U.S. patent application number 12/469521 was filed with the patent office on 2009-11-19 for zonal isolation system.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Philippe Gambier, Jose F. Garcia, Dinesh R. Patel.
Application Number | 20090283279 12/469521 |
Document ID | / |
Family ID | 41315044 |
Filed Date | 2009-11-19 |
United States Patent
Application |
20090283279 |
Kind Code |
A1 |
Patel; Dinesh R. ; et
al. |
November 19, 2009 |
ZONAL ISOLATION SYSTEM
Abstract
A zonal isolation system for use in a well is provided. The
zonal isolation system includes a zonal isolation tool, at least
one anchor, and at least one polished bore receptacle. The zonal
isolation system may include a setting string for activation of the
zonal isolation tool and/or the at least one anchor. The zonal
isolation system may also include an isolation string for
maintaining separation zones during production or injection of the
well.
Inventors: |
Patel; Dinesh R.; (Sugar
Land, TX) ; Gambier; Philippe; (Houston, TX) ;
Garcia; Jose F.; (Sugar Land, TX) |
Correspondence
Address: |
SCHLUMBERGER RESERVOIR COMPLETIONS
14910 AIRLINE ROAD
ROSHARON
TX
77583
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
41315044 |
Appl. No.: |
12/469521 |
Filed: |
May 20, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
11308617 |
Apr 12, 2006 |
7591321 |
|
|
12469521 |
|
|
|
|
60594628 |
Apr 25, 2005 |
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Current U.S.
Class: |
166/382 ;
166/118 |
Current CPC
Class: |
E21B 33/129 20130101;
E21B 33/1216 20130101; E21B 33/1272 20130101; E21B 23/06
20130101 |
Class at
Publication: |
166/382 ;
166/118 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 23/00 20060101 E21B023/00; E21B 23/01 20060101
E21B023/01 |
Claims
1. A zonal isolation system for use in a well, comprising: a zonal
isolation tool; at least one anchor; and at least one polished bore
receptacle.
2. The system of claim 1, further comprising a second polished bore
receptacle wherein the at least one polished bore receptacle is
placed above the zonal isolation tool and the second polished bore
receptacle is place below the zonal isolation tool.
3. The system of claim 1, further comprising a second anchor
wherein the at least one anchor is placed above the zonal isolation
tool and the second anchor is place below the zonal isolation
tool.
4. The system of claim 1, further comprising an expansion joint for
allowing for movement of parts and tubulars due to external forces
caused by temperature fluctuations downhole.
5. The system of claim 1, further comprising a setting string for
activating one or more parts of the zonal isolation system.
6. The system of claim 5, further comprising a isolation string 94
for maintaining separation of zones during production or
injection.
7. The system of claim 3, wherein the at least one anchor and the
second anchor are classical slip anchors.
8. The system of claim 3, wherein the at least one anchor and the
second anchor are two-stage slip anchors.
9. The system of claim 3, wherein the at least one anchor and the
second anchor are self locking anchors.
10. The system of claim 3, wherein the at least one anchor and the
second anchor are penetrator-type anchors.
11. A method of forming zonal isolation in a well, comprising a)
positioning a zonal isolation tool in a wellbore between two zones;
b) enabling setting the zonal isolation tool using polished bore
receptacles; c) preventing movement of the zonal isolation tool
using anchors; and c) setting the zonal isolation tool using a
setting string positioned across the polished bore receptacles.
12. The method of claim 11, further comprising an expansion joint
for allowing for movement of parts and tubulars due to external
forces caused by temperature fluctuations downhole.
13. The method of claim 11, further comprising an isolation string
94 for maintaining separation of zones during production or
injection.
14. The method of claim 11, wherein the at least one anchor and the
second anchor are classical slip anchors.
15. The method of claim 11, wherein the anchors are two-stage slip
anchors.
16. The method of claim 11, wherein the anchors are self locking
anchors.
17. The method of claim 11, wherein the anchors are penetrator-type
anchors.
18. The method of claim 11, wherein one of the polished bore
receptacles is placed above the zonal isolation tool and the other
polished bore receptacle is places below the zonal isolation tool.
Description
[0001] This application claims the benefit under 35 U.S.C. .sctn.
119(e) of and is a continuation-in-part of U.S. Provisional
Application Ser. No. 60/594,628, entitled "Zonal Isolation Tool,"
filed Apr. 25, 2005; and of U.S. application Ser. No. 11/308,617,
entitled, "Zonal Isolation Tools and Methods of Use," filed Apr.
12, 2006, both hereby incorporated by reference.
RELATED ART
[0002] A zonal isolation tool should provide reliable, long-term
isolation between two or more subsurface zones in a well. A typical
application would be to segregate two zones in an open-hole region
of a well, the zones being separated by a layer of low permeability
shale in which the zonal isolation tool is placed. A nominal size
configuration would be usable in wellbores drilled with an 81/2
inch (21.6 cm) outer diameter bit below 95/8 inch (24.5 cm) casing,
but the use of zonal isolation tools is not limited to any
particular size, or to use in open holes. By segregating open-hole
intervals, downhole chokes may be used for production management.
