U.S. patent application number 14/082469 was filed with the patent office on 2015-05-21 for subsea intervention plug pulling device.
This patent application is currently assigned to CHEVRON U.S.A. INC.. The applicant listed for this patent is Mauricio Baez, John Lloyd Busby, Stephen Gregory Pierce, Brian Saucier, Raymond A. Stawaisz, Walter Warren Weaver. Invention is credited to Mauricio Baez, John Lloyd Busby, Stephen Gregory Pierce, Brian Saucier, Raymond A. Stawaisz, Walter Warren Weaver.
Application Number | 20150136406 14/082469 |
Document ID | / |
Family ID | 52014391 |
Filed Date | 2015-05-21 |
United States Patent
Application |
20150136406 |
Kind Code |
A1 |
Baez; Mauricio ; et
al. |
May 21, 2015 |
Subsea Intervention Plug Pulling Device
Abstract
A plug pulling device includes an elongated housing comprising a
production tree connection interface, a shifting tool disposed
within and along a substantial length the housing and comprising a
distal end configured to couple to a tubing plug, and a seal
disposed within the housing and formed around a portion of the
shifting tool. The seal isolates a first portion of the housing
from a second portion of the housing. The second portion of the
housing is adjacent to the production tree connection interface.
The shifting tool is configured to move partially in and out of the
first portion of the housing when there is a pressure differential
between the first portion of the housing and an environment
external to the first portion of the housing.
Inventors: |
Baez; Mauricio; (Sugar Land,
TX) ; Stawaisz; Raymond A.; (Tomball, TX) ;
Busby; John Lloyd; (Spring, TX) ; Saucier; Brian;
(Magnolia, TX) ; Pierce; Stephen Gregory; (Katy,
TX) ; Weaver; Walter Warren; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baez; Mauricio
Stawaisz; Raymond A.
Busby; John Lloyd
Saucier; Brian
Pierce; Stephen Gregory
Weaver; Walter Warren |
Sugar Land
Tomball
Spring
Magnolia
Katy
Houston |
TX
TX
TX
TX
TX
TX |
US
US
US
US
US
US |
|
|
Assignee: |
CHEVRON U.S.A. INC.
San Ramon
CA
|
Family ID: |
52014391 |
Appl. No.: |
14/082469 |
Filed: |
November 18, 2013 |
Current U.S.
Class: |
166/335 |
Current CPC
Class: |
E21B 23/00 20130101;
E21B 23/04 20130101; E21B 33/076 20130101; E21B 33/043
20130101 |
Class at
Publication: |
166/335 |
International
Class: |
E21B 23/00 20060101
E21B023/00 |
Claims
1. A plug pulling device, comprising: a housing comprising a closed
top end and an open bottom end; a shifting tool comprising a stem
and a pulling tool disposed at a distal end of the stem, wherein
the shifting tool is movable in and out of the housing via the
bottom end; a circular seal disposed within the housing and around
the shifting tool, and forming a fluid tight seal between the
shifting tool and the housing, the shifting tool being slidable
with respect to the seal and along a length of the housing, wherein
the seal divides the housing into a first chamber and a second
chamber, the first chamber defined between the top end of the
housing and the seal, and the second chamber defined between the
seal and the bottom end, wherein the first chamber and the second
chamber are isolated from each other by the seal; a first hot stab
coupled to the first chamber configured to deliver hydraulic fluid
in and out of the first chamber; and a second hot stab coupled to
the second chamber configured to deliver hydraulic fluid in and out
of the second chamber.
2. The plug pulling device of claim 1, further comprising at least
one stabilizer guide disposed within the housing and surrounding
the stem of the shifting tool.
3. The plug pulling device of claim 1, wherein the bottom end of
the housing comprises a standard production tree mating
feature.
4. The plug pulling device of claim 1, wherein the production tree
is coupled to a well comprising a tubing plug, the production tree
comprising at least one valve configured to open or isolate the
well.
5. The plug pulling device of claim 4, wherein the shifting tool is
configured to travel away from the top end of the housing towards
the tubing plug until the pulling tool latches onto the tubing plug
and travel back towards the top end of the housing after the
pulling tool latches onto the tubing plug, wherein the tubing plug
travels towards the top end of the housing with the shifting
tool.
6. The plug pulling device of claim 5, wherein the shifting tool
travels towards the tubing plug when pressure in the first chamber
overcomes pressure in the second chamber, wherein the second
chamber is communicative with the production tree.
7. The plug pulling device of claim 5, wherein the shifting tool
moves back towards the top end of the housing when pressure in the
second chamber overcomes pressure in the first chamber, wherein the
second chamber is communicative with the production tree.
8. The plug pulling device of claim 6, wherein pressure in the
first chamber overcomes pressure in the second chamber through
pumping hydraulic fluid into the first chamber via the first hot
stab.
9. The plug pulling device of claim 7, wherein pressure in the
second chamber overcomes pressure in the first chamber through
pumping hydraulic fluid into the second chamber via the second hot
stab.
10. The plug pulling device of claim 7, wherein pressure in the
second chamber overcomes pressure in the first chamber through
pumping hydraulic fluid out the first chamber via the first hot
stab.
