U.S. patent application number 13/457062 was filed with the patent office on 2012-12-27 for apparatus and methods for use in establishing and/or maintaining controlled flow of hydrocarbons during subsea operations.
This patent application is currently assigned to BP CORPORATION NORTH AMERICA INC.. Invention is credited to Pierre Albert Beynet, Douglas Paul Blalock, Kevin James Devers.
Application Number | 20120325489 13/457062 |
Document ID | / |
Family ID | 46026982 |
Filed Date | 2012-12-27 |
United States Patent
Application |
20120325489 |
Kind Code |
A1 |
Beynet; Pierre Albert ; et
al. |
December 27, 2012 |
APPARATUS AND METHODS FOR USE IN ESTABLISHING AND/OR MAINTAINING
CONTROLLED FLOW OF HYDROCARBONS DURING SUBSEA OPERATIONS
Abstract
Apparatus includes a seal head having first and second ends and
a sidewall having an internal diameter. The first end of the seal
head is open to the environment, and the second end is closed to
the environment by an end cap. The seal head includes an aperture
configured to accommodate a subsea source. A tubular seal head
extension is fluidly connected to the seal head end cap. The seal
head extension has an external diameter, an external surface, and a
length. A movable element having first and second ends and a
sidewall structure having an internal diameter sufficiently larger
than the external diameter of the extension forms an annulus
between the movable element and the extension. The movable element
first end opens to the environment, while its second end is closed
by an end cap defining an exit fluidly connectable to a subsea
collection system.
Inventors: |
Beynet; Pierre Albert;
(Houston, TX) ; Blalock; Douglas Paul; (Katy,
TX) ; Devers; Kevin James; (Katy, TX) |
Assignee: |
BP CORPORATION NORTH AMERICA
INC.
Houston
TX
|
Family ID: |
46026982 |
Appl. No.: |
13/457062 |
Filed: |
April 26, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61479769 |
Apr 27, 2011 |
|
|
|
Current U.S.
Class: |
166/353 ;
166/367; 166/368 |
Current CPC
Class: |
E21B 43/0122 20130101;
E21B 37/06 20130101 |
Class at
Publication: |
166/353 ;
166/368; 166/367 |
International
Class: |
E21B 43/013 20060101
E21B043/013; E21B 17/01 20060101 E21B017/01; E21B 33/038 20060101
E21B033/038 |
Claims
1. An apparatus comprising: a seal head comprising first and second
ends and a seal head sidewall structure having an internal
diameter, the sidewall structure connecting the first and second
ends, the seal head first end open to the environment, the seal
head second end closed to the environment by an end cap, the seal
head further comprising at least one aperture configured to
accommodate a subsea source of hydrocarbons; a tubular seal head
extension fluidly connected to the end cap of the seal head, the
tubular seal head extension having an internal diameter less than
the internal diameter of the seal head, an external diameter, an
external surface, and a length; and a movable element comprising
first and second ends and a sidewall structure having an internal
diameter sufficiently larger than the external diameter of the
tubular seal head extension to form an annulus there between, the
movable element sidewall structure connecting the movable element
first and second ends, the movable element first end open to the
environment, and the movable element second end closed to the
environment by a movable element end cap defining an exit fluidly
connectable to a subsea collection system.
2. The apparatus of claim 1 wherein the movable element comprises a
first end opening configured to slidingly engage the external
surface of the tubular seal head extension along its length.
3. The apparatus of claim 1 wherein the seal head comprises a
second tubular member.
4. The apparatus of claim 3 wherein the movable element comprises a
third tubular member.
5. The apparatus of claim 1 wherein the at least one aperture is in
a seal head sidewall structure and is selected from curve-shaped
apertures and non-curve-shaped apertures.
6. The apparatus of claim 5 wherein the curve-shaped apertures are
selected from U-shaped apertures, parabolic apertures, and circular
apertures.
7. The apparatus of claim 5 wherein the non-curve-shaped apertures
are selected from square apertures, triangular apertures, and
trapezoidal apertures.
8. The apparatus of claim 5 wherein the at least one apertures
comprise one or more flexible sealing members.
9. The apparatus of claim 2 wherein the external surface of the
tubular seal head extension is polished.
10. The apparatus of claim 9 wherein the opening of the movable
element first end comprises a polished internal surface configured
to engage the polished external surface of the tubular seal head
extension.
11. The apparatus of claim 4 wherein the third tubular is
connectable to a drill string.
12. The apparatus of claim 2 wherein the movable element first end
further comprises a second opening configured to allow material to
escape.
13. The apparatus of claim 1 further comprising one or more ROV
handles attached to the seal head.
14. The apparatus of claim 1 further comprising one or more ROV
handles attached to the movable element.
15. The apparatus of claim 1 wherein the seal head further
comprises one or more access points for a functional fluid.
16. The apparatus of claim 1 wherein the movable element further
comprises one or more access points for a functional fluid.
17. An apparatus comprising: a first tubular comprising first and
second ends and a first tubular sidewall structure having an
internal diameter, the sidewall structure connecting the first and
second ends, the first end of the first tubular open to the
environment, the first tubular second end closed to the environment
by an end cap, the first tubular comprising at least one aperture
in the first tubular sidewall structure configured to accommodate a
subsea source of hydrocarbons; a second tubular fluidly connected
to the end cap of the first tubular, the second tubular having an
internal [diameter less than the internal diameter of the first
tubular, an external diameter, an external surface, and a length;
and a third tubular comprising first and second ends and a sidewall
structure having an internal diameter sufficiently larger than the
external diameter of the second tubular to form an annulus there
between, the third tubular sidewall structure connecting the third
tubular first and second ends, the third tubular first end open to
the environment, and the third tubular second end closed to the
environment by a third tubular end cap defining an exit fluidly
connectable to a subsea collection system.
18. A method comprising: deploying a fluid collection apparatus
from a surface vessel subsea near a subsea source of hydrocarbons,
the apparatus comprising: a seal head comprising first and second
ends and a seal head sidewall structure having an internal
diameter, the sidewall structure connecting the first and second
ends, the seal head first end open to the environment, the seal
head second end closed to the environment by an end cap, the seal
head comprising at least one aperture configured to accommodate a
subsea source; a tubular seal head extension fluidly connected to
the end cap of the seal head, the tubular seal head extension
having an internal diameter less than the internal diameter of the
seal head, an external diameter, an external surface, and a length;
and a movable element comprising first and second ends and a
sidewall structure having an internal diameter sufficiently larger
than the external diameter of the tubular seal head extension to
form an annulus there between, the movable element sidewall
structure connecting the movable element first and second ends, the
movable element first end open to the environment, and the movable
element second end closed to the environment by a movable element
end cap defining an exit fluidly connected to the vessel by a
subsea collection system; positioning the apparatus to collect
hydrocarbons from the source of hydrocarbons; and collecting
hydrocarbons using the apparatus and the subsea collection
system.