Similarly, selective zonal injection may be performed. If
distributed temperature sensing is placed in the well, monitoring
predictive control is possible.
[0003] A conventional completion assembly 10 with a zonal isolation
tool 12 is illustrated in FIGS. 1 and 2 for allowing production of
two separate flows 4A and 4B from an open hole 3. Assembly 10 may
include a production packer 14, a gravel pack packer 16, flow
control valves 18, and other components commonly used in downhole
completions. Zonal isolation tool 12 may comprise a packer 20, a
pair of anchors 22, a pair of polished bore receptacles (PBRs) 24,
and an expansion joint 26. Service tools may include a setting
string 28 and an isolation string 30.
[0004] However, most of the current openhole zonal isolation
systems are not designed to enable long term, openhole, hydraulic
isolation. Specific challenges include sealing and anchoring the
system, and the ability to allow for expansion and/or contraction
due to thermal effects, all located within the openhole interval of
a sandface completion. There are also issues of coping with
retaining the differential pressure rating for wider open hole
internal diameters or changes in the open hole internal diameter
within the specified operating envelope.
[0005] Therefore, while there have been some improvements in zonal
isolation tool designs and systems, further improvement is
desired.
SUMMARY
[0006] In general, a zonal isolation system for use in a well is
provided. The zonal isolation system includes a zonal isolation
tool, at least one anchor, and at least one polished bore
receptacle. The zonal isolation system includes a setting string
for activation of the zonal isolation tool and/or the at least one
anchor. The zonal isolation system may also include an isolation
string for maintaining separation zones during production or
injection of the well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 is a schematic side elevation view, partially in
longitudinal cross section, of a completion assembly comprising an
embodiment of a zonal isolation tool constructed in accordance with
embodiments of the invention;
[0008] FIG. 2 is a schematic side elevation view, partially in
longitudinal cross section, of the zonal isolation tool of FIG. 1,
along with a setting string and isolation string;
[0009] FIG. 3 is a schematic longitudinal side elevation view of a
portion of the base structure of the zonal isolation tool of FIG.
1;
[0010] FIG. 4 is a schematic longitudinal side elevation view of a
portion of the base structure of the zonal isolation tool of FIG. 1
after inflation pressure has been applied;
[0011] FIG. 5 is a schematic longitudinal side elevation view of a
portion of the base structure of the zonal isolation tool of FIG. 1
with a compressive load being applied;
[0012] FIGS. 6A-D are schematic longitudinal cross sectional views
of a portion of the base structure of the zonal isolation tool of
FIG. 1 illustrating an operational sequence;
[0013] FIG. 7 is a schematic longitudinal cross section view of a
portion of the zonal isolation tool of FIG. 1 illustrating the seal
element;
[0014] FIG. 8 is a schematic longitudinal cross section view of a
portion of the zonal isolation tool of FIG. 1 illustrating the seal
element after inflation pressure;
[0015] FIG. 9 is a schematic longitudinal cross section view of a
portion of the zonal isolation tool of FIG. 1 illustrating the seal
element after compressive loading is applied;
[0016] FIG. 10 is a more detailed schematic longitudinal cross
section view of the seal element of the zonal isolation tool of
FIG. 1;
[0017] FIG. 11 is an enlarged detailed view of a portion of the
seal element of the zonal isolation tool of FIG. 1;
[0018] FIG. 12 is an enlarged schematic longitudinal cross section
view illustrating anti-extrusion sheets used in the zonal isolation
tool of FIG. 14;
[0019] FIG. 13 is a perspective schematic view of the structural
undercarriage of the zonal isolation tool of FIG. 1;
[0020] FIGS. 14A and 14B are schematic axial cross section views
illustrating alternate fluid pathways that may be incorporated in
the zonal isolation tool of FIG. 1; and
[0021] FIGS. 15A, 15B, and 15C are schematic longitudinal cross
section views of another embodiment of a zonal isolation tool.
[0022] FIG. 16 is a schematic side elevation views, partially in
longitudinal cross section, of the zonal isolation system along
with a setting string and isolation string;
[0023] FIG. 17 is a partial schematic side views of a slip
anchor;
[0024] FIG. 18 is a partial schematic side views of a two-stage
slip anchor;
[0025] FIG. 19 is a perspective view of a self locking anchor;
[0026] FIG. 20 is a partial schematic side views of a penetrator
type anchor;
[0027] FIG. 21 is a schematic cross section side view of a portion
of the zonal isolation system;
[0028] It is to be noted, however, that the appended drawings are
not to scale and illustrate only some embodiments of this
invention, and are therefore not to be considered limiting of its
scope.
