U.S. patent application number 16/591086 was filed with the patent office on 2020-01-30 for isolation head and method of use for oilfield operations.
The applicant listed for this patent is TECH ENERGY PRODUCTS, L.L.C.. Invention is credited to Barton Hickie.
Application Number | 20200032615 16/591086 |
Document ID | / |
Family ID | 67844458 |
Filed Date | 2020-01-30 |
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United States Patent
Application |
20200032615 |
Kind Code |
A1 |
Hickie; Barton |
January 30, 2020 |
ISOLATION HEAD AND METHOD OF USE FOR OILFIELD OPERATIONS
Abstract
A method and apparatus according to which at least part of a
wellhead is fluidically isolated from excessive pressures,
temperatures, and/or flow rates during a wellbore operation using
an isolation head, the isolation head including an isolation spool
and an isolation sleeve.
Inventors: |
Hickie; Barton; (Oklahoma
City, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
TECH ENERGY PRODUCTS, L.L.C. |
BOSSIER CITY |
LA |
US |
|
|
Family ID: |
67844458 |
Appl. No.: |
16/591086 |
Filed: |
October 2, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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16296772 |
Mar 8, 2019 |
10450832 |
|
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16591086 |
|
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62641058 |
Mar 9, 2018 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 34/02 20130101;
E21B 2200/06 20200501; E21B 43/26 20130101 |
International
Class: |
E21B 34/02 20060101
E21B034/02 |
Claims
1. An apparatus, comprising: an isolation spool adapted to be
operably coupled to a wellhead; and an isolation sleeve operably
coupled to the isolation spool and moveable relative thereto;
wherein, when the isolation spool is operably coupled to the
wellhead, the isolation sleeve is adapted to move, relative to the
isolation spool, to sealingly engage first and second packoff
surfaces; and wherein, when the isolation sleeve is sealingly
engaged with the first and second packoff surfaces, the isolation
sleeve is adapted to isolate at least a portion of the wellhead
from a fluid flowing through the apparatus.
2. The apparatus of claim 1, further comprising: an actuator
operably coupling the isolation sleeve to the isolation spool and
adapted to move the isolation sleeve relative to the isolation
spool.
3. The apparatus of claim 2, wherein the actuator comprises: a rack
gear operably associated with the isolation sleeve; and a pinion
gear engageable with the rack gear to move the isolation
sleeve.
4. The apparatus of claim 1, wherein the isolation spool defines an
internal passage; and wherein the isolation sleeve extends within
the internal passage of the isolation spool.
5. The apparatus of claim 1, further comprising: an isolation valve
connected to the isolation spool; wherein the isolation valve is
positioned between the first and second packoff surfaces when the
isolation spool is operably coupled to the wellhead; and wherein
the at least a portion of the wellhead comprises the isolation
valve so that, when the isolation spool is operably coupled to the
wellhead and the isolation sleeve is sealingly engaged with the
first and second packoff surfaces, the isolation sleeve is adapted
to isolate the isolation valve from the fluid flowing through the
apparatus.
6. The apparatus of claim 5, further comprising a fluid line
adapted to: bypass the isolation valve, and place the wellhead and
the apparatus in fluid communication so that first and second fluid
pressures acting axially on opposing end portions, respectively, of
the isolation sleeve are equalized with a third fluid pressure in
the wellhead.
7. The apparatus of claim 1, further comprising one or more valves
connected to the isolation spool and adapted to isolate, from
atmosphere, first and second fluid pressures acting axially on
opposing end portions, respectively, of the isolation sleeve.
8. The apparatus of claim 7, further comprising a fluid line
adapted to place the wellhead and the apparatus in fluid
communication so that the first and second fluid pressures acting
axially on the opposing end portions, respectively, of the
isolation sleeve are equalized with a third fluid pressure in the
wellhead.
9. The apparatus of claim 7, further comprising an isolation valve
connected to the isolation spool so that: the isolation spool is
positioned between the isolation valve and the one or more valves;
and the isolation valve is positioned between the first and second
packoff surfaces when the isolation spool is operably coupled to
the wellhead; wherein the at least a portion of the wellhead
comprises the isolation valve so that, when the isolation spool is
operably coupled to the wellhead and the isolation sleeve is
sealingly engaged with the first and second packoff surfaces, the
isolation sleeve is adapted to isolate the isolation valve from the
fluid flowing through the apparatus.
10. The apparatus of claim 9, further comprising a fluid line
adapted to: bypass the isolation valve, and place the wellhead and
the apparatus in fluid communication so that the first and second
fluid pressures acting axially on the opposing end portions,
respectively, of the isolation sleeve are equalized with a third
fluid pressure in the wellhead.
11. The apparatus of claim 1, further comprising the first and
second packoff surfaces.
12. The apparatus of claim 1, further comprising the first packoff
surface.
13. The apparatus of claim 1, further comprising the second packoff
surface.
14. The apparatus of claim 1, further comprising the wellhead.
15. The apparatus of claim 1, further comprising a frac tree, the
frac tree comprising one or more valves connected to the isolation
spool and adapted to isolate, from atmosphere, first and second
fluid pressures acting axially on opposing end portions,
respectively, of the isolation sleeve.
16. A method, comprising: isolating, from atmosphere, first and
second fluid pressures acting axially on opposing end portions,
respectively, of an isolation sleeve; equalizing the first and
second fluid pressures acting axially on the opposing end portions,
respectively, of the isolation sleeve with a third fluid pressure
in a wellhead, the wellhead comprising an isolation valve; after
equalizing the first and second fluid pressures with the third
fluid pressure, opening the isolation valve of the wellhead; and
after opening the isolation valve of the wellhead, sealingly
engaging the isolation sleeve with first and second packoff
surfaces, wherein the isolation valve of the wellhead is positioned
between the first and second packoff surfaces.
17. The method of claim 16, further comprising: isolating, using
the isolation sleeve, the isolation valve from fluid flowing
through the wellhead.
18. The method of claim 16, wherein sealingly engaging the
isolation sleeve with the first and second packoff surfaces
comprises: moving the isolation sleeve, relative to the isolation
valve, so that the isolation sleeve extends through the isolation
valve.
19. The method of claim 18, wherein the equalization of the first
and second fluid pressures with the third fluid pressure
facilitates the movement of the isolation sleeve.
20. The method of claim 16, wherein equalizing the first and second
fluid pressures with the third fluid pressure comprises connecting
a fluid line to the wellhead; wherein the fluid line bypasses the
isolation valve of the wellhead; and wherein the first and second
fluid pressures are equalized with the third fluid pressure via the
fluid line.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation of U.S. application Ser.
No. 16/296,772, filed Mar. 8, 2019, which claims the benefit of the
filing date of, and priority to, U.S. Application Ser. No.
62/641,058, filed Mar. 9, 2018, the entire disclosures of which are
hereby incorporated herein by reference.
TECHNICAL FIELD
[0002] The present disclosure relates generally to oil or gas
wellbore equipment, and, more particularly, to an isolation head
for fluidically isolating at least part of a wellhead from
excessive pressures, temperatures, and/or flow rates during a
wellbore operation.
BACKGROUND
[0003] Many oilfield operations expose wellhead equipment at the
surface of a subterranean wellbore to extreme conditions--examples
of such oilfield operations include cementing, acidizing,
injecting, fracturing, and/or gravel packing of the wellbore.