19. A method comprising: deploying a subsea collection system and a
fluid collection apparatus from a surface vessel subsea near a
subsea source of hydrocarbons, the apparatus comprising: a seal
head comprising first and second ends and a seal head sidewall
structure having an internal diameter, the sidewall structure
connecting the first and second ends, the seal head first end open
to the environment, the seal head second end closed to the
environment by an end cap, the seal head comprising at least one
aperture configured to accommodate a subsea source of hydrocarbons;
a tubular seal head extension fluidly connected to the end cap of
the seal head, the tubular seal head extension having an internal
diameter less than the internal diameter of the seal head, an
external diameter, an external surface, and a length; and a movable
element comprising first and second ends and a sidewall structure
having an internal diameter sufficiently larger than the external
diameter of the tubular seal head extension to form an annulus
there between, the movable element sidewall structure connecting
the movable element first and second ends, the movable element
first end open to the environment, and the movable element second
end closed to the environment by a movable element end cap defining
an exit fluidly connected to the vessel by the subsea collection
system; positioning the apparatus to collect hydrocarbons from the
source of hydrocarbons; displacing seawater from the subsea
collection system and the fluid collection apparatus by forcing a
low-density gas down the subsea collection system at least during
the positioning of the apparatus until the gas bubbles out of a
first end of the fluid collection apparatus, limiting ingress of
seawater or hydrocarbon gas hydrates into the subsea collection
system and apparatus thus limiting plugging of the subsea
collection system and apparatus; moving the surface vessel so that
the apparatus is a few meters above the subsea source, with the
apparatus in the hydrocarbon plume; landing the seal head of the
fluid collection apparatus on the subsea source, while the
apparatus remains filled with low-density gas; gradually reducing
flow of the gas and gradually opening a choke to establish and
maintain flow of collected hydrocarbons up the apparatus and subsea
collection system.
20. The method of claim 19 further comprising pumping a functional
fluid into the apparatus through one or more valves on the
apparatus during at least the collecting step, limiting hydrocarbon
gas hydrate formation during the collecting of hydrocarbons.
21. The method of claim 19 further comprising monitoring flow into
and out of the first end of the movable element.
22. The method of claim 19 further comprising allowing the movable
element and attached subsea collection system to move up and down
with heave of the surface vessel.
23. The method of claim 19 further comprising guiding positioning
of the apparatus using one or more ROVs.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to and claims priority under 35
U.S.C. .sctn.119(e) to assignee's U.S. provisional patent
application Ser. No. 61/479,769, filed Apr. 27, 2011, incorporated
herein by reference.
BACKGROUND INFORMATION
[0002] 1. Technical Field
[0003] The present disclosure relates in general to tools
(apparatus) and methods useful in the subsea marine hydrocarbon
exploration, production, well drilling, well completion, well
intervention, and containment and disposal fields.
[0004] 2. Background Art
[0005] Assignee's U.S. provisional patent application Ser. No.
61/479,769, filed Apr. 27, 2011, describes broadly methods of using
nitrogen or other low-density fluid to establish and/or maintain
hydrocarbon flow in a riser from a subsea source to one or more
surface vessels during subsea marine operations such as hydrocarbon
containment and disposal operations, hydrocarbon exploration,
production, well drilling, well completion, and well
intervention.
SUMMARY
[0006] Apparatus of the present disclosure may be used to establish
and/or maintain hydrocarbon flow in a riser extending from one or
more subsea sources to one or more surface vessels.
[0007] A first aspect of the disclosure is an apparatus comprising:
[0008] a seal head comprising first and second ends and a seal head
sidewall structure having an internal diameter, the sidewall
structure connecting the first and second ends, the seal head first
end open to the environment, the seal head second end closed to the
environment by an end cap, the seal head comprising at least one
aperture configured to accommodate a subsea source; [0009] a
tubular seal head extension fluidly connected to the end cap of the
seal head, the tubular seal head extension having an internal
diameter less than the internal diameter of the seal head, an
external diameter, an external surface, and a length; and [0010] a
movable element comprising first and second ends and a sidewall
structure having an internal diameter sufficiently larger than the
external diameter of the tubular seal head extension to form an
annulus there between, the movable element sidewall structure
connecting the movable element first and second ends, the movable
element first end open to the environment, and the movable element
second end closed to the environment by a movable element end cap
defining an exit fluidly connectable to a subsea collection
system.
[0011] In certain embodiments, the seal head, tubular seal head
extension, and movable element may each comprise a tubular member.
In other embodiments the movable element may have a diameter
sufficiently large to serve as a gas/liquid separator, and in
certain embodiments as a gas/first liquid/second liquid and solids
separator. In certain embodiments the apparatus may comprise more
than one seal head fluidly connected to the movable element.
[0012] A second aspect of the disclosure are methods of using an
apparatus of this disclosure, comprising:
[0013] deploying a fluid collection apparatus from a surface vessel
subsea near a subsea source of hydrocarbons, the apparatus
comprising: [0014] a seal head comprising first and second ends and
a seal head sidewall structure having an internal diameter, the
sidewall structure connecting the first and second ends, the seal
head first end open to the environment, the seal head second end
closed to the environment by an end cap, the seal head comprising
at least one aperture configured to accommodate a subsea source;
[0015] a tubular seal head extension fluidly connected to the end
cap of the seal head, the tubular seal head extension having an
internal diameter less than the internal diameter of the seal head,
an external diameter, an external surface, and a length; and [0016]
a movable element comprising first and second ends and a sidewall
structure having an internal diameter sufficiently larger than the
external diameter of the tubular seal head extension to form an
annulus there between, the movable element sidewall structure
connecting the movable element first and second ends, the movable
element first end open to the environment, and the movable element
second end closed to the environment by a movable element end cap
defining an exit fluidly connected to the vessel by a subsea
collection system; positioning the apparatus to collect
hydrocarbons from the source of hydrocarbons; and [0017] collecting
hydrocarbons using the apparatus and subsea collection system.
[0018] Certain method embodiments may comprise: [0019] displacing
seawater from the subsea collection system and apparatus by forcing
a low-density gas down the subsea collection system at least during
the positioning of the apparatus until the gas bubbles out of the
first end of the seal head, limiting ingress of seawater or
hydrocarbon gas hydrates into the subsea collection system and
apparatus thus limiting plugging of the subsea collection system
and apparatus; [0020] moving the surface vessel so that the
apparatus is a few meters above the subsea source, with the
apparatus in the hydrocarbon plume; [0021] landing the seal head of
the fluid collection apparatus on the subsea source, while the
apparatus remains filled with low-density gas; and [0022] gradually
reducing flow of the gas and gradually opening a choke to establish
and maintain flow of collected hydrocarbons through the apparatus
and subsea collection system.
