U.S. patent application number 15/147417 was filed with the patent office on 2016-11-10 for dissolving material flow control device.
The applicant listed for this patent is Superior Energy Services, LLC. Invention is credited to Eddie Glenn Bowen, Anthony Thomas.
Application Number | 20160326837 15/147417 |
Document ID | / |
Family ID | 57223338 |
Filed Date | 2016-11-10 |
United States Patent
Application |
20160326837 |
Kind Code |
A1 |
Bowen; Eddie Glenn ; et
al. |
November 10, 2016 |
Dissolving Material Flow Control Device
Abstract
A flow control device formed of a tubular housing having a
circumferential wall and a central passage. A plurality of flow
apertures are formed through a section of the circumferential wall
and a dissolvable material is positioned to block flow through the
flow apertures. A closing sleeve capable of moving into a position
to block flow through the flow apertures is also positioned within
the housing.
Inventors: |
Bowen; Eddie Glenn; (Porter,
TX) ; Thomas; Anthony; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Superior Energy Services, LLC |
Harvey |
LA |
US |
|
|
Family ID: |
57223338 |
Appl. No.: |
15/147417 |
Filed: |
May 5, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62157834 |
May 6, 2015 |
|
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|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 34/063 20130101;
E21B 34/14 20130101; E21B 2200/06 20200501 |
International
Class: |
E21B 34/10 20060101
E21B034/10; E21B 43/08 20060101 E21B043/08; E21B 33/12 20060101
E21B033/12; E21B 34/06 20060101 E21B034/06 |
Claims
1-28. (canceled)
29. A flow control device comprising: a. a tubular housing having a
circumferential wall and a central passage; b. a plurality of flow
apertures formed through a section of the circumferential wall; c.
a dissolvable material positioned to block flow through the flow
apertures; and d. a closing sleeve capable of moving into a
position to block flow through the flow apertures.
30. The flow control device of claim 29, wherein the dissolvable
material is formed within the flow apertures.
31. The flow control device of claim 29, wherein the dissolvable
material forms a dissolvable sleeve positioned to the interior of
the circumferential wall.
32. The flow control device of claim 29, wherein the dissolvable
sleeve has a sleeve wall with a thickness ranging between about 1/8
inch and about 1 inch.
33. The flow control device of claim 29, wherein the closing sleeve
has an internal profile engageable by a service tool inserted into
the housing's central passage.
34. The flow control device of claim 33, wherein the closing sleeve
includes a holding collet for holding the closing sleeve in a
closed position.
35. The flow control device of claim 34, wherein the tubular
housing has an internal closing profile shaped to be engaged by
fingers on the closing collet.
36. The flow control device of claim 35, wherein the fingers of the
closing collet are configured to disengage from the closing profile
when force is applied to the closing sleeve by a service tool
moving within the tubular housing's central passage.
37. The flow control device of claim 29, wherein a sleeve seal is
position on either side of a section of the circumferential wall
having the flow apertures such that the sleeve seals engage the
closing sleeve when the closing sleeve blocks the flow
apertures.
38. The flow control device of claim 31, wherein the dissolvable
sleeve is positioned to block the closing sleeve prior to it
dissolving.
39. The flow control device of claim 38, wherein a screen encloses
the tubular housing.
40. The flow control device of claim 38, wherein the dissolvable
material is a magnesium and aluminum nanocomposite disintegrating
material.
41. A method of selectively establishing a fluid communication
between the interior and exterior of a tubular string positioned
within a wellbore, the method comprising the steps of: a.
positioning within a wellbore a flow control device comprising: i.
a tubular housing having a circumferential wall and a central
passage; ii. a plurality of flow apertures formed through a section
of the circumferential wall; iii. a dissolvable material positioned
to block flow through the flow apertures; and iv. a closing sleeve
capable of moving into a position to block flow through the flow
apertures; v. wherein the flow control device is run into the
wellbore without a further tubular string or service tool being
positioned within the central passage of the tubular housing b.
performing at least one downhole operation by increasing pressure
in the tubular string while the dissolvable material blocks flow
through the flow apertures; c. dissolving the dissolvable material
and thereby establishing fluid communication between an interior
and exterior of the tubular string; and d. wherein the central
passage extends above the tubular housing along the tubular string
and prior to the dissolving of the dissolvable material, there is
no flow path through the circumferential wall from outside the
tubular housing into the central passage.
42. The method of claim 41, wherein the step of increasing the
pressure includes increasing the pressure in the range of about
7,500 to about 15,000 p.s.i.