Isolation tools are available that attempt to protect wellhead
equipment from excessive pressures, temperatures, and flow rates
encountered during oilfield operations, but these isolation tools
are often insufficient to handle extreme duty cycles. For example,
during fracturing of the wellbore, the wellhead equipment may be
subject to a fluid pressure of up to 20,000 psi or more. Some
isolation tools are configured to position and secure a mandrel
within a wellhead, which mandrel includes a packoff assembly
adapted to isolate the wellhead from fluid flowing through the
mandrel to and from the wellbore. However, the high pressures and
flow rates encountered during wellbore fracturing operations often
cause packoff assemblies to "lift-off" from a sealing surface,
allowing the fracturing fluid or slurry to leak or blow by the
packoff assembly into the wellhead equipment. For this reason
(among others), existing isolation tools are susceptible to
blowouts (i.e., the uncontrolled release of oil and/or gas from the
wellbore). To make matters worse, if a blowout does occur, there is
no simple way to stop the blowout using existing isolation tools.
Therefore, what is needed is an apparatus, system, or method that
addresses one or more of the foregoing issues, and/or one or more
other issues.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1A is a diagrammatic illustration of a fracturing (or
"frac") system including an isolation head, the isolation head
including an isolation spool and an isolation sleeve, the isolation
sleeve being positioned so as not to fluidically isolate the
wellhead from fluid flowing through the isolation head, according
to one or more embodiments of the present disclosure.
[0005] FIG. 1B is an elevational view of the frac system of FIG.
1A, according to one or more embodiments of the present
disclosure.
[0006] FIG. 2 is a perspective cross-sectional view of a tubing
spool of the frac system of FIG. 1B, according to one or more
embodiments of the present disclosure.
[0007] FIG. 3 is a perspective view of an isolation head of the
frac system of FIG. 1B, according to one or more embodiments of the
present disclosure.
[0008] FIG. 4 is a cross-sectional view of an isolation sleeve of
the isolation head of FIG. 3, according to one or more embodiments
of the present disclosure.
[0009] FIG. 5 is a perspective view of an actuator of the isolation
head of FIG. 3, according to one or more embodiments of the present
disclosure.
[0010] FIG. 6 is a perspective view of an actuator support flange
of the isolation head of FIG. 3, according to one or more
embodiments of the present disclosure.
[0011] FIG. 7 is a cross-sectional view of the isolation head of
FIG. 3 taken along the line 7-7 of FIG. 3, according to one or more
embodiments of the present disclosure.
[0012] FIG. 8 is a cross-sectional view of the isolation head of
FIG. 3 taken along the line 8-8 of FIG. 3, according to one or more
embodiments of the present disclosure.
[0013] FIG. 9 is an elevational view of the frac system of FIG. 1B
in a first operational state or configuration, according to one or
more embodiments of the present disclosure.
[0014] FIG. 10 is an elevational view of the frac system of FIG. 9
in a second operational state or configuration, according to one or
more embodiments of the present disclosure.
[0015] FIG. 11A is a diagrammatic illustration of the frac system
similar to that shown in FIG. 1A, except that the isolation sleeve
is repositioned to fluidically isolate at least a portion of a
wellhead from fluid flowing through the isolation head, according
to one or more embodiments of the present disclosure.
[0016] FIG. 11B is a partial cross-sectional view of the frac
system of FIG. 10 in a third operational state or configuration,
which third operational state or configuration is also illustrated
diagrammatically in FIG. 11A, according to one or more embodiments
of the present disclosure.
[0017] FIG. 11C is an enlarged view of a portion of FIG. 11B,
according to one or more embodiments of the present disclosure.
[0018] FIG. 11D is an enlarged view of another portion of FIG. 11B,
according to one or more embodiments of the present disclosure.
[0019] FIG. 12 is a flow diagram of a method for implementing one
or more embodiments of the present disclosure.
[0020] FIG. 13 is a diagrammatic illustration of a computing node
for implementing one or more embodiments of the present
disclosure.
DETAILED DESCRIPTION
[0021] Referring to FIG. 1A, in an embodiment, a fracturing (or
"frac") system is diagrammatically illustrated and generally
referred to by the reference numeral 1. The frac system 1 is
adapted to communicate fluid (e.g., containing a carrier fluid and
a particulate material) into a wellbore 2 that traverses a
subterranean formation for various oilfield operations such as, for
example, fracturing or gravel packing operations. In this regard,
the frac system 1 can be designed to communicate various types of
fluids desired to be deposited into the wellbore 2 for a particular
oil and gas operation; for example, the fluid can be a fracturing
or gravel packing fluid used in fracturing or gravel packing
operations. The frac system 1 includes an isolation head 10. In
some embodiments, as in FIG. 1A, the isolation head 10 includes an
isolation spool 58, an isolation sleeve 60, and an actuator 72. The
isolation spool 58 includes an upper packoff surface 3. The
isolation sleeve 60 includes an upper packoff assembly 86, a
mandrel assembly 4, and a lower packoff assembly 100.
[0022] The actuator 72 is operably associated with the isolation
spool 58. In addition, the actuator 72 is operably associated with,
and adapted to displace, the isolation sleeve 60. In some
embodiments, as in FIG. 1A, the actuator 72 facilitates movement of
the isolation sleeve 60 in opposing directions, as indicated by
arrows 5 and 6. The actuator 72 may be, include, or be part of,
motor(s), cylinder actuator(s), other actuators powered by
electric, pneumatic, or hydraulic power, or any combination
thereof. In some embodiments, one or more position sensors can be
operably associated with the isolation sleeve 60 and adapted to
detect the position of the isolation sleeve 60. The position
sensor(s) may be, include, or be part of encoder(s), linear
position transducer(s), wire potentiometer(s), another transducer
capable of translating linear motion into a mechanical or
electrical signal, or any combination thereof.
[0023] The frac system 1 is operably associated with a wellhead 12,
which wellhead 12 serves as the surface termination of the wellbore
2. The wellhead 12 includes a lower packoff surface 7. A valve
stack 20 is operably associated with the isolation head 10,
opposite the wellhead 12. A fracturing (or "frac") tree 28 is
operably associated with the valve stack 20. In some embodiments,
the valve stack 20 is part of the frac tree 28; accordingly, the
valve stack 20 and the frac tree 28 may be collectively referred to
herein as the "frac tree". One or more fracturing (or "frac") pumps
8 may be operably associated with, and adapted to pump fluid to,
the frac tree 28. Any fluid communicated to the frac tree 28 from
the frac pump(s) 8 travels into the wellbore 2 only after passing
through the wellhead 12. In some embodiments, one or more other oil
and gas tools can be operably associated with the wellhead 12 and
located between the isolation head 10 and the wellhead 12.
Accordingly, in such embodiments, any fluid communicated to the
frac tree 28 from the frac pump(s) 8 travels into the wellbore 2
only after passing through the other oil and gas tool(s) and the
wellhead 12.
[0024] In operation, the actuator 72 moves the isolation sleeve 60
relative to the isolation spool 58 and the wellhead 12 to sealingly
engage the upper and lower packoff assemblies 86 and 100 with the
upper and lower packoff surfaces 3 and 7, respectively. When the
upper and lower packoff assemblies 86 and 100 are sealingly engaged
with the upper and lower packoff surfaces 3 and 7, respectively,
the isolation sleeve 60 isolates at least a portion of the wellhead
12 from fluid flowing through the isolation head 10. However, as
shown in FIG. 1A, prior to the upper and lower packoff assemblies
86 and 100 being sealingly engaged with the upper and lower packoff
surfaces 3 and 7, respectively, the isolation sleeve 60 does not
isolate the wellhead 12 from fluid flowing through the isolation
head 10. The operation of the frac system 10 and, more
particularly, the isolation spool 10, will be described in further
detail below.