[0023] These and other features of apparatus and methods of the
disclosure will become more apparent upon review of the brief
description of the drawings, the detailed description, and the
claims that follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0024] The manner in which the objectives of this disclosure and
other desirable characteristics may be obtained is explained in the
following description and attached drawings in which:
[0025] FIG. 1 is a schematic side view of a subsea collection
system employing an apparatus and method in accordance with the
present disclosure;
[0026] FIG. 2 is a more detailed schematic cross-sectional view of
the apparatus illustrated in FIG. 1;
[0027] FIGS. 3, 4, and 5 are detailed schematic perspective views,
with portions cut away, of three apparatus embodiments in
accordance with the present disclosure;
[0028] FIGS. 6 and 7 are schematic side elevation views of two
other seal head embodiments, with FIG. 7A illustrating a schematic
plan view of the embodiment illustrated in FIG. 7; and
[0029] FIGS. 8 and 9 are logic diagrams of two method embodiments
in accordance with the present disclosure.
[0030] It is to be noted, however, that the appended drawings are
not necessarily to scale and illustrate only typical embodiments of
this disclosure, and are therefore not to be considered limiting of
its scope, for the disclosure may admit to other equally effective
embodiments.
DETAILED DESCRIPTION
[0031] In the following description, numerous details are set forth
to provide an understanding of the disclosed methods. However, it
will be understood by those skilled in the art that the methods
covered by the claims may be practiced without these details and
that numerous variations or modifications from the specifically
described embodiments may be possible and are deemed within the
claims. All U.S. published patent applications and U.S. patents
referenced herein are hereby explicitly incorporated herein by
reference. In the event definitions of terms in the referenced
patents and applications conflict with how those terms are defined
in the present application, the definitions for those terms that
are provided in the present application shall be deemed
controlling.
[0032] Apparatus and methods of this disclosure may be employed for
deepwater subsea containment, disposal, production, and well
intervention. While many of the methods described herein may be
used in the context of containment and disposal, it is explicitly
noted that the methods described herein are not restricted to
containment and disposal operations, but may be used in conjunction
with any "subsea source", as that term is defined herein. As used
herein, the term "collection system" includes any facility,
component, assembly, and the like, such as a subsea riser and fluid
transfer system that may fluidly connect an apparatus of the
present disclosure to a surface vessel. As used herein the term
"upstream" when used to describe deployment of a collection system,
riser and/or collection tool means the collection system, riser
and/or collection tool is/are not in the plume of hydrocarbons
emanating from a subsea source. As used herein the term
"hydrocarbon gas hydrates" means hydrates formed from hydrocarbon
gases selected from the group consisting of methane, ethane,
propane, butane, isobutane, isobutene and mixtures thereof. The
methods of the present disclosure may be fully or partially
implemented before, during, and after a collection system and
apparatus of the present disclosure are deployed to collect
hydrocarbons from a subsea component that has been compromised (for
example, but not limited to, a subsea well blowout, damaged subsea
blow out preventer (BOP), damaged subsea riser or other subsea
conduit, damaged subsea manifold, and the like), and/or other
subsea source(s), such as seeps from the seafloor, and may be used
in any marine environment, but are particularly useful in deep and
ultra-deep subsea marine environments. The methods may also be used
to control and/or totally prevent hydrocarbon gas hydrate formation
during deployment of a subsea riser prior to and during a subsea
operation to collect hydrocarbons producing naturally. Methods of
the disclosure may also be used to start the flow or enhance the
flow rate of source fluids using gas lift principles by injecting
nitrogen or other gas, with or without produced gas, near the lower
end of the riser.
[0033] In the containment and disposal context, in certain
embodiments the methods described herein may be used in subsea
marine environments to establish and/or maintain flow of material
(hydrocarbons, or fluids comprising hydrocarbons) in a riser from a
subsea source to one or more surface vessels. As used herein, the
phrases "maintain flow" and "maintaining flow" mean controlling
and/or totally preventing hydrocarbon gas hydrate formation during
deployment of a subsea collection system and apparatus. The terms
"establishing flow" and "maintaining flow" may also comprise using
gas lift or subsea pumping methods. Both the establishment and
maintenance of flow may involve preventing, managing, mitigating,
and/or controlling hydrocarbon gas hydrate formation directly in
the collection system and apparatus hydrocarbon flow passage prior
to, during deployment, and during use of the collection system and
apparatus, and any subsea equipment, accessory components, and the
like attached to the collection system and apparatus for
containment and disposal operations, as well as other operations.
The methods and apparatus of this disclosure may not only be used
for containment and disposal operations, but may also be used for
exploration, production, drilling, completion, and intervention. In
certain embodiments, a chamber filled with low-density fluid may be
formed in the collection tool, allowing the establishing of a
shielded flow of hydrocarbons from the source of hydrocarbons. By
"shielded flow" is meant that the flow of hydrocarbons is shielded
from substantial contact with seawater. Since water is a necessary
ingredient in formation of hydrocarbon gas hydrates, this
advantageously mitigates their formation.
[0034] Certain apparatus of the present disclosure, which may be
referred to alternatively herein as "collection tools", "fluid
collection tools", "fluid collection apparatus", or simply "tools",
may comprise a seal head comprising first and second ends and a
seal head sidewall structure having an internal diameter, the
sidewall structure connecting the first and second ends. The seal
head first end may be open to the environment, and the seal head
second end may be closed to the environment by an end cap, the seal
head comprising at least one aperture in the sidewall structure or
first end configured to accommodate a subsea source, for example a
damaged subsea riser or pipeline, or a subsea seep.
[0035] Certain apparatus may comprise a tubular seal head extension
fluidly connected to the end cap of the seal head, the tubular seal
head extension having an internal diameter less than the internal
diameter of the seal head, an external diameter, an external
surface, and a length.
[0036] Certain apparatus may comprise a movable element comprising
first and second ends and a sidewall structure having an internal
diameter sufficiently larger than the external diameter of the
tubular seal head extension to form an annulus there between. In
certain embodiments the movable element sidewall structure may
connect the movable element first and second ends, the movable
element first end open to the environment, and the movable element
second end closed to the environment by a movable element end cap
defining an exit fluidly connectable to a subsea collection
system.
[0037] In certain apparatus embodiments the movable element may
comprise a first end opening configured to slidingly engage the
external surface of the tubular seal head extension along its
length.
[0038] In certain apparatus embodiments the seal head may comprise
a second tubular member, and the movable element may comprise a
third tubular member.
[0039] In certain apparatus embodiments the at least one aperture
in the seal head sidewall structure may be selected from
curve-shaped apertures and non-curve-shaped apertures. Curve-shaped
apertures may be selected from U-shaped apertures, parabolic
apertures, circular apertures, and the like. Non-curve-shaped
apertures may be selected from square apertures, triangular
apertures, trapezoidal apertures, and the like.
[0040] In certain apparatus embodiments the at least one aperture
may comprise one or more flexible sealing members generally
adjacent the edges of the aperture, for example, but not limited
to, rubber sealing members.