11. A subsea intervention device, comprising: an elongated housing
comprising a production tree connection interface; a shifting tool
disposed within and along a substantial length of the housing and
comprising a distal end configured to couple to a tubing plug; and
a seal disposed within the housing and formed around a portion of
the shifting tool, the seal isolating a first portion of the
housing from a second portion of the housing, wherein the second
portion of the housing is adjacent to the production tree
connection interface, wherein the shifting tool is configured to
move partially in and out of the first portion of the housing when
there is a pressure differential between the first portion of the
housing and an environment external to the first portion of the
housing.
12. The subsea intervention device of claim 11, wherein the first
portion of the housing is closed and filled with a hydraulic
fluid.
13. The subsea intervention device of claim 11, further comprising:
a first hydraulic coupling point coupled to the first portion of
the housing, wherein hydraulic fluid is pumped in and/or out of the
first portion of the housing via the hydraulic coupling point; and
a second hydraulic coupling point coupled to the second portion of
the housing, wherein hydraulic fluid is pumped in and/or out of the
second hydraulic coupling point.
14. The subsea intervention device of claim 11, wherein the
shifting tool moves partially out of the first portion of the
housing when a pressure in the first portion is greater than a
pressure in the environment external to the first portion of the
housing.
15. The subsea intervention device of claim 11, wherein the
shifting tool moves back into the first portion of the housing when
a pressure in the first portion is less than a pressure in the
environment external to the first portion of the housing.
16. The subsea intervention device of claim 11, wherein the housing
is coupled to a production tree via the production tree coupling
interface, and the production tree is coupled to a well, and
wherein the shifting tool is configured to move partially out of
the housing and partially into the well until the shifting tool
latches onto a tubing plug disposed within the well, and move back
into the housing with the tubing plug, removing the tubing plug
from the well.
17. A method of pulling a tubing plug from a production tubing,
comprising: coupling a plug pulling device to a production tree of
a well, the plug pulling device comprising a housing and a shifting
tool disposed within the housing, the housing divided into a first
chamber and a second chamber by a seal, wherein the first chamber
is isolated from the second chamber and the second chamber couples
to the production tree; opening one or more valves of the
production tree; pushing the shifting tool substantially out of the
first chamber and into the production tree and the well coupled to
the production tree until the shifting tool latches onto the tubing
plug disposed within the well; and pulling the shifting tool back
into the first chamber along with the tubing plug.
18. The method of claim 17, comprising: increasing pressure within
the first chamber relative to pressure within the second chamber
and the production tree until the shifting tool latches onto the
tubing plug.
19. The method of claim 17, comprising: decreasing pressure within
the first chamber relative to pressure within the second chamber
and the production tree to pull to shifting tool back into the
first chamber.
20. The method of claim 17, wherein pushing the shifting tool
substantially out of the first chamber comprises injecting
hydraulic fluid into the first chamber, and wherein pulling the
shifting tool back into the first chamber comprises removing
hydraulic fluid from the first chamber.
Description
TECHNICAL FIELD
[0001] The present application relates to retrieving a tubing plug
that is placed within a production tubing of a well. Specifically,
the present application relates to systems and methods for
retrieving the tubing plug.
BACKGROUND
[0002] Well completion is the process of preparing a borehole for
controlled production of natural resources. Typically, a well is
created by alternatingly drilling and installing a series of
telescoping casings. For example, in certain subsea well
completions, a first hole of a certain depth is drilled from the
seafloor and fitted with a conductor casing. Space between the
outer perimeter of the conductor casing and the first hole is
filled with cement or other agent to stabilize and set the casing
within the first hole. A second hole is then drilled from the
bottom of the first hole, in which the second hole has a smaller
diameter then the first hole. Likewise, the second hole is fitted
with a casing, and the space between the outer perimeter of the
casing and the second hole is filled with cement or another agent.
A variable number of telescoping-sized holes and can be drilled and
cased, collectively known as a casing string. The depth of each
hole and casing segment and the total number of segments depends on
various factors such as rock stress, pore pressure, required hole
diameter and depth, and so forth. A segment of the casing string
known as a surface casing extends to or above the seafloor and
terminates at a wellhead located at or near the surface of the
seafloor. A blowout preventer (BOP) is typically attached to the
wellhead to maintain pressure and security of the well during
remaining well sections and completions. Generally, a completed
well further includes a production tubing substantially extending
from the tubing hanger at the mud line to the bottom of the well,
through which the resources are brought to a pipeline for
production. In order to facilitate recovery of resources from
surrounding formations, certain portions of the casing string
and/or production tubing are perforated to allow fluids from
surrounding formations to flow into the production tubing. The
production tubing is typically hung from a tubing head spool or the
wellhead at the surface of the seafloor.