[0025] Referring to FIG. 1B, with continuing reference to FIG. 1A,
in an embodiment, the isolation head 10 is connected to the
wellhead 12 and is adapted to fluidically isolate at least a
portion of the wellhead 12 from fluid flowing through the isolation
head 10. The wellhead 12 is connected at the surface termination of
the wellbore 2 and includes one or more wellhead components, such
as, for example, a casing head 14, a tubing spool 16 connected to
the casing head 14, and an isolation valve 18 connected to the
tubing spool 16. In some embodiments, at least the isolation head
10 and the lower packoff surface 7 of the wellhead 12 together form
a wellhead isolation tool. In some embodiments, the casing head 14
and/or the tubing spool 16 is/are adapted to receive a casing
string and/or a tubing string, one or both of which may include a
bit guide for guiding downhole tools into the wellbore 2. In some
embodiments, at least an uppermost portion of such a casing string
can be considered part of the wellhead 12. In some embodiments, in
addition, or instead, at least an uppermost portion of such a
tubing string can be considered part of the wellhead 12. In
addition to, or instead of, the casing head 14, the tubing spool
16, and the isolation valve 18, the wellhead 12 may include one or
more other wellhead components, such as, for example, a casing
spool, a casing hanger, a tubing head, a tubing hanger, a packoff
seal, a valve tree, a blowout preventer, choke equipment, another
wellhead component, or any combination thereof.
[0026] Referring still to FIG. 1B, the valve stack 20 is connected
to the isolation head 10, opposite the wellhead 12, and includes
valves 22 and 24 configured to either prevent or allow the flow of
a fluid through the valve stack 20. The valve 22 is connected to
the isolation head 10. The valve stack 20 also includes a fluid
block 26 connected between the valves 22 and 24. The fluid block 26
includes an internal passage through which a fluid is communicated
between the valves 22 and 24. The fluid block 26 may also include
one or more diverter passages extending into the internal passage
of the fluid block 26, and through which fluid may be communicated
to and/or from the internal passage of the fluid block 26. In some
embodiments, in addition to, or instead of, the valves 22 and 24,
the valve stack 20 includes one or more other valves.
[0027] In some embodiments, to facilitate, for example, fracturing
and/or gravel packing of the wellbore 2, the frac tree 28 is
connected to the valve stack 20, opposite the isolation head 10, as
shown in FIG. 1B. The frac tree 28 includes a goat head 30 and a
swab valve 32. The goat head 30 is connected to the valve stack 20
and includes a plurality of fluid inlets 34 adapted to communicate,
for example, fracturing or gravel packing fluid to the wellbore 2,
as indicated by the arrows 36 in FIG. 1B. The swab valve 32 is
connected to the goat head 30, opposite the valve stack 20, and
provides vertical access to the wellbore 2 for well interventions
(e.g., using wireline or coiled tubing). In some embodiments, a
blind flange 33 is connected to the swab valve 32 to prevent, or at
least reduce, fluid from leaking to atmosphere from the swab valve
32, and/or to provide a lifting point for lowering the frac tree 28
onto the valve stack 20.
[0028] Referring to FIG. 2 with continuing reference to FIG. 1B, in
an embodiment, the tubing spool 16 of the wellhead 12 includes a
lower flange 38, a leak investigation port 40, and upper flange 42,
a plurality of lockdown pins 44, a body 46, an internal passage 48,
access ports 50 and 52, and a landing shoulder 54. The lower flange
38 is connectable to the casing head 14 (shown in FIG. 1B). The
leak investigation port 40 is formed in the lower flange 38 and
configured to permit pressure testing of the bit guide and or other
components of the wellhead 12. The isolation valve 18 (or another
component of the wellhead 12) is configured to be connected to the
upper flange 42 of the tubing spool 16. The body 46 extends between
the lower flange 38 and the upper flange 42, and the internal
passage 48 extends longitudinally through the lower flange 38, the
body 46, and the upper flange 42. The internal passage 48 defines
annular recesses 56 in the tubing spool 16 adjacent the lower
flange 38, at least one of the annular recesses 56 being configured
to accommodate the bit guide. The access ports 50 and 52 extend
radially through the body 46 and into the internal passage 48. Once
the desired hydrocarbon production has been established (e.g.,
after fracturing and/or gravel packing operations have been
completed), the landing shoulder 54 of the tubing spool 16 is
configured to support a tubing hanger from which production tubing
extends into the wellbore 2. In this regard, the plurality of
lockdown pins 44 are configured to secure the tubing hanger against
the landing shoulder 54. In some embodiments, the lower packoff
surface 7 (shown in FIG. 1A) may be defined in the tubing spool 16
by, for example, the internal passage 48. Alternatively, the lower
packoff surface 7 may be defined elsewhere in the tubing spool 16
or in some other component of the wellhead 12.
[0029] Referring to FIG. 3 with continuing reference to FIG. 1B, in
an embodiment, the isolation head 10 includes the isolation spool
58 and the isolation sleeve 60. The isolation spool 58 includes a
lower flange 62, an upper flange 64, a plurality of lockdown pins
66, a spool body 68, an internal passage 70, the actuator 72, and
actuator support flanges 74 and 76. The lower flange 62 of the
isolation spool 58 is connectable to the isolation valve 18 (or
another component of the wellhead 12). Similarly, the valve stack
20 is connectable to the upper flange 64 of the isolation spool 58.
The spool body 68 extends between the lower flange 62 and the upper
flange 64, and the internal passage 70 extends longitudinally
through the lower flange 62, the spool body 68, and the upper
flange 64. In some embodiments, the upper packoff surface 3 (shown
in FIG. 1A) may be defined in the isolation spool 58 by, for
example, the internal passage 70. The actuator support flanges 74
and 76 are connected to the spool body 68 of the isolation spool 58
and are each configured to support at least respective portions of
the actuator 72, as will be described in further detail below. The
lockdown pins 66 are configured to secure the isolation sleeve 60
against a landing shoulder 78 (shown in FIG. 11C) of the isolation
spool 58, as will be described in further detail below.
[0030] Referring to FIG. 4, in an embodiment, the mandrel assembly
4 of the isolation sleeve 60 includes a mandrel 80 and a mandrel
extension 82. The mandrel 80 includes a mandrel body 84, the upper
packoff assembly 86, an internal passage 88, an internal connection
90, an external surface 92, and rack gears 94 and 96. The upper
packoff assembly 86 is connected to an upper end portion of the
mandrel body 84 and is configured to seal against the upper packoff
surface 3 (shown in FIG. 1A) of the isolation spool 58, as will be
described in further detail below. The upper packoff assembly 86
has a diameter D1. In some embodiments, the upper packoff assembly
86 and the mandrel body 84 are integrally formed. The internal
passage 88 extends longitudinally through the mandrel body 84 and
the upper packoff assembly 86. The internal connection 90 is formed
in an end portion of the mandrel body 84 opposite the upper packoff
assembly 86. In some embodiments, as FIG. 4, the internal
connection 90 is a female threaded connection. The rack gears 94
and 96 are connected to the external surface 92 of the mandrel body
84 and extend longitudinally along different sides of the mandrel
body 84. In some embodiments, the rack gears 94 and 96 are
integrally formed with the mandrel body 84.