[0041] In certain apparatus embodiments the external surface of the
tubular seal head extension may be polished. In certain apparatus
embodiments the opening of the movable element first end may
comprise a polished internal surface configured to engage the
polished external surface of the tubular seal head extension.
[0042] In certain apparatus embodiments wherein the movable member
is a third tubular, the third tubular may be connectable to a drill
string.
[0043] In certain apparatus embodiments the movable element first
end may comprise a second opening configured to allow material to
escape, such as a small amount of hydrates, viewable subsea for
example by a diver or a remotely operable vehicle (ROV). Certain
apparatus embodiments may comprise one or more ROV handles attached
to the seal head. Certain apparatus embodiments may comprise one or
more ROV handles attached to the movable element.
[0044] In certain apparatus embodiments the seal head may comprise
one or more access points for a functional fluid. In certain
apparatus embodiments the movable element may comprise one or more
access points for a functional fluid.
[0045] Certain method embodiments may comprise deploying a fluid
collection apparatus of the present disclosure from a surface
vessel subsea near a subsea source of hydrocarbons, positioning the
apparatus to collect hydrocarbons from the source of hydrocarbons,
and collecting hydrocarbons using the apparatus and subsea
collection system.
[0046] Certain method embodiments may comprise displacing seawater
from the subsea collection system and apparatus by forcing a
low-density gas into the subsea collection system at least during
the positioning of the apparatus until the gas bubbles out of the
first end of the seal head, limiting ingress of seawater or
hydrocarbon gas hydrates into the subsea collection system and
apparatus thus limiting plugging of the subsea collection system
and apparatus. Certain methods may comprise moving the surface
vessel so that the apparatus is a few meters above the subsea
source, with the apparatus in the hydrocarbon plume. Certain
methods may comprise landing the seal head on the subsea source,
while the apparatus remains filled with low-density gas, and
gradually reducing flow of the gas and gradually opening a choke to
establish and maintain flow of collected hydrocarbons up the
apparatus and subsea collection system.
[0047] Certain method embodiments may comprise pumping a functional
fluid into the apparatus through one or more valves or other access
points on the apparatus during at least the collecting step,
limiting hydrocarbon gas hydrate formation during the collecting of
hydrocarbons.
[0048] Certain method embodiments may comprise monitoring flow into
and/or out of the first end of the movable element.
[0049] Certain method embodiments may comprise allowing the movable
element and attached subsea collection system to move up and down
with heave of the surface vessel.
[0050] Certain method embodiments may comprise guiding positioning
of the apparatus using one or more ROVs.
[0051] Certain method embodiments may comprise connecting riser
sections at or near the sea surface on one or more surface vessels.
Certain embodiments may comprise constructing the riser using high
strength steel tubulars using threaded coupled connectors. In
certain embodiments the tubulars and the threaded coupled
connectors may be insulated. In certain embodiments the insulated
tubulars may be vacuum-insulated tubulars. In certain embodiments
the riser may be constructed of one or more tubulars selected from
the group consisting of drill pipe, reel pipe, flexible pipe,
composite pipe, and hose.
[0052] Certain method embodiments may comprise controlling
hydrocarbon gas hydrate formation by limiting contact of liquids or
solids with inner surfaces of the collection system and tool during
at least the positioning of the tool subsea. In certain embodiments
a functional fluid may be pumped into the tool, the functional
fluid selected from the group consisting of wax inhibitor,
asphaltene inhibitor, hydrocarbon gas hydrate inhibitor, and
combinations thereof. In certain embodiments, a dispersant chemical
may be introduced into any hydrocarbons mixing with seawater.
Methods of this disclosure where one or more functional fluids are
used in the tool in conjunction with a low-density fluid being
forced down the collection system, and optionally a dispersant
chemical, are deemed methods of limiting formation of hydrocarbon
gas hydrates, whereas methods of using only a low-density fluid
forced down the collection system (and tool, if present during
deployment) and optionally a dispersant, are deemed methods of
controlling hydrocarbon gas hydrate formation. In the latter
methods, the risk of hydrate formation is higher, but the form of
the hydrate may be controlled to a manageable level by preventing
flakes of hydrates forming drifts, or hard compactions of
hydrocarbon gas hydrates.
[0053] As used herein the phrase "on the seabed", when used to
describe location of a tool or other item, is understood to include
tools in baskets, or on platforms or manifolds, that are in turn
resting directly on (touching) the seabed. As used herein "ceasing
the forcing of low-density fluid" means the forcing of the
low-density fluid down the collection system, riser, or other
facility, is gradually reduced and then stopped during the
collection step.
[0054] In certain method embodiments the collection tool may be
designed to be positioned over a leaking riser or other subsea
hydrocarbon source. In certain embodiments, tools of the present
disclosure may comprise a large diameter lower conduit, for example
a 32 inch (81 cm) diameter pipe, which has U-cuts or equivalent to
accommodate a riser or pipeline laying on or above the seabed and a
drill pipe (if present) also laying on or above the seabed. At its
upper end the large diameter conduit may have a smaller diameter
conduit (for example 10 inches (25 cm) diameter) attached thereto,
which may function as a chimney. The smaller diameter conduit
extends upward into (and may slidingly engage) another conduit, for
example a pipe having diameter intermediate to the large and small
diameter conduits. This tool and variations of it and their
operation are further described herein.
[0055] In certain method embodiments the surface vessel may be a
drill ship or vessel including a drilling rig, and the collection
system may include a riser having an upper end connected to the
drill ship or drilling rig. In certain embodiments the surface
vessel may be a mobile offshore drilling unit (MODU). In certain
embodiments the surface vessel may be a floating storage and/or
off-loading vessel, such as a floating production, storage, and
off-loading (FPSO) vessel. The surface vessel may be moored to a
turret, or dynamically positioned, or both.
[0056] In certain embodiments the low-density fluid may be selected
from the group consisting of nitrogen, nitrogen-enriched air,
helium, chlorine, hydrogen, argon, krypton, neon, dehumidified
versions of any of these, and/or any mixture thereof. In certain
embodiments the low-density fluid may comprise a gas atmosphere
consisting essentially of nitrogen, where the phrase "consisting
essentially of nitrogen" means that the gas atmosphere is mostly
nitrogen plus any allowable impurities that would not affect the
ability of the nitrogen to limit hydrocarbon gas hydrate formation.
The pressure of the low-density fluid in the riser near the distal
end of the riser and in the tool attached to the riser should be
such as to permit outward flow of the nitrogen (or other gas)
during deployment and before start up.
[0057] In certain methods the connecting of the riser sections may
comprise connecting drill pipe riser sections, or other riser
sections, using threaded joints. In certain methods the connecting
of riser sections may comprise connecting sections of insulated
pipe using threaded or other joints; in certain embodiments the
threaded joints may be vacuum insulated tubing with insulation
covers for the threaded connections.