43. The method of claim 41, wherein a screen encloses the tubular
housing.
44. The method of claim 41, wherein the flow control device is
position within a production interval of the wellbore and discrete
screen sections are positioned above and below the flow control
device within the production interval.
45. A method of carrying out completion operations within a
wellbore having at least one producing interval, the method
comprising the steps of: a. positioning within the producing
interval a tubular string including a flow control device and at
least one screen joint above or below the flow control device, the
flow control device comprising: i. a tubular housing having a
circumferential wall and a central passage; ii. a plurality of flow
apertures formed through a section of the circumferential wall;
iii. a dissolvable material positioned to block flow through the
flow apertures; and iv. a closing sleeve capable of moving into a
position to block flow through the flow apertures; v. wherein the
positioning of the tubular string is carried out without a further
tubular member being positioned within the central passage of the
flow control device; b. after step (a), circulating fluids through
the central passage and back up an annulus of the wellbore; and c.
after step (b), increasing pressure within the central passage in
order to set packers and isolate the annulus along the producing
interval.
46. The method of claim 45, wherein at least one screen joint is
positioned above the flow control device and at least one screen
joint is positioned below the flow control device.
47. The method of claim 45, further comprising, before the step of
setting the packers, spotting a solvent to the dissolvable material
in the wellbore along the producing interval.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit under 35 U.S.C.
.sctn.119(e) of U.S. Provisional Application Ser. No. 62/157,834
filed May 6, 2015, which is incorporated by reference herein in its
entirety.
BACKGROUND OF INVENTION
[0002] In the oil and gas completions industry, a tubular string
position within the wellbore will have various devices (often
generically called "valves") for controlling the flow of fluid
between the interior and exterior of the tubular string. One common
form for such valves is a "sliding sleeve" valve, where an outer
tubular member has a series of apertures and a concentric internal
tubular sleeve is shifted to uncover the apertures (i.e., "open"
the valve) or to cover the apertures (i.e., "close" the valve).
Often, this sleeve is shifted between its open and closed position
by a tool which is run into the wellbore (e.g., on coiled tubing)
and which engages a profile on the internal surface of the
sleeve.
[0003] Obviously, each trip running a tool in and out of the
wellbore is a time consuming and costly action. Therefore, the oil
and gas industry is always seeking more efficient ways to
selectively open communication between the interior of the tubular
string and the producing formation through which the wellbore
extends.
BRIEF DESCRIPTION OF DRAWINGS
[0004] FIG. 1 is a cross-section of a first embodiment of a flow
control device of the present invention.
[0005] FIG. 2 is a cross-section of a second embodiment of a flow
control device of the present invention.
[0006] FIG. 3A illustrates a first method of employing the flow
control device described herein.
[0007] FIG. 3B illustrates a second method of employing the flow
control device described herein.
DETAILED DESCRIPTION OF SELECTED EMBODIMENTS
[0008] The embodiment of the flow control device 1 seen in FIG. 1
is generally formed of a tubular housing 3 having a circumferential
wall 5 and a central passage 4. Typically, each end of the housing
will include a connector device 7, e.g., threaded or some other
coupling structure, to allow the flow control device (usually a
series of flow control devices) to be integrated at the appropriate
location(s) along the length of the tubular string being positioned
in the wellbore. The circumferential wall 5 will include a section
6 with at least one, and more commonly a plurality of, flow
apertures 10 formed through the circumferential wall 5. In FIG. 1,
the flow apertures 10 are a series of circular flow apertures 11
which are about 1 inch in diameter. Naturally, the size of the
circular apertures 11 could vary substantially and be shapes other
than circles. Section B-B seen in FIG. 1 is a cross-section through
the apertures 11. In the FIG. 1 embodiment, the section 6 having
the flow apertures 10 is a separable sub-component 9 connected the
rest of housing 1 by threaded connection 13.
[0009] FIG. 1 suggests how the apertures 11 will be filled with a
"disappearing" or dissolving material 34. Although FIG. 1
illustrates only a few apertures 11 filled with dissolving material
34, it will be understood that typically all, or substantially all,
of the apertures 11 will be filled with dissolving material 34. A
"dissolving" material can be any material which may initially act
to plug apertures 11 under initially encountered wellbore
conditions (e.g., pressure, temperature, pH, etc.), but will
dissolve, degrade, or disintegrate under a second condition(s)
(including extended time under initially existing wellbore
conditions) to the point that fluid flow may be established through
the apertures 11. As a nonlimiting example, the dissolving material
should be capable of maintaining its integrity (i.e., blocking
flow) at differential pressures of up to twelve thousand psi.