[0031] Referring still to FIG. 4, the mandrel extension 82 includes
a mandrel extension body 98, the lower packoff assembly 100, an
internal passage 102, an external surface 104, and an external
connection 106. The lower packoff assembly 100 is connectable to a
lower end portion of the mandrel extension body 98 and is
configured to seal against, for example, the lower packoff surface
7 (shown in FIG. 1A) of the wellhead 12, as will be described in
further detail below. The lower packoff assembly 100 has a diameter
D2. In some embodiments, the diameter D2 of the lower packoff
assembly 100 less than the diameter D1 of the upper packoff
assembly 86. In some embodiments, the lower packoff assembly 100
and the mandrel extension body 98 are integrally formed. The
internal passage 102 extends longitudinally through the mandrel
body 84 and the lower packoff assembly 100. The external connection
106 is formed in an end portion of the mandrel extension body 98
opposite the lower packoff assembly 100. In some embodiments, as in
FIG. 4, the external connection 106 is a male threaded connection.
The external connection 106 of the mandrel extension 82 is
connectable to the internal connection 90 of the mandrel 80.
Alternatively, in some embodiments, the internal connection 90 of
the mandrel 80 is omitted and replaced with an external connection,
and the external connection 106 of the mandrel extension 82 is
omitted and replaced with an internal connection that is
connectable to the external connection of the mandrel 80.
[0032] Referring to FIG. 5, in an embodiment, the actuator 72
includes an input driveshaft 108, an input gearbox 110 connected to
the input driveshaft 108, output gearboxes 111 and 112 connected to
the input gearbox 110, output driveshafts 114 and 116 connected to
the output gearboxes 111 and 112, respectively, and pinion gears
118 and 120 connected to the output driveshafts 114 and 116,
respectively. The pinion gears 118 and 120 matingly engage the rack
gears 94 and 96, respectively, connected to the mandrel body 84. As
a result, rotation of the input driveshaft 108 in one direction
(e.g., clockwise) drives the input gearbox 110 and the output
gearboxes 111 and 112 so that the output driveshafts 114 and 116
rotate the pinion gears 118 and 120 in directions indicated by the
curvilinear arrows 122 and 124, respectively, thereby causing the
isolation sleeve 60 to move longitudinally in a direction indicated
by the straight arrow 126. Similarly, rotation of the input
driveshaft 108 in the opposite direction (e.g., counterclockwise)
drives the input gearbox 110 and the output gearboxes 111 and 112
so that the output driveshafts 114 and 116 rotate the pinion gears
118 and 120 in directions opposite the directions indicated by the
curvilinear arrows 122 and 124, respectively, thereby causing the
isolation sleeve 60 to move longitudinally in a direction opposite
the direction indicated by the straight arrow 126.
[0033] Referring to FIG. 6, in an embodiment, the actuator support
flanges 74 and 76 each include a blind flange 128 and support
plates 130 and 132 connected to the blind flange 128. The support
plates 130 and 132 together form a bearing housing 134 that
accommodates one or the other of the pinion gears 118 and 120 and
bearings 136 and 138 (shown in FIG. 7) that are configured to
rotatably support one or the other of the output driveshafts 114
and 116. The support plates 130 and 132 include bearing retainers
140 and 142 (shown in FIG. 7), respectively, connected thereto for
retaining the bearings 136 and 138 and one or the other of the
pinion gears 118 and 120 within the bearing housing 134.
[0034] Turning also to FIGS. 7 and 8, the spool body 68 includes
access passages 144 and 146 extending into the internal passage 70
of the isolation spool 58, and drive ports 148 extending into the
access passages 144 and 146, respectively. The bearing housings 134
of the actuator support flanges 74 and 76 extend within the access
passages 144 and 146, respectively, so that the pinion gears 118
and 120 matingly engage the rack gears 94 and 96, respectively,
connected to the mandrel body 84. The drive ports 148 each
accommodate one or the other of the output driveshafts 114 and 116.
Moreover, as shown in FIG. 7, annular recesses 150 are formed in
the spool body 68 at end portions of the drive ports 148 opposite
the access passages 144 and 146, respectively, the annular recesses
150 each accommodate a seal 152 (e.g., a packing seal or the like)
to prevent, or at least reduce, fluid from leaking through the
drive ports 148 to atmosphere. Finally, as shown in FIG. 8,
corresponding pairs of annular grooves 154 and 156 are formed in
the isolation spool 58 and the actuator support flanges 74 and
76--each pair of annular grooves 154 and 156 accommodates a seal
158 to prevent, or at least reduce, fluid from leaking through the
access passages 144 and 146 to atmosphere.
[0035] In operation, in an embodiment, as illustrated in FIGS. 9,
10, and 11A-11D, with continuing reference to FIGS. 1A, 1B, and
2-8, the isolation head 10 is used to fluidically isolate at least
a portion of the wellhead 12 from fluid flowing through the
isolation head 10. In order to fluidically isolate the at least
part of the wellhead 12, the isolation head 10 is first connected
to the isolation valve 18 (or another component) of the wellhead
12, as shown in FIG. 9. Before the isolation head 10 is connected
to the wellhead 12, the isolation valve 18 is stroked to, or
remains in, a closed configuration to prevent the communication of
wellbore fluids to atmosphere. In some embodiments, when the
isolation head 10 is connected to the wellhead 12, the isolation
sleeve 60, including the upper packoff assembly 86 and at least
part of the mandrel body 84, protrudes upwardly (as viewed in FIG.
9) from the internal passage 70 and above the upper flange 64 of
the isolation head 10. Once the isolation head 10 has been so
connected to the wellhead 12, the valve stack 20 is suspended over
the isolation head 10 and lowered using a cable 160 in a downward
direction 162. In some embodiments, a blind flange 163 is connected
to the valve 24 to prevent, or at least reduce, fluid from leaking
to atmosphere from the valve stack 20, and/or to provide a lifting
point for lowering the valve stack 20 onto the isolation head 10.
In some embodiments, when the valve stack 20 is suspended over the
isolation head 10, the valve 22, the valve 24, or both the valve 22
and the valve 24 are stroked to an open configuration to allow the
valve stack 20 to "swallow" the upwardly protruding isolation
sleeve 60 as the valve stack 20 is lowered in the downward
direction 162.
[0036] As shown in FIG. 10, once the valve stack 20 has been
completely lowered onto the isolation head 10 in the downward
direction 162 using the cable 160 so that the upwardly protruding
isolation sleeve 60 is "swallowed" by the valve 22, the valve 24,
or both the valve 22 and the valve 24, the valve stack 20 is
connected to the isolation head 10 via the upper flange 64, and a
fluid line 164 is connected between the tubing spool 16 and the
fluid block 26. For example, in some embodiments, the fluid line
164 may be connected between one, or both, of the access ports 50
and 52 of the tubing spool 16 and one or more of the diverter
passages extending into the internal passage of the fluid block 26.
Once the fluid line 164 is connected between the tubing spool 16
and the fluid block 26, fluid communication can be established, via
the fluid line 164, between the internal passage 48 of the tubing
spool 16 and the internal passage of the fluid block 26. Such fluid
communication between the tubing spool 16 and the fluid block 26
permits pressure equalization across the closed isolation valve 18
(i.e., above and below the isolation valve 18 as viewed in FIG.
10), thereby enabling the isolation valve 18 to be more easily
stroked to an open configuration. Thus, after pressure equalization
is permitted across the closed isolation valve 18 using the fluid
line 164, the isolation valve 18 can be opened, as indicated by the
curvilinear arrow 165. Although described as being connected
between the tubing spool 16 and the fluid block 26, the fluid line
164 (or another fluid line) may instead be connected between
various other suitable locations to produce the desired pressure
equalization on opposing sides of the isolation valve 18. For
example, the fluid line 164 may be connected between any component
of the wellhead 12 and any component of the isolation head 10, the
valve stack 20, and/or the frac tree 28.