[0003] As another mode of isolating the well from the surface
environment (i.e., to prevent uncontrolled flow of resources to the
surface) during completions, a tubing plug is disposed within the
production tubing and tested. When it is known that the tubing plug
successfully isolates the well, the BOP can be removed and a
production tree, also known as a Christmas tree, can be installed
onto the wellhead to provide production and flow control of the
well. With the tubing plug still in place, the production tree is
tested. Before the well can be put into production, the tubing plug
needs to be removed. Traditionally, in order to remove the tubing
plug from the production tubing, the BOP is reinstalled to provide
a mechanical barrier for the well during retrieval of the tubing
plug. Deploying a BOP and retrieving the plug typically requires
the use of a mobile offshore drilling unit (MODU). However, a MODU
is a very large and highly complex piece of equipment designed for
heavy duty operations such as drilling. As a result, MODUs are very
costly to operate, often costing millions of dollars. Additionally,
such conventional plug retrieval is performed through a slickline
operation, in which a thin wire with a tool attached is run
down-hole into the production tubing to retrieve the plug. These
operations are susceptible to certain issues such as wire breakage,
in which the wire and the tool are dropped down-hole. Thus, the
wire and tool need to be fished out before attempting to operate
the well, adding time and cost to the operation. Thus, it would be
beneficial and highly cost effective to eliminate the need to use a
MODU or slickline operation for plug pulling processes.
SUMMARY
[0004] In general, in one aspect, the disclosure relates to a plug
pulling device. The plug pulling device includes a housing
including a closed top end and an open bottom end. The plug pulling
device further includes a shifting tool including a stem and a
pulling tool disposed at a distal end of the stem, in which the
shifting tool is movable in and out of the housing via the bottom
end. The plug pulling device also includes a circular seal disposed
within the housing and around the shifting tool, forming a fluid
tight seal between the shifting tool and the housing. The shifting
tool is slidable with respect to the seal and along a length of the
housing. The seal divides the housing into a first chamber and a
second chamber. The first chamber is defined between the top end of
the housing and the seal, and the second chamber is defined between
the seal and the bottom end. The first chamber and the second
chamber are isolated from each other by the seal. The plug pulling
device further includes a first hot stab and a second hot stab. The
first hot stab is coupled to the first chamber and configured to
deliver hydraulic fluid in and out of the first chamber. The second
hot stab is coupled to the second chamber and configured to deliver
hydraulic fluid in and out of the second chamber.
[0005] In another aspect, the disclosure can generally related to a
subsea intervention device. The subsea intervention devices
includes an elongated housing including a production tree
connection interface. The subsea intervention device further
includes a shifting tool disposed within and along a substantial
length of the housing and having a distal end configured to couple
to a tubing plug. The subsea intervention device also includes a
seal disposed within the housing and formed around a portion of the
shifting tool. The seal isolates a first portion of the housing
from a second portion of the housing. The second portion of the
housing is adjacent to the production tree connection interface.
The shifting tool is configured to move partially in and out of the
first portion of the housing when there is a pressure differential
between the first portion of the housing and an environment
external to the first portion of the housing.
[0006] In another aspect, the disclosure can generally relate to a
method of pulling a tubing plug from a production tubing. The
method includes coupling a plug pulling device to a production tree
of a well, in which the plug pulling device includes a housing and
a shifting tool disposed within the housing. The housing is also
divided into a first chamber and a second chamber by a seal. The
first chamber is isolated from the second chamber and the second
chamber couples to the production tree. The method also includes
opening one or more valves of the production tree, and pushing the
shifting tool substantially out of the first chamber and into the
production tree and the well coupled to the production tree until
the shifting tool latches onto the tubing plug disposed within the
well. The method further includes pulling the shifting tool back
into the first chamber along with the tubing plug.
[0007] These and other aspects, objects, features, and embodiments
will be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The drawings illustrate only example embodiments of systems
and methods for pulling a tubing plug from a production tubing in a
subsea well, and are therefore not to be considered limiting of its
scope, as the disclosures herein for pulling a tubing plug from a
production tubing may admit to other equally effective embodiments.
The elements and features shown in the drawings are not necessarily
to scale, emphasis instead being placed upon clearly illustrating
the principles of the example embodiments. Additionally, certain
dimensions or positioning may be exaggerated to help visually
convey such principles. In the drawings, reference numerals
designate like or corresponding, but not necessarily identical,
elements. The methods shown in the drawings illustrate certain
steps for carrying out the techniques of this disclosure. However,
the methods may include more or less steps than explicitly
illustrated in the example embodiments. Two or more of the
illustrated steps may be combined into one step or performed in an
alternate order. Moreover, one or more steps in the illustrated
methods may be replaced by one or more equivalent steps known in
the art to be interchangeable with the illustrated step(s). In one
or more embodiments, one or more of the features shown in each of
the figures may be omitted, added, repeated, and/or substituted.
Accordingly, embodiments of the present disclosure should not be
limited to the specific arrangements of components shown in these
figures.
[0009] FIG. 1 illustrates a cross-sectional representation of a
subsea well system for use with a plug pulling device at a first
stage of well completion, in accordance with example embodiments of
the present disclosure;
[0010] FIG. 2 illustrates a cross-sectional representation of a
well system for use with a plug pulling device at a second stage of
well completion, in accordance with example embodiments of the
present disclosure;
[0011] FIG. 3 illustrates a cross-sectional representation of a
well system for use with a plug pulling device in a third stage of
well completion, in accordance with example embodiments of the
present disclosure;
[0012] FIG. 4 illustrates a cross-sectional representation of a
plug pulling device in an initial retracted state coupled to a well
system, in accordance with example embodiments of the present
disclosure;
[0013] FIG. 5 illustrates a cross-sectional representation of a
well system with a plug pulling device in a deployed state, in
accordance with example embodiments of the present disclosure;
[0014] FIG. 6 illustrates a cross-sectional representation of a
well system with a plug pulling device in a retrieved state, in
accordance with example embodiments of the present disclosure;
[0015] FIG. 7 illustrates a method of pulling a plug from a subsea
well, in accordance with example embodiments of the present
disclosure; and
[0016] FIG. 8 illustrates another method of pulling a plug from a
subsea well, in accordance with example embodiments of the present
disclosure.
DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS
[0017] Example embodiments directed to pulling a plug from a subsea
well will now be described in detail with reference to the
accompanying figures. Like, but not necessarily the same or
identical, elements in the various figures are denoted by like
reference numerals for consistency. In the following detailed
description of the example embodiments, numerous specific details
are set forth in order to provide a more thorough understanding of
the disclosure herein. However, it will be apparent to one of
ordinary skill the art that the example embodiments herein may be
practiced without these specific details. In other instances,
well-known features have not been described in detail to avoid
unnecessarily complicating the description. Designations such as
"first" and "second" are merely used to distinguish between
distinct features, and not meant to limit the number of features.
Furthermore, in certain embodiments, such distinct features are not
precluded from having the same value, if applicable. Descriptions
such as "top", "bottom", "distal", and "proximal" are merely used
to distinguish between different portions of an element or
component and are not meant to imply an absolute orientation.
[0018] In certain example embodiments, production fluid as
described herein is one or more of any solid, liquid, and/or vapor
that can be found in subterranean formations. Examples of
production fluid can include, but are not limited to, crude oil,
natural gas, water, steam, and hydrogen gas. Production fluid can
be called other names, including but not limited to down hole
fluid, reservoir fluid, a resource, and a field resource. In
certain example embodiments, the techniques provided herein are
directed towards well completions and well interventions in subsea
environments, including both deep water and shallow water
environments.
[0019] The present disclosure provides a subsea intervention plug
pulling device. In certain example embodiments, the plug pulling
device is a self-contained device which attaches to a production
tree and is configured to remove a tubing plug from a production
tubing or well without the need for an intervening blowout
preventer (BOP) stack or lower marine riser package (LMRP). The
plug pulling device makes use of the valves of the production tree
as barriers as it recovers the tubing plug. As discussed above,
attaching a BOP to a production tree requires the use of a costly
mobile offshore drilling unit (MODU). Thus, as the plug pulling
device eliminates the need for BOP attachment for plug pulling, the
MODU is likewise unnecessary, decreasing the time and cost of the
plug pulling operation.
[0020] Referring now to the drawings, FIG. 1 illustrates a subsea
well system 100 at a first stage of completion for use with a plug
pulling device, in accordance with example embodiments of the
present disclosure. Referring to FIG. 1, the well system includes a
wellbore 102 formed in an underwater subterranean formation 104. In
certain example embodiments, the subterranean formation 104
includes one or more of a number of formation types, including but
not limited to, shale, limestone, sandstone, clay, sand, and salt.
In certain example embodiments, the subterranean formation 104 also
includes one or more reservoirs in which one or more resources
(e.g., oil, gas) can be located.
[0021] In certain example embodiments, the wellbore 102 has one or
more of a number of segments, and each segment has a one or more of
a number of dimensions. Examples of such dimensions include, but
are not limited to, a diameter, a curvature, a depth (i.e.,
length), a horizontal displacement, and the like. In certain
example embodiments, the well 100 includes a casing string 106
disposed within the wellbore 102. In certain example embodiments,
the casing string 106 comprises a casing segment fitted to each of
the segments of the wellbore 102. In one example embodiment, and as
illustrated in FIG. 1, the casing string 106 includes a conductor
casing 108, a surface casing 110, and a production casing 112. In
certain example embodiments, the casing string 106 includes more or
less segments than those provided in the present example. A segment
of casing string 106 can also be known as a casing tube, casing
pipe, or casing. Each casing pipe of the casing string 106 has a
length and a width (i.e., outer diameter). The length of a casing
pipe can vary. For example, a common length of a casing pipe is
approximately 40 feet. The length of a casing pipe can be longer
(e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width
of the casing pipe can also vary and can depend on the
cross-sectional shape of the casing pipe. In certain example
embodiments, each subsequent casing pipe has a width smaller than
the previous casing pipe and is disposed deeper within the borehole
102. Thus, in certain example embodiments, the casing string 106 is
made up of telescoping casing pipes. The length and width of the
casing pipes as well as the number of casing pipes that make up the
casing string 106 are determined by data collected regarding
various conditions of the environment and the subterranean
formation 104 and the desired well completion.