[0010] The dissolving material may be any number of materials
including, but not limited to, dissolvable metals such as
magnesium, aluminum (including alloys thereof), dissolvable
polymeric materials, or other dissolvable polymers. Magnesium (Mg),
either in elemental form or as an alloy, can serve as one preferred
base material for dissolvable material 34. For example, the
dissolvable material 34 could be Mg alloys that combine other
electrochemically active metals, including binary Mg--Zn, Mg--Al
and Mg--Mn alloys, as well as tertiary Mg--Zn--Y and Mg--Al--X
alloys, where X includes Zn, Mn, Si, Ca or Y, or a combination
thereof. These Mg--Al--X alloys may include, by weight, up to about
85% Mg, up to about 15% Al and up to about 5% X. These
electrochemically active metals, including Mg, Al, Mn or Zn, or
combinations thereof, may also include a rare earth element or
combination of rare earth elements. As used herein, rare earth
elements include Sc, Y, La, Ce, Pr, Nd, Fe, or Er, or a combination
thereof. Where present, a rare earth element or combinations of
rare earth elements may be present, by weight, in an amount of
about 5% or less. As a specific example, TervAlloy.TM. available
from Terves, Inc. of Euclid, Ohio is a magnesium and aluminum
nanocomposite disintegrating material designed to disintegrate
(turn to powder) based on exposure to a controlled fluid (e.g., an
electrolyte), or an electrical or thermal stimuli. TervAlloy.TM.
will disintegrate into very fine grained particles after a
specified time in response to a controlled environmental stimulus.
A wide range of solvents may be employed as long as they are
capable of reducing the dissolving material without excessive
corrosion of downhole tubulars and equipment. As nonlimiting
examples, the solvent could be brines formed from NaCl, CaCl, NaBr,
CaBr, caesium formates, sodium formates, etc. Likewise, the solvent
could be any number of acids including various concentrations of
hydrofluoric acid, hydrochloric acid, sulfuric acid, acetic acid,
and other acids commonly used in the downhole environment. In one
embodiment, the dissolvable material such as the above
TervAlloy.TM. may be coated with a polymer that is unaffected by
acids and brines found in the downhole environment where the
material is to be used. When it is desired to remove the
dissolvable material, a solvent effective against the polymer
(e.g., hydrofluoric acid) is circulated to remove the polymer
coating, thus exposing the TervAlloy.TM. existing brines that will
ultimately degrade it. The brine may be latent brine or additional
brine which is circulated downhole.
[0011] Adjacent to the section 6 of apertures 10 is the closing
sleeve 20. Closing sleeve 20 is a slidable sleeve having an outer
diameter slightly smaller than the inner diameter of section 6 such
that closing sleeve 20 travels into section 6. Although a portion
of the sleeve length is shown removed in the FIG. 1 illustration,
the length of closing sleeve 20 will be sufficient to engage the
sleeve seals 30A and 30B on each side of section 6. In the
illustrated embodiment, closing sleeve 20 will include a tool
profile 26 allowing a conventional closing tool (e.g., a tool
mounted on coil tubing or wireline) to engage the tool profile 26
and apply the force necessary to move closing sleeve 20 into the
section 6. Closing sleeve 20 will also include a closing collet 22
having a series of collet fingers 23. As is well known in the art,
collet fingers will be biased outward, but be configured to flex
inward with the application of sufficient force. In FIG. 1, the
collet fingers are shown engaging the open collet profile 25, which
will require a first pulling force (for example, about 3000 to 4000
lbs) to move the collet fingers out of profile 25. Although not
explicitly seen in the Figures, it can be envisioned how, as
closing sleeve 20 moves into its closed position blocking the
apertures 11, the collet fingers 23 will move into and engage the
closed collet profile 24. The closed collet profile is configured
such that a similar force is required to dislodge the collet
fingers 23 from closed collet profile 24. As suggested above, once
closing sleeve 20 is in the closed position, the sleeve's
engagement will seals 30A and 30B will form a fluid tight barrier
preventing fluid communicating though the apertures 11 (i.e., in
the case where the dissolvable material 34 has been dissolved from
apertures 11). Although seals 30A and 30B could be any number of
conventional or future developed seals, in certain examples, seals
30A and 30B may be a bonded seal or an unipack seal, e.g., a seal
formed from a mesh/rubber matrix.