[0037] Turning briefly back to FIG. 1A, before the upper and lower
packoff assemblies 86 and 100 are sealingly engaged with the upper
and lower packoff surfaces 3 and 7, respectively, the isolation
sleeve 60 does not isolate the wellhead 12 from fluid flowing
through the isolation head 10. Instead, the frac pump(s) 8 are
allowed to communicate fluid to the wellbore 2 along two separate
flow paths, at least one of which includes the wellhead 12. The
first flow path is indicated by arrows 9a, 9b, 9c, 9h, 9i. More
particularly, fluid traveling along the first flow path does not
enter the isolation sleeve 60, but is instead is communicated: from
the frac pump(s) 8 to the frac tree 28, as indicated by the arrow
9a; from the frac tree 28 to the valve stack 20, as indicated by
the arrow 9b; from the valve stack 20 to the isolation spool 58, as
indicated by the arrow 9c; from the isolation spool 58 to the
wellhead 12, as indicated by the arrow 9h; and from the wellhead 12
to the wellbore 2, as indicated by the arrow 9i.
[0038] In contrast, the second flow path varies depending on the
position of the isolation sleeve 60 relative to the isolation spool
58, which position changes as the isolation sleeve 60 is moved in
the opposing directions 5 and 6, but the second flow path always
includes the isolation sleeve 60. For example, when the isolation
sleeve 60 is moved in the direction 6 such that the lower packoff
assembly 100 extends within the isolation spool 58 and the upper
packoff assembly 86 extends within the valve stack 20 and/or the
frac tree 28, the second flow path is indicated by arrows 9a, 9b,
9d, 9f, 9h, 9i. Specifically, when the lower packoff assembly 100
extends within the isolation spool 58 and the upper packoff
assembly 86 extends within the valve stack 20 and/or the frac tree
28, the fluid traveling along the second flow path is communicated:
from the frac pump(s) 8 to the frac tree 28, as indicated by the
arrow 9a; from the frac tree 28 to the valve stack 20, as indicated
by the arrow 9b; from the valve stack 20 to the isolation sleeve
60, as indicated by the arrow 9d; from the isolation sleeve 60 to
the isolation spool 58, as indicated by the arrow 9f; from the
isolation spool 58 to the wellhead 12, as indicated by the arrow
9h; and from the wellhead 12 to the wellbore 2, as indicated by the
arrow 9i.
[0039] For another example, when the mandrel assembly 4 extends
within the isolation spool 58 but neither the upper packoff
assembly 86 nor the lower packoff assembly 100 extends within the
isolation spool 58, the second flow path is indicated by arrows 9a,
9b, 9d, 9g, 9i. Specifically, when the mandrel assembly 4 extends
within the isolation spool 58 but neither the upper packoff
assembly 86 nor the lower packoff assembly 100 extends within the
isolation spool 58, the fluid traveling along the second flow path
is communicated: from the frac pump(s) 8 to the frac tree 28, as
indicated by the arrow 9a; from the frac tree 28 to the valve stack
20, as indicated by the arrow 9b; from the valve stack 20 to the
isolation sleeve 60, as indicated by the arrow 9d; from the
isolation sleeve 60 to the wellhead 12, as indicated by the arrow
9g; and from the wellhead 12 to the wellbore 2, as indicated by the
arrow 9i.
[0040] For yet another example, when the isolation sleeve 60 is
moved in the direction 5 such that the upper packoff assembly 86
extends within the isolation spool 58 and the lower packoff
assembly 100 extends within the wellhead 12 (but before the upper
and lower packoff assemblies 86 and 100 are sealingly engaged with
the upper and lower packoff surfaces 3 and 7, respectively), the
second flow path is indicated by arrows 9a, 9b, 9c, 9e, 9g, 9i.
Specifically, when the upper packoff assembly 86 extends within the
isolation spool 58 and the lower packoff assembly 100 extends
within the wellhead 12 (but before the upper and lower packoff
assemblies 86 and 100 are sealingly engaged with the upper and
lower packoff surfaces 3 and 7, respectively), the fluid traveling
along the second flow path is communicated: from the frac pump(s) 8
to the frac tree 28, as indicated by the arrow 9a; from the frac
tree 28 to the valve stack 20, as indicated by the arrow 9b; from
the valve stack 20 to the isolation spool 58, as indicated by the
arrow 9c; from the isolation spool 58 to the isolation sleeve 60,
as indicated by the arrow 9e; from the isolation sleeve 60 to the
wellhead 12, as indicated by the arrow 9g; and from the wellhead 12
to the wellbore 2, as indicate by the arrow 9i.
[0041] Referring to FIG. 11A with continuing reference to FIG. 1A,
after the isolation valve 18 is opened, the isolation sleeve 60 can
be actuated in the direction 5 to sealingly engage the upper and
lower packoff assemblies 86 and 100 with the upper and lower
packoff surfaces 3 and 7, respectively, so that at least a portion
of the wellhead 12 is fluidically isolated from fluid flowing
through the isolation head 10 during the wellbore operation. Such
isolation of the at least a portion of the wellhead 12 from the
fluid flowing through the isolation head 10 is accomplished by
cutting off the first flow path along which the fluid is permitted
to be communicated from the frac pump(s) to the wellbore 2 (shown
in FIG. 1A). More particularly, the sealing engagement of the upper
and lower packoff assemblies 86 and 100 with the upper and lower
packoff surfaces 3 and 7, respectively, cuts off at least the
portion of the first flow path represented by the arrow 9h in FIG.
1A. As a result, the frac pump(s) 8 are only allowed to communicate
fluid to the wellbore along one flow path, which is indicated by
arrows 9a, 9b, 9c, 9j, 9k, and 9i. Specifically, when the upper and
lower packoff assemblies 86 and 100 are sealingly engaged with the
upper and lower packoff surfaces 3 and 7, respectively, the fluid
traveling along the one flow path is communicated: from the frac
pump(s) 8 to the frac tree 28, as indicated by the arrow 9a; from
the frac tree 28 to the valve stack 20, as indicated by the arrow
9b; from the valve stack 20 to the isolation spool 58, as indicated
by the arrow 9c; from the isolation spool 58 to the isolation
sleeve 60, as indicated by the arrow 9j; from the isolation sleeve
60 to the wellhead 12, as indicated by the arrow 9k; and from the
wellhead 12 to the wellbore 2, as indicated by the arrow 9i.
[0042] Turning briefly back to FIG. 5, in order to move the
isolation sleeve 60 in the direction 126 (which is analogous to the
direction 5 shown in FIG. 11A) after the isolation valve 18 is
opened, the input driveshaft 108 of the actuator 72 can be rotated
in one direction (e.g., clockwise) to drive the input gearbox 110
and the output gearboxes 111 and 112 so that the output driveshafts
114 and 116 rotate the pinion gears 118 and 120 in the directions
122 and 124, thereby causing the isolation sleeve 60 to move
longitudinally in the direction 126 (also shown in FIGS. 11B-11D).
This rotation of the input driveshaft 108 in the one direction
(e.g., clockwise) to move the isolation sleeve 60 longitudinally in
the direction 126 is continued until the upper packoff assembly 86
engages the landing shoulder 78 of the isolation spool 58, as shown
in FIGS. 11B and 11C. The lockdown pins 66 are then used to secure
the isolation sleeve 60 against the landing shoulder 78 of the
isolation spool 58. In some embodiments, the valve stack 20 acts as
a lubricator to facilitate the movement of the isolation sleeve 60
longitudinally in the direction 126. More particularly, once the
isolation valve 18 is opened, fluid is communicated from the
wellhead 12 to the valve stack 20 through the isolation head 10 so
that fluid pressures acting longitudinally on opposing end portions
of the isolation sleeve 60 are equal. As a result, the force
required to move the isolation sleeve 60 in the direction 126 is
reduced as compared to existing isolation tools. Moreover, in those
embodiments in which the diameter D2 of the lower packoff assembly
100 is less than the diameter D1 of the upper packoff assembly 86,
the fluid pressures acting longitudinally on the opposing end
portions of the isolation sleeve 60 bias the isolation sleeve 60 in
the direction 126 when the isolation valve 18 is in the open
configuration.