DETAILED DESCRIPTION
[0029] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those skilled in the art that the present
invention may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0030] Described herein is a zonal isolation system 80 for use in
wellbores. A "wellbore" may be any type of well, including, but not
limited to, a producing well, a non-producing well, an experimental
well, and exploratory well, and the like. Wellbores may be
vertical, horizontal, any angle between vertical and horizontal,
diverted or non-diverted, and combinations thereof, for example a
vertical well with a non-vertical component. Also, in the
description, the terms "connect", "connection", "connected", "in
connection with", and "connecting" are used to mean "in direct
connection with" or "in connection with via another element". The
term "set" is used to mean "one element" or "more than one
element". The terms "up" and "down", "upper" and "lower",
"upwardly" and "downwardly", "upstream" and "downstream", "above"
and "below", and other like terms indicating relative positions
above or below a given point or element are used in this
description to more clearly described some embodiments as disclosed
herein. However, when applied to equipment and methods for use in
wells that are deviated or horizontal, such terms may refer to a
left to right, right to left, or other relationship as
appropriate.
[0031] Referring now to FIGS. 16 and 21, the open hole zonal
isolation system 80 may comprise a zonal isolation tool 29, a first
anchor 82 and a second anchor 84, an upper polished bore receptacle
86 and a lower polished bore receptacle 88, and an expansion joint
90. The zonal isolation system may also include a setting string 92
and an isolation string 94.
[0032] Referring now to FIGS. 3, 4 and 5, an embodiment of the
zonal isolation tool 29 is disclosed. The drawings are schematic in
fashion and not to scale. The same numerals are used to call out
similar components. This embodiment includes an elastomeric seal
member 34 initially inflated by a fluid entering an inflation port
21 in base pipe 15. Inflation port 21 aligns with a similar passage
31 in a member 19, which may be described as an inflation valve,
during initial expansion of seal member 34. Member 19, along with a
moveable piston 13 and a movable sleeve 7 also define an expandable
chamber 2. Moveable sleeve 7 includes a through hole 9, whose
function will become apparent. Base pipe 15 includes another
through passage 11 opening into a chamber 23 formed in a stationary
sleeve 5. Moveable piston 13 is able to slide longitudinally
downward within stationary sleeve 5. Passage 31 opens into a large
chamber 43 able to accept fluid to expand sealing member 34.
Chamber 43 is sealed by an o-ring or other seal at 39.
[0033] FIGS. 4 and 5 illustrate operation of the zonal isolation
tool 29. Sealing member 34 is initially expanded via fluid pressure
entering through inflation port 21 and passage 31 and into chamber
43 to an initial expansion pressure, causing sealing member 34 to
engage a wellbore or borehole wall 33. During this initial
expansion, moveable piston 13 and moveable sleeve 7 remain
essentially stationary. Once the defined initial pressure is
reached in chamber 43, member 19 moves to the left, blanking or
closing inflation port 21, and through hole 9 opens into the
hydroforming chamber 43, as illustrated in FIG. 5. After inflation
port 21 is blanked off or closed, a fluid 45 is introduced into
chamber 23 via through hole 11, causing moveable piston 13 and
moveable sleeve 7 to the right in FIG. 5. This in turn causes
sealing member 34 to compress axially and also to form a seal at or
near a leading edge 32. Fluid pressure 35A is also allowed to vent
from the annulus 6 into chamber 43 through passage 9 and pressure
35B is nearly equal to pressure 35A, allowing pressure
communication as indicated by the arrows from annulus 6 to chamber
43. Pressures 35A and 35B are higher than pressure 37. Sealing
member 34 (FIG. 5) may include an underlying carriage 36 (FIG. 13).
After actuation, differential pressure energizes the cup-type seal
34, vis-a-vis pressure in 35B which is greater than pressure in 37.
It should be noted that the fluid pressure used to activate the
sealing member 34 may be transmitted to the sealing member 34
and/or setting pistons 13 by various means. An embodiment receives
the tubing pressure via a setting tool 28 fitted with sealing
elements (o-rings, packing, or the like). When the sealing members
34 are situated in polished bores both above and below the zonal
isolation tool 29 or packer system, a pressure chamber is formed
that communicates with the packer element and setting pistons 13.
Pressure is applied thru the setting tool 28 via the surface
control equipment at the rig. Another embodiment utilizes the
differential pressure between the hydrostatic pressure downhole and
a trapped atmospheric chamber (not shown) integral to the packer
device. To activate the packer, a setting tool is used to break the
seal of the atmospheric trap chamber. Once freed, the pressure
differential may be used to hydroform the element, and further to
apply the compressive load as claimed. A similar embodiment may
compliment or even replace the trapped atmospheric chamber with a
pre-charged volume of nitrogen or other gas stored within the
packer. The result is to create a large differential pressure at
setting depth. Further embodiments may include activation by non
pressurizing means, such as mechanical ratcheting via an
electric-powered or hydraulic-powered downhole device, such as a
tractor run on slickline, e-line, or coiled tubing.