[0022] As illustrated in FIG. 1, the conductor casing 108 is the
widest casing and includes a proximal end 109a substantially at the
seafloor 118 or surface of the subterranean formation 104 and a
distal end 109b at a first distance from the seafloor 118. The
surface casing 110 is narrower than the conductor casing 108 and
fits therethrough. In certain example embodiments, the surface
casing 110 includes a proximal end 111a extending above the
seafloor 118 and a distal end 111b at a second distance from the
seafloor 118. The certain example embodiments, the second distance
is larger than the first distance and the surface casing 110
extends deeper into the subterranean formation 104. The production
casing 112 is the smallest and deepest casing of the casing string
106. As discussed above, certain other example wells 100 may
include more casing segments. In certain example embodiments, one
or more of the casing segments are coupled to or hung from another
casing segment by a hanger 116, which couples the two casing
segments. In certain example embodiments, one or more of the casing
segments further include casing shoes 114 at respective distal
ends. The casing shoes 114 help guide the casing pipe through
obstacles when being deposited into the wellbore 102. The casing
string 106 is made of one or more of a number of suitable
materials, including by not limited to steel. In certain example
embodiments, the casing string 106 is set along the substantial
length of the wellbore 102.
[0023] In certain example embodiments, the casing string 106 is
cemented to the walls of the wellbore 102. A cement slurry is
injected into the space between the casing string 106 and the
wellbore 102 walls and fills the gaps between the wellbore 102 and
the casing string 106. The cement layer can provide various
functional benefits, including but not limited to, stabilizing and
securing the casing string 106 in the wellbore 102, and protecting
and isolating the completion. In certain example embodiments, each
casing pipe is individually cemented to the respective wellbore
segment.
[0024] In certain example embodiments, the well system 100 further
includes a tubing head spool 122 coupled to the proximal end 111a
of the surface casing 110 or the wellhead. In certain example
embodiments, the tubing head spool 122 is coupled around the
proximal end 111a of the surface casing 110 via a high pressure
seal. The tubing head spool 122 is configured to hang production
tubing 202 (FIG. 2) down the wellbore 102 and seal the annulus
between the surface casing 110 and the production tubing 202. The
size and pressure rating of the tubing head spool 122 can vary
based on one or more of a number of factors, including but not
limited to, the weight of the production tubing 202, the weight of
the casing string 106, and formation conditions. In certain example
embodiments, the well system 100 includes a hub connection 120
coupled to the tubing head spool 122. The hub connection 120
couples the well to a flow line, which delivers the resources
(e.g., gas, oil) produced from the well to a manifold and/or
production facility, where the resources are collected.
[0025] FIG. 2 illustrates the well system 100 at a second stage of
completions, in accordance with example embodiments of the present
disclosure. Referring to FIG. 2, the well system 100 further
includes production tubing 202 disposed within the wellbore 102 and
concentrically traversing the casing 106. As discussed above, the
production tubing 202 is hung from the tubing head spool 122. The
production tubing 202 can also be known as tubing or tubing string.
In certain example embodiments, the production tubing 202 includes
a number of tubing pipes that are mechanically coupled to each
other end-to-end, usually with mating threads. The tubing pipes of
the production tubing 202 can be mechanically coupled to each other
directly or using a coupling device, such as a coupling sleeve. In
certain example embodiments, the production tubing 202 extends from
above the seafloor to substantially the bottom of the wellbore 102
and/or casing string 106.
[0026] Each tubing pipe of a tubing string 202 has a length and a
width (e.g., outer diameter). The length of a tubing pipe can vary.
For example, a common length of a tubing pipe is approximately 30
feet. The length of a tubing pipe can be longer (e.g., 40 feet) or
shorter (e.g., 10 feet) than 30 feet. The width of a tubing pipe
can also vary and can depend on one or more of a number of factors,
including but not limited to the inner diameter of the casing pipe.
For example, the width of the tubing pipe is less than the inner
diameter of the casing pipe. The width of a tubing pipe can refer
to an outer diameter, an inner diameter, or some other form of
measurement of the tubing pipe. Examples of a width in terms of an
outer diameter can include, but are not limited to, 7 inches, 5
inches, and 4 inches.
[0027] In certain example embodiments, a distal end 216 of the
production tubing 202 is located toward the bottom of the wellbore
102, and a proximal end 212 of the production tubing 202 is located
at or above the seafloor 118 and coupled within the tubing head
spool 122. The size (e.g., outer diameter, length) of the
production tubing 202 can be determined based, in part, on the size
and configuration of the casing string 106 and/or the wellbore 102.
The tubing can be made of one or more of a number of suitable
materials, including but not limited to steel. The one or more
materials of the production tubing 202 can be the same or different
than the materials of the casing string 106.
[0028] The production tubing 202 substantially traverses the length
of the well and is configured to deliver the resources from the
well to the surface 118. In certain example embodiments, the
production tubing 202 includes one or more valves, such as a first
valve 206 and a second valve 208. The valves 206, 208 can be
actuated to act as mechanical barriers when it is desired to impede
the upward flow of fluid resources from the subterranean formation
104. In certain example embodiments, one or more of the valves 206,
208 may have an acceptable leak rate.
[0029] In certain example embodiments, the production tubing 202 is
hung from the tubing head spool 122 at the proximal end 212 such
that resources are directed to reach the surface via the production
tubing 202. Furthermore, in certain example embodiments, the
production tubing 202 is coupled to the casing 106 via a tubing
hanger 204. The tubing hanger further secures and stabilizes the
production tubing 202 within the casing 106 and the wellbore
102.