[0012] Although the FIG. 1 embodiment illustrates a single section
6 of flow apertures and a single closing sleeve 20 between two
connector devices 7, it will be understood that other embodiments
could have multiple sets of flow aperture sections 6 with closing
sleeves 20 positioned sequentially as a continuous tubular section
with no intervening connector devices 7. This principle applies
equally to the FIG. 2 embodiment discussed below.
[0013] FIG. 2 illustrates a modification of the flow control device
shown in FIG. 1. In the FIG. 2 embodiment, the flow apertures 10
are formed of elongated slots 12. However, the flow apertures in
some instances may be circular, oval, or other shaped apertures.
Moreover, rather than the flow apertures 10 being directly filled
with the dissolvable material, the FIG. 2 embodiment utilizes an
inner sleeve 35 formed of the dissolving material (or dissolving
sleeve 35). In one example, dissolving sleeve 35 material is formed
from the TervAlloy.TM. specified above. In the example of the
tubular housing 3 having an outer diameter of approximately 6
inches, the thickness of dissolving sleeve 35 is approximately 3/8
inches. However, the housing dimensions and sleeve thicknesses may
vary considerably among different embodiments. In the FIG. 2
embodiment, the positioning of dissolving sleeve 35 acts to block
closing sleeve 20 prior to the time dissolving sleeve 35 has been
dissolved. Once dissolving sleeve 35 has been removed, then closing
sleeve 20 may function in conjunction with seals 30 as described in
FIG. 1 with respect to blocking flow through flow slots 12. FIG. 2
also shows a profile 36 formed on the inner surface of dissolving
sleeve 35. This profile is intended to aid in the tool assembly
process. A gripping tool may engage profile 36 and assist in
overcoming the tight tolerances encountered when inserting
dissolving sleeve 35 within the tubular sections forming housing
2.
[0014] In many contemplated uses, the flow control device seen in
FIGS. 1 and 2 may include well screens positioned over tubular
housing 2. One such screen is represented schematically in FIG. 2
as screen section 45. Any number of convention or future developed
well screens could be employed depending on wellbore conditions and
the type/size of particles the screen is intended to block from
entry through the flow apertures. As one non-limiting examples, the
screens could be slip-on wire jackets, direct wrap wire jackets,
slip-on pre-pack filters, or woven mesh filters. Example
screen/filter opening sizes could be from 60 um to 500 um (or any
sub-range there between). Although not explicitly shown in the
drawings, many embodiments will be formed of a series of flow
control devices 1 connected together under a continuous length of
screen section.
[0015] As one example of a contemplated use, a tubular string
incorporating a series of flow control devices 1 will be run into
the wellbore such that the flow control devices are positioned at
the wellbore locations where communication exterior to the string
is desired. At this point, the dissolvable material is intact in
the flow apertures (or the dissolving sleeves are in place) and the
closing sleeves (i.e., nondissolving permanent sleeves) are in the
open position. Various downhole operations requiring an increase of
fluid pressure internal to the tubular string may be carried out;
for example, setting pressure activated packers incorporated into
the string, or circulating while running in the hole without need
of an inner string. In one example, the pressure is within the
central passage of the flow control device is increased in the
range of about 7,500 to 15,000 about p.s.i. (or any sub-range
therebetween).
[0016] It will be understood that when the dissolvable material is
in place in the flow apertures, there are no flow paths through the
circumferential wall of the tubular housing, i.e., no flow paths
from outside the tubular housing into the central passage (or from
the central passage to the outside of the tubular housing). The
absence of flow paths is not only in portion of the central passage
in the immediate area of the flow apertures, but also portions of
the central passage extending above or below the tubular housing
along the tubular string.
[0017] As suggested above, there are certain embodiments where the
step of initially positioning the flow control device in the
wellbore includes running the flow control device into the wellbore
without a service tool (or any other type of inner tubular member)
being positioned within the central passage of the flow control
device's tubular housing. These embodiments could be employed to
carry out operations such as a single trip standalone screen
application where the production assembly and sandface assembly are
run and installed in a single trip using the dissolvable material
as a barrier to flow. This arrangement enables circulation of
filter cake removal fluids, packer corrosion inhibitor fluids, and
aides in fluid loss control while removing the BOP's and installing
the wellhead. Further, packers may be set without the need of
running a plug or any other isolation device by applying pressure
against the dissolvable material prior to its degradation phase
permitting activation of any downhole hydraulic device in the
completion assembly as required.