[0058] In certain methods, if flow up the riser or other collection
system is not sufficient, certain methods may comprise providing an
auxiliary method to achieve sufficient flow selected from the group
consisting of pumping the hydrocarbon up the riser using a subsea
pump, employing gas lift with a non-oxidizing mixture of collected
gas (with or without added nitrogen) added through an umbilical or
coiled tubing employing a compressor, and employing gas lift using
a flue gas (with or without added nitrogen) added through an
umbilical or coiled tubing employing a compressor.
[0059] In certain other embodiments the riser may further comprise
one or more drill collars in the string, for example near the
distal end of a drill pipe riser, in order to provide weight to the
drill pipe riser during deployment.
[0060] As used herein the phrase "subsea source" includes, but is
not limited to: 1) production sources such as subsea wellheads,
subsea BOPs, other subsea risers, subsea manifolds, subsea piping
and pipelines, subsea storage facilities, and the like, whether
producing, transporting and/or storing gas, liquids, or combination
thereof, including both organic and inorganic materials; 2) subsea
containment sources of all types, including damaged subsea BOPs,
risers, manifolds, tanks, and the like; and 3) fissures or openings
in the sea floor.
[0061] Certain hydrate inhibition method embodiments include those
wherein the hydrate-inhibitor liquid chemical is selected from the
group consisting of alcohols (such as methanol, ethanol, and the
like) and glycols (such as ethylene glycol, propylene glycol, and
the like, and mixtures of glycols). An important property of
propylene glycol is its ability to lower the freezing point of
water. This results in its use in the formulation of antifreeze
mixtures. Propylene glycol is almost as efficient as ethylene
glycol in antifreeze applications. Solutions of inhibited propylene
glycol (propylene glycol containing a corrosion inhibitor) may also
be employed.
[0062] In certain method embodiments a hydrocarbon dispersant may
be employed, for example pumped around the base of a seal head, or
around the bottom of a movable element. One suitable dispersant may
be the chemical known under the trade designation COREXIT.RTM.,
whose composition is given more fully herein.
[0063] Yet other method embodiments comprise, in the event of a
hurricane or planned disconnect, disconnecting the collection
system and movable element in a controlled manner using upward
force, which force may have a lateral component. Even if not
performed in a controlled manner, such as during an unplanned
weather event, or ship malfunction event, apparatus of the present
disclosure are designed such that the movable element may
disconnect from the seal head extension and seal head without
extensive damage to the seal head, seal head extension, movable
element, and collection system. In the case of a surface vessel
drive off the movable element is just dragged off by the drill pipe
or other collection system. Optional nylon or other cables attached
to the movable element and seal head may break, leaving the seal
head and seal head extension on the seafloor. It is preferable to
close the upper choke prior to disconnecting to prevent the sucking
up of water in the riser. Once disconnected a low-density fluid may
be pumped into the riser to mix with or displace the hydrocarbons
and permit seawater to fill up the riser prior to retrieving
it.
[0064] In certain method embodiments, if cooling at the surface or
subsea choke is excessive during collection of the hydrocarbons,
the hydrocarbon flow may be heated prior to the choke by pumping
heated seawater into an annulus between the riser and an external
riser, or heating the oil on the deck of the surface vessel.
[0065] The primary features of the methods of the present
disclosure will now be described with reference to the drawing
figures, after which some of the operational details will be
further explained. In accordance with the present disclosure, FIG.
1 is a schematic side view of a subsea collection system 100
employing an apparatus 8 and method in accordance with the present
disclosure. A surface vessel 2, for example an MODU on the sea
surface 3, is illustrated as having a drill string 4 attached
thereto. In certain embodiments, for example if surface vessel 2 is
an FPSO, a fluid transfer system 5 may be provided, and one or more
drill collars 6, which are essentially heavier, more robust
sections of drill pipe. Drill pipe 4, or a drill collar 6 as the
case may be, is fluidly connected to a collection tool 8 of the
present disclosure, illustrated schematically as sealing around a
damaged riser 10 having an internal drill pipe or service pipe 12
partially buried in mud on seafloor 14.
[0066] Examples of useful fluid transfer systems may be the fluid
transfer systems described in assignee's co-pending U.S.
provisional patent application serial number 61480368, filed Apr.
28, 2011, incorporated herein by reference, comprising a fluid
connector assembly configured to connect a subsea system designed
to route hydrocarbon fluids from a subsea source to a surface
vessel and disconnect on command. The fluid connector assembly may
comprise a hydraulic quick disconnect fluid connector comprising a
first quick disconnect portion detachable from a second quick
disconnect portion upon receipt of a disconnect command. The
assembly may comprise a first hydraulically-operated isolation
valve in the first quick disconnect portion, and a second
hydraulically-operated isolation valve in the second quick
disconnect portion, the isolation valves configured to close upon
receipt of a close command, and a plurality of hydraulic
fluid-conveying tubes, at least one tube connected to each of the
valves and to the hydraulic quick disconnect fluid connector, and
configured to execute the disconnect and close commands.
[0067] FIG. 2 is a more detailed schematic cross-sectional view of
collection tool 8 illustrated in FIG. 1. Collection tool 8
includes, in this embodiment, a seal head 20, which in certain
embodiments may be a large diameter conduit, and a tubular seal
head extension 18, which in certain embodiments may be a small
diameter conduit. A sliding seal 16, which in certain embodiments
may be a conduit having a diameter intermediate that of seal head
20 and seal head extension 18, is also included in embodiment 8. In
embodiment 8 seal head 20 includes apertures 22 and 24
accommodating damaged riser 10 and a drill pipe or service pipe 12,
respectively. As more fully explained herein in reference to FIG.
4, a polished seal area 26 may be included. FIG. 2 schematically
illustrates a formation of hydrates 28 on the inside of sliding
seal 16 and external of tubular seal head extension 18, and a layer
of liquid hydrocarbons 30. A small amount of escaping hydrates 32
may be allowed so as to confirm their formation and take remedial
action, as further explained herein. A pair of nylon ropes or other
cables 34 may be attached on stops variously positioned on seal
head 20 and sliding seal 16 as illustrated. Cables 34 may be
advantageous in case of surface vessel 2 drive-off or inclement
weather, allowing sliding seal 16 to detach from the remainder of
collection tool 8 in case sealing head 20 becomes snagged. During
normal operation, hydrocarbons and other produced fluids travel
through collection tool 8 as indicated by arrow 36 and drill pipe 4
or other collection system to surface vessel 2.