[0034] The zonal isolation tool 29 of this embodiment uses
hydroforming pressure as a first step to energize. Initial
inflation will affect a long length of sealing contact, assuring
good compliance to the open hole. After initial inflation, a
compressive load is applied via linear piston 7 (FIG. 5) to ensure
sealing point 32 near the leading end of the sealing element
structure.
[0035] The following are operational considerations, occurring
sequentially: (1) the tubing or base pipe 15 must be open to the
sealing member; (2) the initial inflation must stop when a defined
pressure within sealing member 34 is reached; (3) inflation port 21
must be assuredly blanked from tubing or base pipe 15; and (4) a
vent must open between sealing member 34 and annulus 6. As
illustrated in FIGS. 3-5, in certain embodiments a linear
compressive load from a moveable piston opens a vent such as
passage 9 in FIG. 5. The operational sequence must happen in the
proper order. FIGS. 6A-D illustrate this order. For example, if
vent 9 is opened prior to port 21 being blanked, then it would
become impossible to blank port 21 because open communication would
be established. To blank the port 21, an o-ring must un-seal, then
re-seal under dynamic conditions. Despite that limitation, other
combinations of this sequence may work in other embodiments, as
disclosed herein.
[0036] Referring to FIG. 7, several circumferential bands 40 may be
employed to prevent seal 34 from expanding radially while running
in hole. FIG. 7 illustrates schematically a simplified seal 34 with
bands 40. The right end 38 of seal 34 is fixed while the left end
44 is free to displace axially to the right. A ratchet ring 42
prevents axial movement to the left and thus helps seal 34 retain
elastic (potential) energy. Setting pressure is applied inside seal
34 via the packer setting tool 28 (FIG. 2). Bands 40 break when a
defined pressure is reached, allowing seal 34 to expand and contact
the formation wall 33 (FIGS. 4, 5). Another embodiment of this
feature may replace or complement the circumferential bands with a
poppet valve.
[0037] As illustrated in FIG. 8, the seal centerline in this
embodiment lies to the right of the contact centerline. This
behavior is conditioned by machining a notch 46 at the left end of
carriage 36 (FIG. 12).
[0038] A setting pressure of approximately 1,500 psi (about 10.3
megaPascals) is used to lengthen the contact length of seal 34 with
the formation (FIG. 8). Finally, the setting pressure is increased
to approximately 2,500 psi (about 17.2 megaPascals) to: (1) blank
port 21 (i.e. isolate inside of sealing member 34 from tubing or
base pipe 15 pressure); (2) vent sealing member 34 to annulus 6
through vent 9; and (3) axially compress the left end of sealing
member 34 to bias sealing point 32. The cup effect makes each seal
unidirectional, as illustrated in FIG. 9. When a bidirectional seal
is desired, at least two seals are required facing opposite
directions.
[0039] A venting port 60 (FIG. 10) may be placed on the
low-pressure side 37 of sealing member 34 to eliminate any
atmospheric trap that would be created between the inner sealing
element 50 outer sealing element 52. Total seal length is indicated
at 55, while slotted length is indicated at 56 if a slotted
carriage is employed.
[0040] Carriage 36 is illustrated in FIG. 13 as a cylinder having
one or more machined slots 58 in the axial direction. These slots
may be used to create individual beams 57 around the cylinder. The
left end of beams 57 may be notched as illustrated in detail in
FIG. 12 to simulate a "simply supported" beam. The right end may
not be notched; if it is not, the right end simulates a
"cantilevered" beam. Carriage 36 may also be un-slotted, that is, a
thin solid tube.
[0041] Inner sealing element 50 (FIG. 11), sometimes referred to as
a bladder, may be an elastomeric cylinder bonded near the ends of
carriage 36 to provide inflation capability to sealing member 34.
Inner sealing element 50 allows sealing member 34 to deploy under
internal pressure and to self-energize when differential pressure
across packer 20 is present. Because inner sealing element 50 may
be cold-bonded to metal at 51, a mechanically energized wedge 53
may be used to improve reliability. Inner sealing element 50 may
have a thickness ranging from about 0.10 to about 0.20 inch (from
about 0.25 to about 0.5 cm), and may comprise 80 durometer HNBR,
although the invention is not so limited, as other materials
discussed herein may be employed.
[0042] Outer sealing element 52 may be a rubber cylinder bonded to
the ends of the carriage 36 to provide sealing against the
formation. Outer sealing element 52 may have any thickness that
provides appropriate tear and wear resistance during conveyance and
good conformability to open-hole irregularities. Its thickness may
range from about 0.30 to about 0.70 inch (from about 0.76 to about
1.78 cm) to. Outer seal element 52 may also comprise 80 durometer
HNBR, and may comprise other materials as discussed herein.