[0018] When it is desired to establish communication outside the
tubular string, a dissolving agent may be circulated into contact
with the dissolving material for sufficient duration to remove or
to sufficiently weaken the dissolving material within the flow
apertures. For example, this may be achieved at the end of a gravel
or frac pack using the inner service tool string on a multi-zone,
single trip application; or it can be achieved using a smaller
workstring run on a separate trip to circulate the solvent
(dissolution fluid). This may involve a single solvent or more than
one (e.g., one solvent to remove a protective coating and another
to dissolve the underlying material) and thus involve separate
trips to spot the different solvents. Once this is accomplished,
fluid communication will be opened with the environment exterior to
the tubular string. When the well operator desires to close off
this fluid path, a closing tool is run downhole to engage and shift
the closing sleeve into the closed position.
[0019] FIGS. 3A and 3B illustrate two nonlimiting examples of
methods employing the above concepts. FIG. 3A shows the wellbore
100 extending through a producing interval 120 with wellbore 100
being a "cased" wellbore including casing 105 and cement layer 110.
The casing and cement layer have been perforated in order to
establish communication with the producing interval. A tubular
string 75, including packers 60, is positioned within the producing
interval 120. The packers 60 could be any number of conventional or
future developed packers which operate to isolate the wellbore
annulus along the producing interval. In the FIG. 3A example,
packers 60 may be pressure activated packers such as CompSet.TM.
packers available from Superior Energy Services, LLC, Completion
Services division, of Houston, Tex. Between packers 60, the tubular
string includes a plurality of flow controls devices 1 such as
described above in reference to FIG. 1 or 2. FIG. 3A illustrates
three flow control devices positioned sequentially one after the
other. However, other embodiments could include other tubular
sections (e.g., screen sections or joints) between the flow control
devices 1.
[0020] In operation, the tubular string is lowered into the
wellbore until the packers 60 are positioned above and below the
producing interval. As suggested in FIG. 3A, there is no service
tool, inner workstring, or other tubular member position in the
central passage of the tubular string 75 as it is lowered into
position. At this point, the flow apertures in the flow control
devices are still plugged with the dissolvable material and any
number of down hole operations may be carried out. For example, the
flow arrows in FIG. 3A suggest the circulation of fluid down the
central passage of the tubular string and back up the annulus, it
being understood that packers 60 are unset at this stage. When it
is desired to set the packers, the lower end of the tubular string
(not seen in FIG. 3A) is closed off by any conventional means such
as a pressure operated valve or by dropping a ball which engages a
ball seat. Thereafter, fluid in the tubular string's central
passage may be raised to the degree necessary to set packers 60. In
order to open the flow apertures in the flow control device, the
dissolvable material in the flow apertures will be dissolved, e.g.,
by allowing existing wellbore fluids to degrade the dissolvable
material over time. In cases where it is necessary to circulate an
acid or other solvent in order to remove the dissolvable material,
the solvent will be circulated to or "spotted" in the area of the
dissolvable plugs prior to setting the packers. Then the packers
are promptly set before the solvent significantly affects the
structural integrity of the plugs.
[0021] FIG. 3B shows a slightly different configuration of the
tubular string. In the FIG. 3B example, the tubular string section
within the production zone includes an flow control device 1 with
at least one screen joint 50 above or below the flow control
device. As used herein, "screen joint" means any suitable
conventional or future developed screen section used in the oil and
gas wells, typically formed by a section of base pipe with
apertures and one or more layers of screen material overlaying the
base pipe. One example of screen joint 50 could be the ProWeld
TOP.TM. screen section available from Superior Energy Services,
LLC, Completion Services division, of Houston, Tex. Naturally, the
FIG. 3B embodiment is merely illustrative and other configurations
could multiple screen joints above and/or below the flow control
device 1 or multiple flow control devices 1 in combination with the
screen joints. Since a wellbore may often be deviated or
horizontal, "above" and "below" do not necessarily mean higher or
lower in the vertical sense, but rather closer, along the wellbore
path, to the surface or toe of the wellbore toe, respectively.
[0022] Although FIGS. 3A and 3B only illustrate one producing
interval, it will be understood that there are often multiple
producing intervals along the length of the wellbore. Each interval
could include a flow control arrangement such as seen in the
figures with the packers separately isolating each interval.
Typically, the packers are set and intervals treated in succession,
with operations conducted on the lowest interval first. It can
readily be seen that while the dissolvable plugs are in place, the
flow control tools will provide fluid loss control for fluids
circulated through the tools, i.e., prevent unintended loss of
fluids into the formation Likewise, while FIGS. 3A and 3B
illustrate methods carried out in cased wellbores, it will be
understood these methods could also be employed in uncased
wellbores.
* * * * *