[0068] FIGS. 3 and 4 are detailed schematic perspective views, with
portions cut away, of two collection tool embodiments 70 and 80 in
accordance with the present disclosure. Embodiment 70 illustrated
in FIG. 3 includes flexible sealing members 38 adjacent apertures
22 and 24. Flexible sealing members 38, which may be for example
rubber or other flexible member, encourage sealing of seal head 20
about a subsea source, such as a damaged riser (not illustrated in
FIG. 3). Also depicted schematically in FIG. 3 is a weld area 40
where seal head extension 18 is secured to a top flange or end 41
of seal head 20, and a weld area 42, where drill pipe 4 connects to
a first end 44 of sliding seal 16. Rather than welding, weld areas
40 and 42 may be replaced by other fasteners known for use with
subsea well heads, such as flanged connections, dog connectors, and
the like. Seal head 20 includes a second end 43 that enters into
mud on the seafloor. A sidewall structure 49 of seal head 20
connects first end 41 and second end 43, and a sidewall structure
17 of sliding seal 16 connects to first end 44. In embodiment 70,
sliding seal member 16 does not include a bottom end, as may be
seen in the cut-out section 45 of sliding seal member 16. Rather,
the lengths and relative diameters of sliding seal member 16 and
tubular seal head extension 18 are sufficient, along with the
relative densities of hydrocarbons, seawater, and any hydrates
formed, to prevent significant escape of hydrocarbons from sliding
seal member 16 bottom area. Included in embodiment 70 are an
optional ROV handle 46 on seal head 20 and an optional ROV handle
48 on sliding seal member 16, which, as those familiar with this
art will recognize, may be placed on the collection tool 70 in many
locations, and are merely examples. A double-headed arrow in FIG. 3
indicates the possible movement directions of sliding seal member
16 as the surface vessel heaves up and down.
[0069] In other embodiments, such as in embodiment 80 illustrated
schematically in FIG. 4, a low pressure polished seal area 26 on
the external surface of tubular seal head extension 18 may be
provided which seals against a polished bore 19 in a bottom plate
47 of sliding seal member 16. In embodiment 80, the external
surface of tubular seal head extension 18 may be polished at least
along the length where it is expected to engage polished bore 19.
One or more pilot holes 50 may be provided in bottom plate 47 to
witness escape of any hydrates that may form, for example by a
camera attached to an ROV. Pilot holes may be equipped with
downward tubular extensions to substantially prevent water mixing
with the collected fluid, such as illustrated at 501 in FIG. 5.
[0070] Optionally, embodiments 70 and 80, and other embodiments
within the present disclosure, may include one or more access
valves 52 and 54. Access valves may allow one or more functional
fluids to be pumped into seal head 20 and/or sliding seal member
16, respectively, for example a hydrate inhibitor fluid.
[0071] In embodiments 70 and 80 of FIGS. 3 and 4 respectively,
sliding seal member 16 may have a length ranging from about 5 ft.
to about 150 ft. (about 1.5 m to about 46 m) or longer, or from
about 5 ft. to about 75 ft. (from about 1.5 m to about 23 m), or
from about 5 ft. to about 20 ft. (about 1.5 m to about 6 m), but in
any case is long enough to overlap with a substantial portion of
the length of seal head extension 18 so that a top open end 21 of
tubular seal head extension 18 is within the cavity formed by
sidewall structure 17 of seal head extension 18. Similarly, the
ratio of external diameter of tubular seal head extension 18 and
internal diameter of sidewall structure 17 of sliding seal member
16 should be small enough to allow movement between the two and
form an annulus 60 between the two. Note that sizes (diameters) of
seal head 20, tubular seal head extension 18, and sliding seal
member 16 may be changed from those discussed above, with possible
sacrifice in response time. Piping of 21-inch (53 cm) and 10-inch
(25 cm) diameter may be available in 20-foot (6.1 m) sections,
enough to provide the telescopic stroke of seal head extension 18
in sliding seal member 16.
[0072] FIG. 5 is a schematic perspective view of another apparatus
embodiment 90 with the present disclosure, illustrating additional
features of various embodiments. Embodiment 90 is illustrated
sealing around a damaged riser 10 laying on seafloor 14 (both
damaged riser 10 and seafloor 14 illustrated in phantom). For
example, embodiment 90 may include a larger diameter movable member
160 having a sidewall surface 170 connecting ends 440 and 470.
Movable member 160 may have an internal diameter that is several
times, or even several ten times or more than that of the external
diameter of seal head extension 18, allowing movable member 160 to
function as a separator, for example, a gas/liquid separator, or
liquid/liquid separator, or gas/first liquid/second liquid
separator, or gas/liquid/solid separator. As viewed through cut-out
portion 450 of sidewall 170, movable member 160 may also include
one or more optional internal baffles or separation enhancement
members, 180, attached to the inside surface of movable member 160,
for example by welding, riveting, and the like.
[0073] Another optional feature may be the provision of one or more
stabilizing guide legs, such as guide legs 91 and 92 in FIG. 5
extending from near the bottom of seal head 20, and which penetrate
into seafloor 14. One of guide legs 91, 92 may be longer than the
other, as illustrated in FIG. 5, where guide leg 91 is longer than
guide leg 92. This arrangement could allow pivoting of the
apparatus about a first, longer guide leg before setting the second
guide leg into the seafloor. Guide legs 91, 92 may be integral with
or attached separately to seal head 20.
[0074] Certain embodiments may include more than one collection
device connected to the same drill pipe 4, as illustrated in
embodiment 90 of FIG. 5. Illustrated in FIG. 5 is a second seal
head 260 having an aperture 242 in its bottom end, which is sunk
into seafloor 14. As illustrated in cut-out portion 460 of sidewall
270, hydrocarbons and/or other material 95 seeping from the
seafloor (naturally or due to a sub-seafloor leak) may be captured
using this apparatus. Seal head 260 includes a top end 240 fluidly
connected to movable member 160 through a subsea connector 252, a
conduit 256, and another subsea connector 254 as illustrated.
Optionally, seal head top end 240 may include one or more hot stab
connections 250 to allow injection of a functional fluid, such as
nitrogen or a hydrate inhibitor. A further option may be the
provision of one or more access handles, 258, for example for
access by an ROV 77B and one of its positioning arms 79B. Other
ROVs, for example ROV 77A and 77C, may be used to guide positioning
of movable member 160 and seal head 20, respectively. ROV 77A may
have a mechanical positioning arm 79A that grasps handle 48, and
ROV 77C may have a mechanical positioning arm 79C that grasps
handle 46. ROVs of this nature are available from Oceaneering
International, Inc. Houston, Tex.
[0075] FIGS. 6 and 7 are schematic side elevation views of two
other seal head embodiments that may be useful in certain apparatus
and method embodiments of the present disclosure. FIG. 6
illustrates an embodiment 360 comprising a solid cover 362 having a
peripheral skirt 364 that penetrates a distance into the seafloor,
or in certain embodiments sets on the seafloor. A nozzle 366
collects hydrocarbons and/or other material 95 bubbling from up
from seafloor 14 and routes the hydrocarbons and/or other material
into a conduit 368, which fluidly connects to a movable member (not
illustrated in FIG. 6) such as movable member 160 illustrated
schematically in FIG. 5. Cover 362 and peripheral skirt 364 may be
metal, plastic, fiberglass reinforced plastic (FRP) and the like.