[0043] Dashed circle "A" in FIG. 11 refers to a detailed view
illustrated in FIG. 12. The use of notched beams in support
carriage 36 helps control the axial location of the leading edge 32
of the contact point of sealing member 34 with the formation. By
allowing some degree of enhanced freedom in radial movement in or
near the notched end 46, the maximum deflection point (contact
point with maximum sealing pressure) shifts to the left of the
structure, as illustrated schematically in FIGS. 8 and 9. This
improves the overall sealing performance of sealing elements 50 and
52 under differential pressure and contributes to the long-term
reliability of the apparatus, particularly sealing member 34.
Additionally, individual beams 57 able to expand radially may be
more efficient than a continuous metallic cylinder in terms of
pressure required to achieve a given expansion and in terms of
conforming to irregular open hole geometries. Carriage 36 may be
made of, for example, 4130/4140 steel.
[0044] Anti-extrusion sheets 54 (FIG. 12) are, in the embodiment
illustrated, sheet metal cylinders located between carriage 36 and
outer sealing element 52 and inner bladder 50 to prevent extrusion
through the gaps formed as individual beams 57 in carriage 36
expand and separate. Anti-extrusion sheets 54 may be slotted or
un-slotted, and may have any thickness suitable for the intended
purpose, but will likely range in thickness from about 0.020 to
about 0.050 inch (from about 0.051 to about 0.13 cm).
Anti-extrusion sheets may comprise half-hardness low-carbon steel,
and if used are welded at 59 to carriage 36 at each end. Un-slotted
anti-extrusion sheets may allow removal of inner elastomeric
element 50 and a buffer layer. A buffer layer of non-metallic
material may be added between the innermost anti-extrusion sheet
metal cylinder 54 and inner elastomeric element 50. A buffer layer
may be used to prevent the sharp edges of the sheet metal cylinder
from puncturing the relatively thin layer of elastomer used for
inner elastomeric member 50. Suitable buffer layer materials
include polyetheretherketone (PEEK), and may be have a thickness
ranging from about 0.010 to about 0.030 inch (about 0.025 to about
0.076 cm).
[0045] FIGS. 14A and 14B illustrate schematic cross section views
at a screen pipe (FIG. 14A) and a packer (FIG. 14B). FIG. 14A
illustrates shunt tubes 62 for pumping gravel slurry or injection
fluids through a zonal isolation tool, and illustrates that the
outer circumference of the screen may have a different center 70
than the inner circumference 72. FIG. 14B illustrates alternate
fluid pathways for pumping gravel slurry or injection fluids
through a zonal isolation tool. Three pathways 64 illustrated
between a screen base pipe 66 and a packer base pipe 15, along with
three packer setting ports 68. Maintaining a sufficiently large
inner diameter is desirable to achieving full functionality for
such alternate fluid pathways. The design illustrated preserves an
equivalent area from for transport tubes. It is possible to move
the packer and screen base pipes onto different centers, which
would ease the disruption in the flow transition.
[0046] FIGS. 15A, 15B, and 15C illustrate schematically an
alternate embodiment of the invention 80. This embodiment differs
from embodiment 29 illustrated in FIGS. 3-5 in operation. After
initial seal pressure is reached in chamber 43 using fluid 41, a
moveable block 76 is moved to the right by fluid pressure 45, and
an O-ring 77 is caused to unseat into a small chamber 78. In the
same movement, inflation port 21 is blanked close, and high
pressure fluid in annulus 6 is allowed to pass through chamber 78
into chamber 43, causing the pressures 35A and 35B to become nearly
equivalent. Since there is no passage in block 76 to align with
inflation port 21 in base pipe 15, there is less chance in this
embodiment that annulus pressure will pass through port 21, and
port 21 is more easily blanked.
[0047] The outer elastomeric elements engage an adjacent surface of
a well bore, casing, pipe, tubing, and the like. Other elastomeric
layers between the inner and outer elastomeric members may be
provided for additional flexibility and backup. A non-limiting
example of an elastomeric element is rubber, but any elastomeric
materials may be used. A separate membrane may be used with an
elastomeric element if further wear and puncture resistance is
desired. A separate membrane may be interleaved between elastomeric
elements if the elastomeric material is insufficient for use alone.
The elastomeric material of outer sealing elements should be of
sufficient durometer for expandable contact with a well bore,
casing, pipe or similar surface. In some embodiments the
elastomeric material may be of sufficient elasticity to recover to
a diameter smaller than that of the wellbore to facilitate removal
therefrom. The elastomeric material should facilitate sealing of
the well bore, casing, or pipe in the inflated state.
[0048] "Elastomer" as used herein is a generic term for substances
emulating natural rubber in that they stretch under tension, have a
high tensile strength, retract rapidly, and substantially recover
their original dimensions (or even smaller in some embodiments).
The term includes natural and man-made elastomers, and the
elastomer may be a thermoplastic elastomer or a non-thermoplastic
elastomer. The term includes blends (physical mixtures) of
elastomers, as well as copolymers, terpolymers, and multi-polymers.
Examples include ethylene-propylene-diene polymer (EPDM), various
nitrile rubbers which are copolymers of butadiene and acrylonitrile
such as Buna-N (also known as standard nitrile and NBR). By varying
the acrylonitrile content, elastomers with improved oil/fuel swell
or with improved low-temperature performance can be achieved.