[0043] In some embodiments, when the upper packoff assembly 86
engages the landing shoulder 78 of the isolation spool 58, the
upper packoff assembly 86 sealingly engages an internal surface of
the isolation spool 58, which internal surface acts as the upper
packoff surface 3, as shown in FIGS. 11B and 11C, while the lower
packoff assembly 100 sealingly engages an internal surface of the
tubing spool 16, which internal surface acts as the lower packoff
surface 7, as shown in FIGS. 11B and 11D. For example, the internal
surface of the tubing spool that acts as the lower packoff surface
7 may be located below (as viewed in FIGS. 11B and 11D) the access
ports 50 and 52; as a result, the access port 50 and/or the access
port 52 can be used to pressure test the effectiveness of the seals
created by the engagement of the lower packoff assembly 100 with
the lower packoff surface 7, the engagement of the upper packoff
assembly 86 with the upper packoff surface 3, or both. Although the
internal surface of the isolation spool 58 is described herein as
acting as the upper packoff surface 3, another surface of the
isolation spool 58, the valve stack 20, the frac tree 28, or any
combination thereof, may instead act as the upper packoff surface
3. In addition, although the internal surface of the tubing spool
16 is described herein as acting as the lower packoff surface 7,
another surface of the tubing spool 16, some other component of the
wellhead 12, or any combination thereof, may instead act as the
lower packoff surface 7.
[0044] After the upper packoff assembly 86 is sealingly engaged
with the upper packoff surface 3, as shown in FIGS. 11B and 11C,
and the lower packoff assembly 100 is sealingly engaged with the
lower packoff surface 7, as shown in FIGS. 11B and 11D, the valve
22 and/or the valve 24 is/are closed, the blind flange 163 is
removed from the valve stack 20, and the frac tree 28 is connected
to the valve stack 20 (as shown in FIG. 1B) to facilitate, for
example, fracturing and/or gravel packing of the wellbore 2. Once
the frac tree 28 is connected to the valve stack 20, the valves 22
and 24 can each be opened so that fracturing or gravel packing
fluid can be communicated into the fluid inlets 34 of the goat head
30, as indicated by the arrows 36 in FIG. 1B. The fracturing and/or
gravel packing fluid travels through the valve stack 20, through
the isolation head 10 (including the isolation spool 58 and the
internal passages 88 and 102 of the isolation sleeve 60), and into
the wellbore 2. During this communication of the fracturing or
gravel packing fluid to the wellbore 2, the isolation sleeve 60
fluidically isolates the at least part of the wellhead 12 so that
the fracturing or gravel packing fluid does not come into contact
with the at least part of the wellhead 12. In some embodiments, the
at least part of the wellhead 12 isolated from the fracturing or
gravel packing fluid includes the isolation valve 18. In some
embodiments, a length of the isolation sleeve 60 is variable to
adapt the isolation head 10 for use with a wellhead having
different dimensions than the wellhead 12 by, for example,
interchanging the mandrel extension 82 with another mandrel
extension substantially identical to the mandrel extension 82 but
having a different length.
[0045] Referring to FIG. 12, a method of operating the frac system
1 is generally referred to by the reference numeral 166. The method
166 includes at a step 168, operably coupling the isolation spool
58 of the isolation head 10 to the wellhead 12, the wellhead 12
including the lower packoff surface 7, and the isolation sleeve 60
of the isolation head 10 including the upper and lower packoff
assemblies 86 and 100. At a step 170, at least one of the valves
22, 24, and 32 of the frac tree 28 is closed to isolate first and
second fluid pressures acting axially on the upper and lower
packoff assemblies 86 and 100, respectively, from atmosphere. At a
step 172, the first and second fluid pressures acting axially on
the upper and lower packoff assemblies 86 and 100, respectively,
are equalized with a third fluid pressure in the wellhead 12. In
some embodiments, the step 172 includes placing the wellhead 12 and
the isolation head 10 in fluid communication via the fluid line 164
to bypass the isolation valve 18. At a step 174, the isolation
valve 18 is opened. At a step 176, the isolation sleeve 60 is moved
relative to the isolation spool 58 to sealingly engage the upper
and lower packoff assemblies 86 and 100 with the upper and lower
packoff surfaces 3 and 7, respectively, to isolate at least a
portion of the wellhead 12 from a fluid flowing through the
isolation head 10. In some embodiments, the at least a portion of
the wellhead isolated from the fluid flowing through the isolation
head includes the isolation valve 18. In some embodiments, the step
176 includes engaging the actuator to move the isolation sleeve
relative to the isolation spool. In some embodiments, the upper
packoff surface 3 is part the isolation spool 58. In other
embodiments, the upper packoff surface 3 is part of the frac tree
28 operably coupled to the isolation spool 58 opposite the wellhead
12.
[0046] In some embodiments, among other things, the operation of
the frac system 1 (i.e., the isolation sleeve 60's fluidic
isolation of the at least part of the wellhead 12 during the
fracturing or gravel packing operation) and/or the execution of the
method 166: effectively increases the pressure rating of the
wellhead 12 (e.g., from 5 ksi to 10 ksi, from 10 ksi to 15 ksi, or
the like) so that the wellhead 12 itself does not have to be
upgraded to perform certain wellbore operations; protects the at
least part of the wellhead 12 from erosion during the fracturing or
gravel packing operation; and allows for rapid shut in of the
wellbore 2 if unsafe conditions develop (or are about to develop),
thereby preventing (or stopping) the uncontrolled release of
hydrocarbons from the wellbore 2 (i.e., a blowout). Furthermore,
among other things, because the fluid pressures acting
longitudinally on the opposing end portions of the isolation sleeve
60 are equal: the isolation head 10 does not encounter "lifting
off" of the isolation sleeve 60 in the same way existing isolation
tools encounter "lifting off" of their mandrels; and the isolation
sleeve 60 can easily be moved by the actuator 72, even when unsafe
conditions develop. For these reasons, unsafe conditions are much
less likely to develop during use of the isolation head 10 than
during use of existing isolation tools and, should such unsafe
conditions develop, the input driveshaft 108 can be rotated in the
opposite direction (e.g., counterclockwise) (as shown in FIG. 5) to
drive the input gearbox 110 and the output gearboxes 111 and 112 so
that the output driveshafts 114 and 116 rotate the pinion gears 118
and 120 in directions opposite the directions 122 and 124,
respectively, thereby causing the isolation sleeve 60 to move
longitudinally in a direction opposite the direction 126. Once the
isolation sleeve 60 has been so moved far enough to clear the
isolation valve 18, the isolation valve 18 can be closed to shut in
the wellbore 2. In some embodiments, since the isolation valve 18
was not exposed to excessive pressures, temperatures, and/or flow
rates during the fracturing or gravel packing of the wellbore 2,
the isolation valve 18 is better suited to stop or prevent such a
blowout than existing isolation tools.