[0030] In certain example embodiments, the cased well 100 and
production tubing 202 are not immediately in communication with the
flow of resource in the reservoir or the subterranean formation 104
after installation. Thus, a plurality of perforations 214 are made
in certain portions of the well to couple the well to the
resources. In certain example embodiments, the plurality of
perforations 214 are made through the production casing 112 and
into the subterranean formation 104. In certain example
embodiments, the plurality of perforations 214 are made through the
production casing 112 and the production tubing 202 and into the
subterranean formation 104. Thus, the well is in fluid
communication with the reservoir and the resources can be brought
to the surface through the production tubing 202.
[0031] In certain example embodiments, the well system 100 includes
a tubing plug 210 disposed within the production tubing 202. The
tubing plug 210 isolates the well and the reservoir from the
surface 118 and the upper portion of the well system 100. The
tubing plug 210 acts as another mechanical barrier configured to
impede the upward flow of resources from the reservoir when the
tubing plug 210 is disposed in the production tubing 202. The
tubing plug 210 is installed when well isolation is desired and can
be removed when the well is put into production. In certain example
embodiments, the tubing plug 210 is installed in the production
tubing 202 after the plurality of perforations 214 are made and
before the well is put into production. In certain example
embodiments, the well is coupled to a BOP when the tubing plug 210
is installed. The tubing plug 210 is to be removed before the well
can produce.
[0032] FIG. 3 illustrates the well system 100 in a third stage of
completion, in accordance with example embodiments of the present
disclosure. In certain example embodiments, after the tubing plug
210 is installed in the production tubing 202 and is tested as an
effective well isolation barrier, the BOP (not shown in FIG. 3) can
be removed and a production tree 302 is placed on top of and
fastened to the tubing head spool 122. In certain example
embodiments, the production tree 302 includes a first valve 304 and
a second valve 306, as shown in the simplified representation
illustrated in FIG. 3. However, in certain example embodiments, the
production tree 302 is much more complex and includes a plurality
of various valves, spools, pressure gauges, chokes, and the like,
which are used to control the flow and recovery of production
fluid. In certain example embodiments, such as that illustrated in
FIG. 3, the production tree 302 is a vertical production tree.
However, in certain other example embodiments of the present
disclosure, the production tree 302 is a horizontal production
tree.
[0033] FIG. 4 illustrates the well system 100 with a plug pulling
device 402, in accordance with an example embodiment of the present
disclosure. Referring to FIG. 4, the plug pulling device 402
includes a closed top end 420 and an open bottom end 422. In
certain example embodiments, the bottom end 422 is securely coupled
to the top of the production tree 302 such that the junction
between the plug pulling device 402 and the production tree 302 is
sealed. In certain example embodiments, the bottom end 422 of the
plug pulling device 402 includes a mating end similar to that of a
BOP and configured to latch onto a standard production tree
connection. The plug pulling device 402 includes a linear inner
cavity 405 extending from the top end 420 to the bottom end 422.
The plug pulling device 402 further includes an elongated shifting
tool 408 disposed within the inner cavity 405. The shifting tool
408 includes a stem 424 and a pulling tool 410 disposed at a distal
end of the stem 424. In certain example embodiments, the shifting
tool 408 has a length substantially similar to or smaller than the
length of the inner cavity 405.
[0034] In certain example embodiments, the plug pulling device 402
includes one or more stabilizing guides 412 disposed within the
inner cavity 405 and surrounding the shifting tool 408. The
stabilizing guides 412 provide support for the shifting tool 408
and keep the shifting tool 408 straight and directed over center.
In certain example embodiments, the stabilizing guides 412 are
concentric rings. The plug pulling device 402 further includes a
seal 414 disposed in the inner cavity 405 between the shifting tool
408 and the inner surface of the housing 403. The seal 414, having
the shifting tool 408 disposed therethrough, separates the inner
cavity 405 of the housing 403 into a first chamber 404 and a second
chamber 406, such that the first chamber 404 is sealed from the
second chamber 406. In certain example embodiments, the first
chamber 404 is defined between the closed top end 422 and the seal
414, and the second chamber 406 is on the opposite side of the seal
414 and adjacent to the open bottom end 422. In certain example
embodiments, the seal 414 is dynamic, allowing the shifting tool
408 is travel up and down therethrough and between the first
chamber 404 and the second chamber 406 while maintaining isolation
between the first chamber 404 and the second chamber 406. In
certain example embodiments, the seal 414 is fabricated from a
low-temperature resistant and corrosion resistant polymer material.
In certain example embodiments, the first chamber 404 is filled
with hydraulic fluid and is communicative with one or more
hydraulic fluid sources (not shown). In certain example
embodiments, the plug pulling device 402 includes at least a first
hot stab 416 and a second hot stab 418. The first hot stab 416 is
coupled to the first chamber 404 and the second hot stab 418 is
coupled to the second chamber 406. The hot stabs 416, 418 are used
to pump hydraulic fluid in and out of the respective chambers 404,
406. In certain example embodiments, the hot stabs 416, 418 are
coupled to a control panel (not shown) which controls actuation of
the hot stabs 416, 418. In certain example embodiments, the hot
stabs 416, 418 are actuated by a remotely operated vehicle (ROV).