Specialty versions of carboxylated high-acrylonitrile butadiene
copolymers (XNBR) provide improved abrasion resistance, and
hydrogenated versions of these copolymers (HNBR) provide improve
chemical and ozone resistance elastomers. Carboxylated HNBR is also
known. Other useful rubbers include polyvinylchloride-nitrile
butadiene (PVC-NBR) blends, chlorinated polyethylene (CM),
chlorinated sulfonate polyethylene (CSM), aliphatic polyesters with
chlorinated side chains such as epichlorohydrin homopolymer (CO),
epichlorohydrin copolymer (ECO), and epichlorohydrin terpolymer
(GECO), polyacrylate rubbers such as ethylene-acrylate copolymer
(ACM), ethylene-acrylate terpolymers (AEM), EPR, elastomers of
ethylene and propylene, sometimes with a third monomer, such as
ethylene-propylene copolymer (EPM), ethylene vinyl acetate
copolymers (EVM), fluorocarbon polymers (FKM), copolymers of
poly(vinylidene fluoride) and hexafluoropropylene (VF2/HFP),
terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and
tetrafluoroethylene (VF2/HFP/TFE), terpolymers of poly(vinylidene
fluoride), polyvinyl methyl ether and tetrafluoroethylene
(VF2/PVME/TFE), terpolymers of poly(vinylidene fluoride),
hexafluoropropylene, and tetrafluoroethylene (VF2/HPF/TFE),
terpolymers of poly(vinylidene fluoride), tetrafluoroethylene, and
propylene (VF2/TFE/P), perfluoroelastomers such as
tetrafluoroethylene perfluoroelastomers (FFKM), highly fluorinated
elastomers (FEPM), butadiene rubber (BR), polychloroprene rubber
(CR), polyisoprene rubber (IR), IM, polynorbornenes, polysulfide
rubbers (OT and EOT), polyurethanes (AU) and (EU), silicone rubbers
(MQ), vinyl silicone rubbers (VMQ), fluoromethyl silicone rubber
(FMQ), fluorovinyl silicone rubbers (FVMQ), phenylmethyl silicone
rubbers (PMQ), styrene-butadiene rubbers (SBR), copolymers of
isobutylene and isoprene known as butyl rubbers (IIR), brominated
copolymers of isobutylene and isoprene (BIIR) and chlorinated
copolymers of isobutylene and isoprene (CIIR).
[0049] The expandable portions of the packers may include
continuous strands of polymeric fibers cured within the matrix of
the integral composite body comprising elastomeric elements.
Strands of polymeric fibers may be bundled along a longitudinal
axis of the expandable packer body parallel to longitudinal cuts in
a laminar interior portion of the expandable body. This can
facilitate expansion of the expandable portion of the composite
body yet provide sufficient strength to prevent catastrophic
failure of the expandable packer upon complete expansion.
[0050] The expandable portions of the tools may also contain a
plurality of overlapping reinforcement members. These members may
be constructed from any suitable material, for example high
strength alloys, fiber-reinforced polymers and/or elastomers,
nanofiber, nanoparticle, and nanotube reinforced polymers and/or
elastomers, or the like, all in a manner known and disclosed in
U.S. patent application Ser. No. 11/093390, filed on Mar. 30, 2005,
entitled "Improved Inflatable Packers", the entirety of which is
incorporated by reference herein.
[0051] The zonal isolation tools may be constructed of a composite
or a plurality of composites so as to provide flexibility. The
expandable portions of the tools may be constructed out of an
appropriate composite matrix material, with other portions
constructed of a composite sufficient for use in a wellbore, but
not necessarily requiring flexibility. The composite may be formed
and laid by conventional means known in the art of composite
fabrication. The composite may be constructed of a matrix or binder
that surrounds a cluster of polymeric fibers. The matrix can
comprise a thermosetting plastic polymer which hardens after
fabrication resulting from heat. Other matrices are ceramic,
carbon, and metals, but the invention is not so limited. The matrix
can be made from materials with a very low flexural modulus close
to rubber or higher, as required for well conditions. The composite
body may have a much lower stiffness than that of a metallic body,
yet provide strength and wear impervious to corrosive or damaging
well conditions. The composite tool body may be designed to be
changeable with respect to the type of composite, dimensions,
number of cable and fibrous layers, and shapes for differing
downhole environments.
[0052] It is understood that the zonal isolation tool may be any
type of isolation or separation device suitable for use in an
openhole environment. These include, but are not limited to,
hydroform-compress-energize packer, swellable elastomer packer,
inflatable ECP, or rubber-compression packer. Furthermore, it is
understood that multiple zonal isolation tools may be positioned or
oriented in any manner to generate uni-directional or
bi-directional sealing.