Embodiment 400, illustrated schematically in FIG. 7, is similar to
embodiment 360, but rather than a solid cover and skirt, includes a
flexible yet sturdy fabric 402 having a chain 410, and weights 414,
416, to collect hydrocarbons and/or other material seeping up from
seafloor 14. A flange 404 and nozzle 406 arrangement, operably and
fluidly connect fabric 402 to a conduit 408, which in turn routes
hydrocarbons and/or other material collected by fabric 402 to a
movable member (not illustrated) such as movable member 160
illustrated schematically in FIG. 5. Fabric 402 may comprise any
number of plastic and/or textile materials. One of many suitable
fabrics that may used are the flexible fabrics used in flexible
storage tanks known under the trade designation Big Red Flexitank,
which are multilayer plastics, and are described in U.S. published
patent application 2010/0122981, which also describes compression
flanges and nozzles useful with such fabrics. FIG. 7A illustrates a
schematic plan view of embodiment 400, illustrating chain 410
extending around the periphery of fabric. This is but one possible
arrangement; chain 410 could be spaced away from the periphery of
fabric 402 several centimeters, or several tens of centimeters.
Another optional feature, one or more loops 420, may be provided to
allow an underwater vehicle such as an ROV to grasp chain 410 and
position fabric 402 where desired.
[0076] FIGS. 8 and 9 are logic diagrams of two method embodiments
in accordance with the present disclosure. The method of embodiment
100 of FIG. 8 is a method of establishing flow of material from a
subsea source through a collection tool and a riser that ties back
to a surface vessel, which may be a drill ship such as a Mobile
Offshore Drilling Unit (MODU) equipped with a flare and hydrocarbon
processing equipment with or without oil storage and oil transfer
equipment to another vessel. In embodiment 100 the method comprises
deploying a fluid collection apparatus from a surface vessel subsea
near a subsea source of hydrocarbons, the apparatus comprising a
collection tool of this disclosure, box 102. Method embodiment 100
then comprises positioning the apparatus to collect hydrocarbons
from the source of hydrocarbons, box 104, and collecting
hydrocarbons using the apparatus and subsea collection system, box
106.
[0077] Another method of this disclosure is presented in the logic
diagram of FIG. 9 as embodiment 200. Embodiment 200 comprises
deploying a subsea collection system and a fluid collection
apparatus from a surface vessel subsea near a subsea source of
hydrocarbons, the apparatus comprising a collection tool of this
disclosure, box 202. Method embodiment 200 then comprises
positioning the apparatus to collect hydrocarbons from the source
of hydrocarbons, box 204. Method 200 then comprises displacing
seawater from the subsea collection system and apparatus by forcing
a low-density gas down the subsea collection system at least during
the positioning of the apparatus until the gas bubbles out of a
first end of the seal head of the fluid collection apparatus,
limiting ingress of seawater or hydrocarbon gas hydrates into the
subsea collection system and apparatus thus limiting plugging of
the subsea collection system and apparatus, box 206; moving the
surface vessel so that the apparatus is a few meters above the
subsea source, with the apparatus in the hydrocarbon plume, box
208; landing the seal head on the subsea source, while the
apparatus remains filled with low-density gas, and gradually
reducing flow of the gas and gradually opening a choke to establish
and maintain flow of collected hydrocarbons through the apparatus
and subsea collection system, box 210; and collecting hydrocarbons
using the apparatus and subsea collection system, box 212.
[0078] In certain method embodiments, one or more inhibitor liquids
may be introduced into or in the vicinity of the collection tool,
the one or more inhibitor liquids selected from the group
consisting of wax inhibitors, asphaltene inhibitors, scale
inhibitors, corrosion inhibitors, antideposition agents,
combinations of two or more thereof, and the like. One or more
dispersant chemicals may also be introduced into or in the vicinity
of the tool. Suitable corrosion inhibitors include, but are not
limited to, compositions selected from the group consisting of
amides, quaternary ammonium salts, rosin derivatives, amines,
pyridine compounds, trithione compounds, heterocyclic sulfur
compounds, alkyl mercaptans, quinoline compounds, polymers of any
of these, and mixtures thereof. Suitable scale inhibitors include,
but are not limited to, compositions selected from the group
consisting of phosphate esters, polyacrylates, phosphonates,
polyacrylamides, polysulfonated polycarboxylates, copolymers
thereof, and mixtures thereof. These scale and corrosion inhibitors
are more fully discussed in U.S. Pat. No. 7,772,160, assigned to
Baker Hughes Inc., Houston, Tex., USA. Suitable asphaltene
inhibitors include, but are not limited to, ester and ether
reaction products, such esters formed from the reaction of
polyhydric alcohols with carboxylic acids; ethers formed from the
reaction of glycidyl ethers or epoxides with polyhydric alcohols;
and esters formed from the reaction of glycidyl ethers or epoxides
with carboxylic acids, as described in U.S. Pat. No. 6,313,367,
also assigned to Baker Hughes. In certain embodiments, a chemical
may contribute more than one of the functions of wax, corrosion,
and scale inhibition, and dispersant action. As noted in the '367
patent, some of the compositions taught therein may function as
asphaltene deposition inhibitors and dispersants.
[0079] Flow rates of the chemicals depend greatly on the specific
situations, and one would not normally use more than required to
perform one or more of the intended tasks. In general, the use of
hydrate inhibitor is recommended to range from 0.5 to about 1.0
volumes of inhibitor chemical to volume of water that is expected
to mix with hydrocarbon. For embodiments of collection tools of the
present disclosure, flow rate of hydrate inhibitor such as methanol
might range from about 2 to about 15 gallons per minute, or from
about 6 to about 8 gallons per minute.
[0080] An alternative is to reduce or eliminate seawater mixing
with hydrocarbons. There are several options to prevent mixing in a
situation such as presented in FIG. 3, including inserting a hose
with an expanding bladder around it to seal annulus 60 (bladders
may be off the shelf items, such as used in packers), and inserting
a mud or cement seal.
[0081] If hydrocarbons do escape the collection tool, dispersants
may be helpful in certain embodiments. Dispersants are mixtures of
solvents, surfactants and other additives that break up the surface
tension of an oil slick or sheen and make oil more soluble in
water. Dispersants do not remove oil from the water, but break up
the oil slick into small droplets. These droplets disperse into the
water column (or depths), where they may then break down further in
the environment. Examples of dispersants that may be useful in the
methods and systems disclosed herein are the chemical compositions
known under the trade designations COREXIT 9500 and COREXIT 9527,
available from Nalco Company, Naperville, Ill., USA, the
compositions of which are publicly available and found in Table
1.