In such embodiments, the ROV includes a reservoir of hydraulic
fluid, which provides a source of hydraulic fluid for the hot stabs
416, 418. In certain example embodiments, the plug pulling device
402 includes additional hot stabs (not shown), including but not
limited to, hot stabs for actuating and testing locks and
valves.
[0035] The plug pulling device 402 is configured to send the
shifting tool 408 downward through the production tree 302 and into
the production tubing 202 until the pulling tool 410 mates with the
tubing plug 210. After the pulling tool 410 becomes mechanically
coupled to the tubing plug 210, the plug pulling device 402 lifts
the shifting tool 408 back up into the housing 403. As the shifting
tool 408 is lifted upward, the tubing plug 210 which is
mechanically coupled to the pulling tool 410, is lifted upward as
well and retrieved. Thus, the tubing plug 210 is removed from the
production tubing 202. Inner workings of the plug pulling device
402 are described in further detail below with respect to FIGS. 4,
5, and 6. FIG. 4 illustrates the plug pulling device 402 in an
initial retracted state, prior to deployment of the shifting tool
408 into the production tubing 202, in accordance with example
embodiments of the present disclosure. FIG. 5 illustrates the plug
pulling device 402 in a second state, in which the shifting tool is
deployed into the production tubing 202 and mated with the tubing
plug 210, in accordance with example embodiments of the present
disclosure. FIG. 6 illustrates the plug pulling device 402 in a
third retracted state, in which the shifting tool is pulled back
into the housing 403 with the retrieved tubing plug, in accordance
with example embodiments of the present disclosure.
[0036] Referring to FIG. 4, when the plug pulling device 402 is in
an initial retracted position, the shifting tool 408 is
substantially within the first chamber 404 and contained within the
inner cavity 405 of the plug pulling tool 402. The valves 304, 306
of the production tree 302 are closed when the plug pulling device
402 is first latched onto the production tree 302. After the plug
pulling device 402 is latched onto the production tree 302 and the
connection is sealed, the valves 304, 306 can be opened as the plug
pulling device 402 provides a closed and isolated environment for
the well, or acts as a barrier. Furthermore, the valves 304, 306
need to be open in order for the shifting tool 408 to reach the
production tubing 202. Pressure is then increased inside the first
chamber 404 to push the shifting tool 408 substantially out of the
first chamber 404 and towards the production tubing 202. As the
seal 414 isolates the first chamber 404 and the shifting tool 408
is slidable with respect to the seal, pressure increase within the
first chamber 404 is mitigated by urging the shifting tool 408
further out of the first chamber 404, which increases the available
volume within the first chamber 404. In the example embodiment
described herein, it should be noted that "out of the first
chamber" refers to portions of the shifting tool 408 and not to the
entire shifting tool 408. In other words, in certain example
embodiments, at least a portion of the stem 424 remains within the
first chamber 404 during the entire operation and some portion of
the stem is always disposed within the seal 414 such that the first
chamber 404 is always isolated from the second chamber 406.
[0037] In certain example embodiments, pressure is increased within
the first chamber 404 by pumping additional hydraulic fluid into
the first chamber 404. In certain example embodiments, the ROV
attaches to the first hot stab 416, which is coupled to the first
chamber 404, and controls the hot stab 416 to pump hydraulic fluid
into the first chamber 404 via the hot stab 416. When the pressure
inside the first chamber 404 is large enough to cause a downward
force on the shifting tool 408 that overcomes an upward force on
the shifting tool generated by pressure in the second chamber 406,
the shifting tool 408 begins to move downward towards the tubing
plug 210.
[0038] Referring to FIG. 5, as more hydraulic fluid is pumped into
the first chamber 404, the shifting tool 408 continues to be
further displaced out of the first chamber 404. Thus, the shifting
tool 408 travels further towards the tubing plug 210. In certain
example embodiments, the shifting tool 408 traverses the production
tree 302 via the open valves 304, 306, to reach the tubing plug
210. In certain example embodiments, the stabilizing guides 412
keep the shifting tool 408 straight and centered as the shifting
tool 408 travels towards the tubing plug 210. Hydraulic fluid
continues to be pumped into the first chamber 404 until the
shifting tool 408 latches onto the tubing plug 210. In certain
example embodiments, the tubing plug 210 is shaped and fitted
within the production tubing 202 such that the tubing plug 210 will
not travel further down the production tubing 202. As such, when
the shifting tool 408 reaches the tubing plug 210, the shifting
tool 408 will stop traveling further downward. In certain example
embodiments, this is indicated by pressure measurement within the
first chamber 404.
[0039] In certain example embodiments, the pressure within the
first chamber 404 urges the pulling tool 410 into mechanical
engagement with the tubing plug 210. Specifically, in certain
example embodiments, the pulling tool 410 includes a collapsible
profile which collapses into the tubing plug 210 until the pulling
tool 410 is disposed in an intended resting space of a
complementary shape within the tubing plug 210. In certain example
embodiments, the pulling tool 410 breaks one or more pins within
the tubing plug 210. The pulling tool 410 then expands within the
tubing plug 210 and is latched within the tubing plug. Thus, the
tubing plug 210 is attached to the shifting tool 408 and will
travel with the shifting tool 408. In certain example embodiments,
the tubing plug 210 and the pulling tool 410 utilize various other
mechanical mating mechanisms and techniques which allow the pulling
tool 410 to engage with the tubing plug 210 such that the tubing
plug 210 can be pulled up with the pulling tool 410.