[0053] Referring now to the zonal isolation system illustrated in
FIGS. 16 and 21, as stated above, the open hole zonal isolation
system 80 may comprise the zonal isolation tool 29, the first
anchor 82, the second anchor 84, the upper polished bore receptacle
86, the lower polished bore receptacle 88, and the expansion joint
90. The zonal isolation system may also include the setting string
92 and the isolation string 94. The zonal isolation system 80
enables long term, openhole, hydraulic isolation while having the
ability to allow for expansion and/or contraction due to thermal
effects and maintain an effective sealing and anchoring system. The
zonal isolation system 80 also retains the differential pressure
rating for wider open hole internal diameters or changes in the
open hole internal diameter within the specified operating
envelope. After deployment, the system uses the differential
pressure to maintain energized seals and once the well is put into
production or injection, the differential of the pressure created
may re-energize the seal.
[0054] To enable setting of the zonal isolation tool 29 discussed
above, the upper polished bore receptacle 86 may be placed above
the zonal isolation tool and a lower polished bore receptacle 88
may be placed below the zonal isolation tool, as shown in FIGS. 16
and 21. The upper polished bore receptacle 86 may comprise a
tubular structure 96 having a first end 98 and a second end 100.
The first end 98 and the second end 100 of the upper polished bore
receptacle 86 may be threaded, preferably using premium threads.
The upper polished bore receptacle 86 may have a continuous inner
diameter 102 which is smooth and polished. The packing of the
setting tool 28 will be positioned within the inner diameter 102
during setting. Similarly, the lower polished bore receptacle 88
may comprise a tubular structure 104 having a first end 106 and a
second end 108. The lower polished bore receptacle 88 may also
include a continuous inner diameter 110 which is smooth, however, a
locating profile 112 machined as a feature in the inner diameter
110 of the lower polished bore receptacle 88 may be included to
assist in locating the setting tool 28 within the inner diameter of
the lower polished bore receptacle. The locating profile 112 is a
pattern of grooves 114 for engaging and seating fingers 116 of a
locating collet 118. The engagement of the locating profile 112 and
the fingers 116 provide an interference interaction between the
components so that in order for the locating profile and the
fingers to be disengaged, a specific amount of tensional force must
be applied to the work string. This provides indication at the
surface of the well that the zonal isolation tool has reached its
intended position downhole. The locating profile is especially
beneficial in long, horizontal, openhole completions. It is
understood that the zonal isolation system may include more than
two polished bore receptacles or one polished bore receptacle with
a communication port that is attached to the zonal isolation
tool.
[0055] The zonal isolation system 80 may also include a pair of
anchors for preventing movement of the zonal isolation tool 29
relative to the openhole by gripping the borehole wall, as shown in
FIG. 16. To prevent transmission of additional loads and movements
into adjacent tubulars, a piston effect resulting from a fully
expanded zonal isolation tool may be isolated using the pair of
anchors. The pair of anchors comprises a first anchor 82 and a
second anchor 84 which are located generally adjacent to the zonal
isolation tool 29. The first anchor 82 may be placed above the
zonal isolation tool and the second anchor 84 may be placed below
the zonal isolation tool. The anchors 82, 84 are located in between
the zonal isolation tool 29 and the polished bore receptacles 86,
88 and may be activated by using the setting tool 28 used for
setting the zonal isolation tool either simultaneously or in the
same trip. The anchors may be attached to the polished bore
receptacles via threads. It is understood that the zonal isolation
system may be deployed having only one anchor, multiple anchors, or
in some cases no anchor will be used.
[0056] The first anchor 82 and the second anchor 84 support tensile
and compressive forces on the tubular string, and provide a
torsional load path. The effectiveness of the anchors may be a
function of the friction coefficient of the openhole and the radial
load applied against the formation. The coefficient of friction is
related to the type of formation and fluids present downhole in the
region of setting the zonal isolation system. In order to protect
the formation from fracture, it is important that the radial loads
remain below the fracture pressure of the formation. Therefore, the
load should be distributed over a large surface area.
[0057] The anchors used with the zonal isolation system may be of
several types. For example, as illustrated in FIG. 17, a classical
slip type anchor 120 may be used. The classical slip anchor 120
comprises a cone that pushes slips outward toward the openhole wall
until the slips make contact with the openhole wall. Friction
against the formation maintains the anchor in position. To initiate
contact with the formation, a hydraulic piston may be used, and a
ratchet maintains the anchor in position and prevents the anchor
from relaxing or moving.
[0058] A two-stage slip anchor 122 may also be used and contains a
pair of support slips on the extremities, or ends of the anchor,
and a pair of principal slips in a center of the anchor, as shown
in FIG. 18. The pair of support slips is based on a C-ring design,
and the pair of principal slips are based on a barrel slip design.
Contact is initiated in the same manner as in the classical slip
anchor discussed above.