TABLE-US-00001 TABLE 1 Ingredients in COREXIT .RTM. 9500 and 9527
brand dispersants CAS Registry Number Chemical Name 57-55-6
1,2-Propanediol 111-76-2 Ethanol, 2-butoxy-* 577-11-7 Butanedioic
acid, 2-sulfo-, 1,4-bis(2-ethylhexyl) ester, sodium salt (1:1)
1338-43-8 Sorbitan, mono-(9Z)-9-octadecenoate 9005-65-6 Sorbitan,
mono-(9Z)-9-octadecenoate, poly(oxy- 1,2-thanediyl) derivs.
9005-70-3 Sorbitan, tri-(9Z)-9-octadecenoate, poly(oxy-
1,2-ethanediyl) derivs 29911-28-2 2-Propanol,
1-(2-butoxy-1-methylethoxy)- 64742-47-8 Distillates (petroleum),
hydrotreated light *Note: This chemical component is not included
in the composition of COREXIT 9500.
[0082] Collection tools in accordance with the present disclosure
may be deployed by a surface vessel or MODU that includes
facilities for deploying tubulars. During deployment, the tool may
be hanging under the vessel, supported by the tubing that, in
certain embodiments, is drill pipe for robustness, although the use
of drill pipe is not required; for example, vacuum-insulated tubing
may be used in certain embodiments if thermal insulation to prevent
hydrates is considered. The tool is brought over the end of the
leaking riser. The vessel rotates the tool to align the apertures
with the damaged riser and drill pipe. As the tool is lowered it
penetrates the mud as the tubing (drill pipe riser or other) is
slackened. Drill collars may be added in the tubing line to
increase mud penetration.
[0083] During start-up, if not self-starting, nitrogen or other
low-density fluid may be injected into the top of tubing 4 to
displace the seawater out of the riser 4 and establish flow of
material up the tool and riser. The top of the tubing 4 is opened
to the processing equipment in the surface vessel. The oil and gas,
having lower density compared to seawater, induces flow of the
produced fluid to the processing equipment. Optionally, gas lift or
pumping may be provided. During normal operation, the vessel stays
on location. An ROV may be used to monitor the bottom of pipe 4.
One or more holes placed about 1 inch (2.54 cm) from the bottom of
pipe 4 may be used as a way to monitor that the nitrogen or other
low-density fluid is flowing all the way to the bottom of tubing 4
and to reduce the losses.
[0084] In an emergency disconnect situation, a surface vessel
having the capability to lift the collection tool and riser up is
used. If the surface vessel cannot lift the collection tool because
of a vessel malfunction, weather, or other reason, the bottom part
of the tool (seal head and seal head extension) may be dragged on
the sea floor. If it snags something on the sea floor, nylon lines
34 (FIG. 2) may be provided that will break.
[0085] The chimney effect of seal head extension 18 may affect
operations, as the venturi effect may induce water to enter through
the apertures at the bottom of seal head 20. To offset this, the
pressure differential is kept low by a relatively short chimney
(seal head extension 18). Improved sealing around the apertures in
seal head 20 may be provided, for example using flexible fabrics,
such as any number of plastic and/or textile materials, and the
like, as known by one of skill in the art. Gravel bags or just
gravel may be placed on the mud floor around the damaged riser and
seal head to form a partial seal and help prevent water from mixing
with the collected fluids.
[0086] Methods of this disclosure where one or more functional
fluids are used in the tool in conjunction with a low-density fluid
being forced down the riser, and optionally a dispersant chemical
(which may or may not have hydrate inhibition function), may limit
formation of hydrocarbon gas hydrates, whereas methods of using
only a low-density fluid forced down the riser (and tool, if
present during deployment) and optionally a dispersant, may control
hydrocarbon gas hydrate formation. In the latter methods, the risk
of hydrate formation is higher, but the form of the hydrate can be
controlled to a manageable level by preventing flakes of hydrates
forming drifts, or hard compactions of hydrocarbon gas
hydrates.
[0087] It should be noted that other vessels may be present during
containment and production operations. For example, separate
ship-based floating production and storage systems on the sea
surface may be present, as well as processing vessels, collection
vessels, service vessels, and the like. Other vessels may be
provided for subsea installation, operational and ROV assistance,
and hydrate prevention and remediation, if needed. A multipurpose
intervention vessel may be present, which may include various
subsea connector conduits, umbilicals from chemical dispersant and
hydrate inhibition systems; a hydrate inhibition system service
vessel which may also supply power and/or hydraulic assistance
through one or more umbilicals; a subsea umbilical distribution
box, and electrical power and/or hydraulic umbilical lines.
[0088] Methods of this disclosure may employ a riser positioning
system and riser tension monitoring sub-system. A riser positioning
system typically comprises a riser position clamp and a pair of
acoustic sources or beacons. Suitable acoustic beacons are
available from Sonardyne International Ltd in the UK, and from
Sonardyne Inc., Houston, Tex. The riser position clamp with two
acoustic beacons may be deployed anywhere on the riser. These
beacons may be integrated with the containment vessel dynamic
positioning (DP) systems in order to provide relative location of
the top of the riser that may be fed directly into the management
of vessel station-keeping limits. The riser tension monitoring unit
may be strain-based and may be installed anywhere along the length
of the riser, and in multiple locations.
[0089] In certain embodiments, certain connections may be expected
to experience heavy fatigue. The teachings of Shilling, et al.,
"Development of Fatigue Resistant Heavy Wall Riser Connectors For
Deepwater HPHT Dry Tree Riser Systems", OMAE2009-79518, may be
useful in these embodiments.
[0090] The collection tools and methods of the present disclosure
may be scalable over a wide range of water depths, well pressures
and conditions. The riser 4 ideally will be capable of handling
over 40,000 bbls per day (about 4800 cubic meters per day) with a
6-inch (15 cm) ID flow path in the riser. The riser joints may for
example comprise 0.563-inch (1.430 cm) wall thickness X-80 steel
material rated to 6,500 psi (45 MPa). In the past, X-80 material
was used in order to successfully weld on premium riser connectors
that had external and internal metal-to-metal seals and met the
fatigue performance requirements of the anticipated service life.
(X-80, or X80, is a number associate with American Petroleum
Institute (API) standard 5 L.)
[0091] In general, riser 4 may have an outer diameter (OD) ranging
from about 1 inch up to about 50 inches (2.5 cm to 127 cm), or from
about 2 inches up to about 40 inches (5 cm to 102 cm), or from
about 4 inches up to about 30 inches (10 cm to 76 cm), or from
about 6 inches up to about 20 inches (15 cm to 51 cm).
[0092] From the foregoing detailed description of specific
embodiments, it should be apparent that patentable collection tools
and methods have been described. Although specific embodiments of
the disclosure have been described herein in some detail, this has
been done solely for the purposes of describing various features
and aspects of the methods and certain apparatus used with those
methods, and is not intended to be limiting with respect to the
scope of the appended claims. It is contemplated that various
substitutions, alterations, and/or modifications, including but not
limited to those implementation variations which may have been
suggested herein, may be made to the described embodiments without
departing from the scope of the appended claims.
* * * * *