[0040] After the shifting tool 408 latches onto the tubing plug 210
via the pulling tool 410, the shifting tool 408 is pulled up and
out of the production tubing 112 and production tree 302 and back
into the inner cavity 405 of the plug pulling device 402. In
certain example embodiments, the shifting tool 408 is pulled up by
decreasing the pressure in the first chamber 404 relative to the
pressure in the second chamber 406, thereby causing a pressure
differential which urges the shifting tool 408 to travel upward and
into the first chamber 404. In certain example embodiments, this is
done by increasing the pressure in the second chamber 406, which is
in fluid communication with the production tree 302 and the well
when the valves 304, 306 are open. In certain such example
embodiments, the ROV attaches to the second hot stab 218, which is
coupled to the second chamber 406, and pumps hydraulic fluid into
the second chamber 406 to increase the pressure in the second
chamber 406. In certain example embodiments, when the pressure in
the second chamber 408 becomes large enough to overcome the
pressure in the first chamber 404, the shifting tool 408 begins to
move upward and back into the first chamber 404. In certain example
embodiments, as the shifting tool 408 moves further into the first
chamber 404, the hydraulic fluid within the first chamber is
allowed to bleed off. In another example embodiment, the pressure
in the first chamber 404 is reduced by removing hydraulic fluid
from the first chamber 404. Thus, as the pressure in the first
chamber 404 gradually decreases, the pressure in the second chamber
406 becomes relatively larger and the pressure differential between
the first and second chambers 404, 406 urges the shifting tool 408
to move back towards the first chamber 404.
[0041] Referring to FIG. 6, eventually, the pressure differential
created between the first chamber 404 and the second chamber 406
brings the shifting tool 408 back into the first chamber 404 along
with the tubing plug 210. After the shifting tool 408 is moved out
of the production tree 302, the valves 304, 306 of the production
tree 302 are closed and tested. The plug pulling device 402 is then
decoupled from the production tree 302 and a cap is put on the
production tree 302 in place of the plug pulling device 402. In
certain example embodiments, the well system 100 is now ready to be
put into production. It should be understood that, in certain
example embodiments, the foregoing steps can be reversed so that
the plug pulling device 402 is used for plug installation
operations.
[0042] FIG. 7 illustrates a method 700 of pulling a plug from a
subsea well, in accordance with example embodiments of the present
disclosure. Example method 700 includes attaching a plug pulling
device onto a production tree of a well. In certain example
embodiments, the plug pulling device includes a housing and a
shifting tool movably disposed within the housing (step 702). The
method 700 further includes opening one or more valves of the
production tree such that the plug pulling device is communicative
with a production tubing of the well (step 704). The method 700
further includes pushing the shifting tool into the production
tubing until the shifting tool mates with a plug disposed within
the production tubing (step 706). The method 700 also includes
pulling the shifting tool out of the production tubing and back
into the housing of the plug pulling device along with the plug
(step 708). Thus, the plug is retrieved. In certain example
embodiments, the valves of the production tree are then closed and
the plug pulling device is decoupled from the production tree.
[0043] FIG. 8 illustrates another method 800 of pulling a plug from
a subsea well, in accordance with example embodiments of the
present disclosure. Example method 800 includes attaching a plug
pulling device onto a production tree of a well. In certain example
embodiments, the plug pulling device includes a housing and a
shifting tool movably disposed within the housing (step 802). The
method 800 further includes opening one or more valves of the
production tree such that the plug pulling device is communicative
with a production tubing of the well (step 804). The method 800
further includes increasing relative pressure in a first chamber of
the housing until the shifting tool travels into a production
tubing of the well and mates with a tubing plug (step 806). In
certain example embodiments, this is done by injecting hydraulic
fluid into the first chamber. The method 800 also includes
decreasing relative pressure in the first chamber until the
shifting tool and the tubing plug travel back into the housing
(step 808). In certain example embodiments, this is done by
removing hydraulic fluid from the first chamber. Thus, the plug is
retrieved. In certain example embodiments, the valves of the
production tree are then closed and the plug pulling device is
decoupled from the production tree.
[0044] In certain example embodiments, the plug pulling tool 402
can be deployed from a small-scale vessel rather than a MODU. The
vessel has a much smaller cost of operation compared to the MODU. A
plug pulling operation utilizing the presently disclosure
techniques also takes less time than the conventional operation
utilizing a MODU. Thus, the presently disclosed techniques provide
significant improvements in the cost and time efficiency of subsea
plug pulling operations.
[0045] Although embodiments described herein are made with
reference to example embodiments, it should be appreciated by those
skilled in the art that various modifications are well within the
scope and spirit of this disclosure. Those skilled in the art will
appreciate that the example embodiments described herein are not
limited to any specifically discussed application and that the
embodiments described herein are illustrative and not restrictive.
From the description of the example embodiments, equivalents of the
elements shown therein will suggest themselves to those skilled in
the art, and ways of constructing other embodiments using the
present disclosure will suggest themselves to practitioners of the
art. Therefore, the scope of the example embodiments is not limited
herein.
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