[0047] Referring to FIG. 13, in an embodiment, a computing node
1000 for implementing one or more embodiments of one or more of the
above-described elements, systems (e.g., 1), methods (e.g., 166)
and/or steps (e.g., 168, 170, 172, 174, and/or 176), or any
combination thereof, is depicted. The node 1000 includes a
microprocessor 1000a, an input device 1000b, a storage device
1000c, a video controller 1000d, a system memory 1000e, a display
1000f, and a communication device 1000g all interconnected by one
or more buses 1000h. In several embodiments, the storage device
1000c may include a floppy drive, hard drive, CD-ROM, optical
drive, any other form of storage device or any combination thereof.
In several embodiments, the storage device 1000c may include,
and/or be capable of receiving, a floppy disk, CD-ROM, DVD-ROM, or
any other form of computer-readable medium that may contain
executable instructions. In several embodiments, the communication
device 1000g may include a modem, network card, or any other device
to enable the node 1000 to communicate with other nodes. In several
embodiments, any node represents a plurality of interconnected
(whether by intranet or Internet) computer systems, including
without limitation, personal computers, mainframes, PDAs,
smartphones and cell phones.
[0048] In several embodiments, one or more of the components of any
of the above-described systems include at least the node 1000
and/or components thereof, and/or one or more nodes that are
substantially similar to the node 1000 and/or components thereof.
In several embodiments, one or more of the above-described
components of the node 1000 and/or the above-described systems
include respective pluralities of same components.
[0049] In several embodiments, a computer system typically includes
at least hardware capable of executing machine readable
instructions, as well as the software for executing acts (typically
machine-readable instructions) that produce a desired result. In
several embodiments, a computer system may include hybrids of
hardware and software, as well as computer sub-systems.
[0050] In several embodiments, hardware generally includes at least
processor-capable platforms, such as client-machines (also known as
personal computers or servers), and hand-held processing devices
(such as smart phones, tablet computers, personal digital
assistants (PDAs), or personal computing devices (PCDs), for
example). In several embodiments, hardware may include any physical
device that is capable of storing machine-readable instructions,
such as memory or other data storage devices. In several
embodiments, other forms of hardware include hardware sub-systems,
including transfer devices such as modems, modem cards, ports, and
port cards, for example.
[0051] In several embodiments, software includes any machine code
stored in any memory medium, such as RAM or ROM, and machine code
stored on other devices (such as floppy disks, flash memory, or a
CD ROM, for example). In several embodiments, software may include
source or object code. In several embodiments, software encompasses
any set of instructions capable of being executed on a node such
as, for example, on a client machine or server.
[0052] In several embodiments, combinations of software and
hardware could also be used for providing enhanced functionality
and performance for certain embodiments of the present disclosure.
In an embodiment, software functions may be directly manufactured
into a silicon chip. Accordingly, it should be understood that
combinations of hardware and software are also included within the
definition of a computer system and are thus envisioned by the
present disclosure as possible equivalent structures and equivalent
methods.
[0053] In several embodiments, computer readable mediums include,
for example, passive data storage, such as a random-access memory
(RAM) as well as semi-permanent data storage such as a compact disk
read only memory (CD-ROM). One or more embodiments of the present
disclosure may be embodied in the RAM of a computer to transform a
standard computer into a new specific computing machine. In several
embodiments, data structures are defined organizations of data that
may enable an embodiment of the present disclosure. In an
embodiment, data structure may provide an organization of data, or
an organization of executable code.
[0054] In several embodiments, any networks and/or one or more
portions thereof, may be designed to work on any specific
architecture. In an embodiment, one or more portions of any
networks may be executed on a single computer, local area networks,
client-server networks, wide area networks, internets, hand-held
and other portable and wireless devices and networks.
[0055] In several embodiments, database may be any standard or
proprietary database software. In several embodiments, the database
may have fields, records, data, and other database elements that
may be associated through database specific software. In several
embodiments, data may be mapped. In several embodiments, mapping is
the process of associating one data entry with another data entry.
In an embodiment, the data contained in the location of a character
file can be mapped to a field in a second table. In several
embodiments, the physical location of the database is not limiting,
and the database may be distributed. In an embodiment, the database
may exist remotely from the server, and run on a separate platform.
In an embodiment, the database may be accessible across the
Internet. In several embodiments, more than one database may be
implemented.
[0056] In several embodiments, a plurality of instructions stored
on a computer readable medium may be executed by one or more
processors to cause the one or more processors to carry out or
implement in whole or in part the above-described operation of each
of the above-described elements, systems (e.g., 1), methods (e.g.,
166) and/or steps (e.g., 168, 170, 172, 174, and/or 176), or any
combination thereof. In several embodiments, such a processor may
include one or more of the microprocessor 1000a, any processor(s)
that are part of the components of the above-described systems,
and/or any combination thereof, and such a computer readable medium
may be distributed among one or more components of the
above-described systems. In several embodiments, such a processor
may execute the plurality of instructions in connection with a
virtual computer system. In several embodiments, such a plurality
of instructions may communicate directly with the one or more
processors, and/or may interact with one or more operating systems,
middleware, firmware, other applications, and/or any combination
thereof, to cause the one or more processors to execute the
instructions.
[0057] A system has been disclosed. The system generally includes a
wellhead that serves as a surface termination of a wellbore that
traverses a subterranean formation, the wellhead including a lower
packoff surface. An isolation head of the system includes an
isolation spool operably coupled to the wellhead and an isolation
sleeve including upper and lower packoff assemblies. The system
also includes an upper packoff surface that is either: part the
isolation spool; or part of a frac tree operably coupled to the
isolation spool opposite the wellhead. The isolation sleeve is
movable relative to the isolation spool to sealingly engage the
upper and lower packoff assemblies with the upper and lower packoff
surfaces, respectively. When the upper and lower packoff assemblies
are sealingly engaged with the upper and lower packoff surfaces,
respectively, the isolation sleeve isolates at least a portion of
the wellhead from a fluid flowing through the isolation head.
[0058] The foregoing system embodiment may include one or more of
the following elements, either alone or in combination with one
another: [0059] An actuator operably coupling the isolation sleeve
to the isolation spool and adapted to move the isolation sleeve
relative to the isolation spool. [0060] The actuator includes: a
rack gear operably associated with the isolation sleeve; and a
pinion gear engageable with the rack gear to move the isolation
sleeve. [0061] The isolation spool defines an internal passage; and
the isolation sleeve extends within the internal passage of the
isolation spool. [0062] The system further includes the frac tree;
wherein the frac tree includes one or more valves adapted to be
closed to isolate first and second fluid pressures acting axially
on the upper and lower packoff assemblies, respectively, from
atmosphere. [0063] The first and second fluid pressures acting
axially on the upper and lower packoff assemblies, respectively,
are adapted to be equalized to facilitate movement of the isolation
sleeve relative to the isolation spool. [0064] The wellhead
includes an isolation valve positioned between the lower packoff
surface and the isolation spool and adapted to be opened and
closed; and the at least a portion of the wellhead isolated from
the fluid flowing through the isolation head when the upper and
lower packoff assemblies are sealingly engaged with the upper and
lower packoff surfaces, respectively, includes the isolation valve.
[0065] First and second fluid pressures acting axially on the upper
and lower packoff assemblies, respectively, are adapted to be
equalized with a third fluid pressure in the wellhead to
facilitate: the opening of the isolation valve; and the movement of
the isolation sleeve relative to the isolation spool. [0066] A
fluid line is adapted to bypass the isolation valve and to place
the wellhead and the isolation head in fluid communication so that
the first and second fluid pressures acting axially on the upper
and lower packoff assemblies, respectively, are equalized with the
third fluid pressure in the wellhead.
