, sequentially, or in varying or alternate
orders with other steps (i.e., steps XYZ can be performed as XZY, YXZ, YZX, ZXY, etc.)
(unless otherwise indicated), and wherein the order and performance of the steps is disclosed
additionally by the claims appended hereto, which are incorporated by reference in their entirety
into this specification for all purposes (including support of the claims) and/or which form a part
of this specification, the method steps presented in the following text. Exemplary methods of
use of the invention are described, with the understanding that the invention is determined and
limited only by the claims. Those of skill in the art will recognize additional steps, different order
of steps, and that not all steps need be performed to practice the inventive methods described.
[0057] While this invention has been described with reference to illustrative
embodiments, this description is not intended to be construed in a limiting sense. Various
modifications and combinations of the illustrative embodiments as well as other embodiments of
the invention, will be apparent to person skilled in the art upon reference to the description. It is,
therefore, intended that the appended claims encompass any such modifications or embodiments.

It is claimed:
1. A downhole fluid flow control system operable to be positioned in a wellbore
extending through a subterranean formation and operable to control fluid flow between the
wellbore and an internal passageway of a tubular, the system comprising:
a tubing-pressure operated device positioned along a flow path between the interior
passageway of the tubular and the exterior of the tubular;
a piston element, biased towards a first position, slidably disposed in a piston
annulus, the piston annulus having a pressure-transmitting port to the interior passageway of the
tubular, the piston element movable to a second position responsive to a tubing-pressure change
transmitted through the pressure-transmitting port; and
a valve element attached to the piston element and movable in response to
movement of the piston element between a closed position wherein fluid flow is blocked across
the flow path and an open position wherein flow is allowed across the flow path.
2. The system of claim 1, wherein the flow path passes through a bypass port defined
in the piston element.
3. The system of claim 2, wherein the piston element further includes a check valve
positioned thereon operable to control fluid flow through the bypass port.
4. The system of claim 1, wherein the flow path passes through the piston annulus.
5. The system of claim 1, wherein the valve element is movable to multiple open
positions, each open position allowing fluid flow across a pre-selected flow area.
6. The system of claim 1, wherein the valve element is releasably attached to the
piston element.
7. The system of claim 6, wherein the valve element and piston element include
cooperating one-way ratchet teeth.
8. The system of claim 5, wherein the valve element is stepped, ramped, conical,
partially conical or otherwise shaped to define the multiple open positions.
9. The system of claim 7, wherein the piston element further includes a slip, the one
way ratchet teeth defined thereon.
10. The system of claim 1, wherein the valve element is a rotational valve element.
11. The system of claim 10, further comprising a j-slot mechanism for controlling
rotational movement of the valve element.
12. The system of claim 11, wherein the j-slot mechanism includes a pin and
cooperating groove in which the pin travels relative to the rotational valve element.
13. The system of claim 12, wherein the groove is defined on the surface of the
rotational valve element and wherein the pin extends radially into the valve annulus.
14. The system of claim 10, wherein the rotational valve element is rotatable to
multiple open positions relative to a cooperating multiple of production ports.
15. The system of claim 10, wherein the rotational valve element can be rotated from a
closed position to an open position and then to a closed position.
16. The system of claim 12, wherein the groove is endless.
17. The system of claim 1, further comprising a temporary holding mechanism
operatively connected to the piston element.
18. The system of claim 17, wherein the temporary holding mechanism can be
repeatedly used.
19. The system of claim 1, wherein the piston element is an annular piston element
having a longitudinal axis coincident with the longitudinal axis of the tubular.
20. A method for servicing a subterranean wellbore extending through a formation, the
method comprising the steps of:
a) positioning at a downhole location a wellbore tubular having a flow control device
positioned thereon, the flow control device having a piston element mounted for
longitudinal movement within a piston annulus and biased towards a first position, a
valve element mounted for movement and operable by the piston element, and
defining a flow path between an interior passageway of the wellbore tubular and the
wellbore annulus, the valve element positioned along the flow path and operable to
selectively block or allow fluid flow along the flow path;
b) increasing tubing pressure;
c) moving the piston longitudinally in response to step b) from the first position to a
second position;
d) decreasing tubing pressure;
e) moving the piston longitudinally in response to step d) from the second position to the
first position;
f) moving the valve element in response to step c); and
g) allowing fluid flow along the fluid flow path in response to step f).
21. The method of claim 20, further comprising the step of sealing a check valve positioned
on the piston element in response to step b), thereby blocking fluid flow through a bypass port
defined in the piston element.
22. The method of claim 20, further comprising the step of releasably attaching the piston
element and valve element to one another in response to step c).
23. The method of claim 22, wherein the step of releasably attaching the piston and valve
elements further comprises the step of interlocking cooperating one-way ratchet teeth defined on
the valve element with corresponding ratchet teeth defined on the piston element.
24. The method of claim 22, wherein the step of interlocking includes moving a toothed slip
into cooperating contact with ratchet teeth of the valve element.
25. The method of claim 20, further comprising the steps of:
cyclically increasing and decreasing tubing pressure;
repeatedly moving the piston element in response thereto;
repeatedly moving the valve element, in response to movement of the piston element,
between a closed position and multiple open positions, each open position allowing a different
fluid flow rate across the valve element.
26. The method of claim 25, further comprising the steps of repeatedly attaching and
detaching the piston element and valve element to one another in response to the repeated
movement of the piston element.
27. The method of claim 20 or 25, wherein step f) further comprises the step of rotating the
valve element.
28. The method of claim 27, wherein the valve element is operable by relative movement
between a pin and a groove.
29. The method of claim 27, wherein the valve element is rotatable between a closed position
and at least two open positions, each open position allowing a different flow rate through the
device.
30. The method of claim 29, wherein the rotating valve is endlessly rotatable.