[0059] In the alternative, a self-locking anchor 124 may be used,
as illustrated in FIG. 19. The self-locking anchor 124 realizes
increased friction and contact pressure with the formation as the
axial forces are increased. The self-locking anchor may comprise a
collet-slip design having blades similar to collet fingers, and
machined teeth similar to a barrel slip. The collet fingers may be
compressed until the collet fingers expand outward and contact the
formation wall. The internal part of the self-locking anchor
maintains the outward force against the openhole, thus providing
the anchor.
[0060] It is understood that a penetrator-type anchor system 126
shown in FIG. 20 may be used and consists of arms, or spikes, that
extend outward and bury/anchor into the formation. It is also
understood that other types of anchors may be used with the zonal
isolation system.
[0061] Referring to FIGS. 16 and 21, the zonal isolation system 80
may also include the expansion joint 90 (also called a compaction
joint) to allow for movement due to external forces caused by
temperature fluctuations downhole. The expansion joint 90 also
allows for the movement of components of the zonal isolation system
and tubulars that may be adjacent to the zonal isolation system.
The expansion joint 90 may be attached to the polished bore
receptacle using a threaded connection.
[0062] The tubulars attached to the zonal isolation system may
expand and contract due to thermal changes. The expansion joint 90
allows for contraction and expansion of that tubular basepipe. The
expansion joint 90 is capable of supporting the weight of the
tubular string by allowing for changes in length but still
maintaining pressure integrity from its inner diameter to its outer
diameter. The expansion joint may be inactive (locked) during
installation and then activated (unlocked) during the setting and
operation stages.
[0063] Referring to FIG. 16, the setting string 92 may be used in
conjunction with the setting tool 28 discussed above to deploy the
zonal isolation tool 29. The setting string 92 may be installed
within the zonal isolation system for activating one or more of the
components above in the zonal isolation system. The setting string
92 includes sealing elements that are positioned at the time of
setting in the pair of polished bore receptacles above and below
the zonal isolation tool. By positioning the setting string in this
manner, a pressure chamber is formed that communicates with the
zonal isolation tool allowing for activation of the zonal isolation
tool and/or the pair of anchors.
[0064] The setting string 92 may set all of the components in a
single trip simultaneously or one device at a time. The setting
string 92 has several features to assist in the setting of the
described components. The collet 118 may be attached to the setting
string 92 which mates with the polished bore receptacle which
includes the locating profile 112 discussed above. The setting
string 92 may also comprise ports, checks, or valves to facilitate
wash-down or debris removal capabilities while running in the
borehole (not shown). These features assist operators specifically
in long, horizontal, openhole completions. It is understood that
the setting string may also comprise devices to set other
completion equipment during the same single trip, such as
production packers, sump packers, and formation isolation
valves.
[0065] Referring to FIG. 16, the internal tubing string used to
transport production or injection fluids is the isolation string
94. The isolation string 94 may be installed after setting the
zonal isolation system to maintain separation of zones during
production or injection. The isolation string 94 utilizes the
polished bore receptacles to complete the zonal isolation within
the tubing string. The isolation string 94 may include a seal which
may interact with the polished bore receptacles to effectively
isolate the desired zone. It is understood that the type of seal
used may be bonded seals, chevron seals or any seal which
effectively seals the zones. Additionally, the setting string may
include seals which seal on the inside of the polished bore
receptacle to separate the zones.
[0066] The isolation string 94 maintains pressure integrity along
its length, and provides the remaining separation for zonal
isolation. The isolation string may be installed in place of the
setting string after all of the components have been activated and
are operational. The isolation string 94 may include a packing
stack to seal in the lower polished bore receptacle which is
located downhole, and may also include a locating collet to mate
with the locating profile 112 on the lower polished bore
receptacle.
[0067] It is understood that the zonal isolation tools as described
and claimed herein may connect in any number of ways to their
wellbore counterparts. Each end of the zonal isolation system may
be adapted to be attached in a tubular string. This can be through
threaded connections, friction fits, expandable sealing means, and
the like, all in a manner well known in the oil tool arts. Although
the term tubular string is used, this can include jointed or coiled
tubing, casing or any other equivalent structure for positioning
tools as disclosed herein. The materials used can be suitable for
use with production fluid or with an inflation fluid.
[0068] The embodiments described herein may be used in an open hole
for sandface completions utilizing stand-alone screens. However,
the embodiments described herein may also be adapted for use in
open-hole gravel pack sand control applications. In the latter
role, the embodiments described herein may incorporate the use of
alternate path transport and shunt tubes to assist gravel slurry
placement. Additionally, the embodiments described herein may be
used in sand control applications utilizing expandable screens.
Aside from the various sand control applications listed, the
embodiments described herein may also be used as an annular
barrier, or for compartmentalizing long open-hole sections.
[0069] Although only a few exemplary embodiments of this invention
have been described in detail above, those skilled in the art will
readily appreciate that many modifications are possible in the
exemplary embodiments without materially departing from the spirit
of this invention. Accordingly, all such modifications are intended
to be included within the scope of this invention as defined in the
following claims.
* * * * *