[0067] A method has also been disclosed. The method generally
includes operably coupling an isolation spool of an isolation head
to a wellhead that serves as a surface termination of a wellbore
that traverses a subterranean formation, the wellhead including a
lower packoff surface, and the isolation head further including an
isolation sleeve including upper and lower packoff assemblies; and
moving the isolation sleeve relative to the isolation spool to
sealingly engage the upper and lower packoff assemblies with an
upper packoff surface and the lower packoff surface, respectively.
When the upper and lower packoff assemblies are sealingly engaged
with the upper and lower packoff surfaces, respectively, the
isolation sleeve isolates at least a portion of the wellhead from a
fluid flowing through the isolation head. Either: the upper packoff
surface is part the isolation spool; or the upper packoff surface
is part of a frac tree operably coupled to the isolation spool
opposite the wellhead.
[0068] The foregoing method embodiment may include one or more of
the following elements, either alone or in combination with one
another: [0069] Moving the isolation sleeve relative to the
isolation spool includes engaging an actuator that operably couples
the isolation sleeve to the isolation spool to move the isolation
sleeve relative to the isolation spool. [0070] The actuator
includes: a rack gear operably associated with the isolation
sleeve; and a pinion gear engageable with the rack gear to move the
isolation sleeve. [0071] The isolation spool defines an internal
passage; and the isolation sleeve extends within the internal
passage of the isolation spool. [0072] The method further includes
closing one or more valves of the frac tree to isolate first and
second fluid pressures acting axially on the upper and lower
packoff assemblies, respectively, from atmosphere. [0073] The
method further includes, before moving the isolation sleeve
relative to the isolation spool, equalizing the first and second
fluid pressures acting axially on the upper and lower packoff
assemblies, respectively, to facilitate movement of the isolation
sleeve relative to the isolation spool. [0074] The wellhead
includes an isolation valve positioned between the lower packoff
surface and the isolation spool; and the at least a portion of the
wellhead isolated from the fluid flowing through the isolation head
when the upper and lower packoff assemblies are sealingly engaged
with the upper and lower packoff surfaces, respectively, includes
the isolation valve. [0075] The method further includes: opening
the isolation valve; and before moving the isolation sleeve
relative to the isolation spool, equalizing first and second fluid
pressures acting axially on the upper and lower packoff assemblies,
respectively, with a third fluid pressure in the wellhead to
facilitate: the opening of the isolation valve; and the movement of
the isolation sleeve relative to the isolation spool. [0076]
Equalizing the first and second fluid pressures acting axially on
the upper and lower packoff assemblies, respectively, with the
third fluid pressure in the wellhead includes: before opening the
isolation valve, placing the wellhead and the isolation head in
fluid communication via a fluid line to bypass the isolation valve
so that the first and second fluid pressures acting axially on the
upper and lower packoff assemblies, respectively, are equalized
with the third fluid pressure in the wellhead.
[0077] An apparatus has also been disclosed. The apparatus
generally includes an isolation spool adapted to be operably
coupled to a wellhead that serves as a surface termination of a
wellbore that traverses a subterranean formation, the wellhead
including a lower packoff surface; an isolation sleeve including
upper and lower packoff assemblies; and an upper packoff surface;
wherein the isolation sleeve is movable relative to the isolation
spool to sealingly engage the upper and lower packoff assemblies
with the upper and lower packoff surfaces, respectively; wherein,
when the upper and lower packoff assemblies are sealingly engaged
with the upper and lower packoff surfaces, respectively, the
isolation sleeve isolates at least a portion of the wellhead from a
fluid flowing through the apparatus; and wherein either: the upper
packoff surface is part the isolation spool; or the upper packoff
surface is part of a frac tree adapted to be operably coupled to
the isolation spool opposite the wellhead.
[0078] The foregoing apparatus embodiment may include one or more
of the following elements, either alone or in combination with one
another: [0079] An actuator operably coupling the isolation sleeve
to the isolation spool and adapted to move the isolation sleeve
relative to the isolation spool. [0080] The actuator includes: a
rack gear operably associated with the isolation sleeve; and a
pinion gear engageable with the rack gear to move the isolation
sleeve. [0081] The isolation spool defines an internal passage; and
the isolation sleeve extends within the internal passage of the
isolation spool. [0082] The apparatus further includes the frac
tree; wherein the frac tree includes one or more valves adapted to
be closed to isolate first and second fluid pressures acting
axially on the upper and lower packoff assemblies, respectively,
from atmosphere. [0083] The first and second fluid pressures acting
axially on the upper and lower packoff assemblies, respectively,
are adapted to be equalized to facilitate movement of the isolation
sleeve relative to the isolation spool. [0084] The apparatus
further includes the wellhead; wherein the wellhead includes an
isolation valve positioned between the lower packoff surface and
the isolation spool and adapted to be opened and closed; and
wherein the at least a portion of the wellhead isolated from the
fluid flowing through the apparatus when the upper and lower
packoff assemblies are sealingly engaged with the upper and lower
packoff surfaces, respectively, includes the isolation valve.
[0085] First and second fluid pressures acting axially on the upper
and lower packoff assemblies, respectively, are adapted to be
equalized with a third fluid pressure in the wellhead to
facilitate: the opening of the isolation valve; and the movement of
the isolation sleeve relative to the isolation spool. [0086] A
fluid line is adapted to bypass the isolation valve and to place
the wellhead and the apparatus in fluid communication so that the
first and second fluid pressures acting axially on the upper and
lower packoff assemblies, respectively, are equalized with the
third fluid pressure in the wellhead.
[0087] It is understood that variations may be made in the
foregoing without departing from the scope of the present
disclosure.
[0088] In some embodiments, the elements and teachings of the
various embodiments may be combined in whole or in part in some or
all of the embodiments. In addition, one or more of the elements
and teachings of the various embodiments may be omitted, at least
in part, and/or combined, at least in part, with one or more of the
other elements and teachings of the various embodiments.
[0089] Any spatial references, such as, for example, "upper,"
"lower," "above," "below," "between," "bottom," "vertical,"
"horizontal," "angular," "upwards," "downwards," "side-to-side,"
"left-to-right," "right-to-left," "top-to-bottom," "bottom-to-top,"
"top," "bottom," "bottom-up," "top-down," etc., are for the purpose
of illustration only and do not limit the specific orientation or
location of the structure described above.
[0090] In some embodiments, while different steps, processes, and
procedures are described as appearing as distinct acts, one or more
of the steps, one or more of the processes, and/or one or more of
the procedures may also be performed in different orders,
simultaneously and/or sequentially. In some embodiments, the steps,
processes, and/or procedures may be merged into one or more steps,
processes and/or procedures.
[0091] In some embodiments, one or more of the operational steps in
each embodiment may be omitted. Moreover, in some instances, some
features of the present disclosure may be employed without a
corresponding use of the other features. Moreover, one or more of
the above-described embodiments and/or variations may be combined
in whole or in part with any one or more of the other
above-described embodiments and/or variations.
[0092] Although some embodiments have been described in detail
above, the embodiments described are illustrative only and are not
limiting, and those skilled in the art will readily appreciate that
many other modifications, changes and/or substitutions are possible
in the embodiments without materially departing from the novel
teachings and advantages of the present disclosure. Accordingly,
all such modifications, changes, and/or substitutions are intended
to be included within the scope of this disclosure as defined in
the following claims. In the claims, any means-plus-function
clauses are intended to cover the structures described herein as
performing the recited function and not only structural
equivalents, but also equivalent structures. Moreover, it is the
express intention of the applicant not to invoke 35 U.S.C. .sctn.
112, paragraph 6 for any limitations of any of the claims herein,
except for those in which the claim expressly uses the word "means"
together with an associated function.
* * * * *