Note: Descriptions are shown in the official language in which they were submitted.
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MARINE SUBSEA ASSEMBLIES
BACKGROUND INFORMATION
Technical Field
The present disclosure relates in general to assemblies useful in marine
hydrocarbon
exploration, production, well drilling, well completion, well intervention,
and containment
and disposal. More particularly, the present disclosure relates to upper and
lower riser
assemblies useful with risers in the above-listed end uses.
Background Art
Free-standing riser (FSR) systems have been used during production and
completion
operations. For a review, please see Hatton et al., Recent Developments in
Free Standing
Riser Technology, 3rd Workshop on Subsea Pipelines, December 3-4, 2002, Rio de
Janeiro,
Brazil. For other examples of FSR systems, see published U.S. Published Patent
Application
Nos. 20070044972 and 20080223583, as well as U.S. Pat. Nos. 4,234,047;
4,646,840;
4,762,180; 6,082,391, 6,321,844, and 7,434,624.
American Petroleum Institute (API) Recommended Practice 2RD, (API-RP-2RD,
First
Edition June 1998), Design of Risers for Floating Production Systems (FPSs)
and Tension-
Leg Platforms (TLPs), is a standard known by those practicing in the oil and
gas production
industry.
Szucs et al., Heavy Oil Gas Lift Using the COR, SPE 97749 (2005) discloses a
lower riser
assembly (LRA) in an FSR.
Tieback connectors have been characterized as "internal" and "external"
tieback connectors,
and each has been patented. Patents on internal tieback connectors are U.S.
Patent Nos.
6,260,624; 5,299,642; 5,222,560; 5,259,459; 4,893,842; 4,976,458; 7,735,562;
5,279,369;
and 5,775,427; and U.S. Published Patent Application No. 20090277645. Patents
on external
tieback connectors are U.S. Patent Nos. 4,606,557; 6,234,252; 6,540,024;
6,070,669;
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6,293,343; 7,503,391; 7,337,848; 5,330,201; 5,255,743; 7,240,735. Drilling
adapters and
their connection to wellheads (casing head or tubing heads) are described in
U.S. Published
Patent Application No. 20090032265. Adjustable hangers are described in U.S.
Patent Nos.
6,065,542; 6,557,644; and 7,219,738.
Due to the complexities of any given reservoir, well design, and riser system,
while certain
minimum standards such as presented in the above-referenced API riser standard
may be
known to persons of ordinary skill in the art, each individual oil or gas well
may be a unique
environment unto itself (see for example U.S. Patent No. 6,747,569). Riser
systems that work
for one reservoir/well/environment may not be suitable for use with other
wells, even those
wells located proximate thereto.
In the containment and disposal context, subsea risers (free-standing or not)
have not been
known as suitable for such use. In particular, until recently industry has not
had to intervene
with respect to subsea leaks at any significant depth, such as depths to 5,000
ft/1500 meters,
or more. In particular, prior containment efforts did not address fluid
properties produced by
the combination of hydrocarbons with sea water at deep-ocean pressures and
temperatures
that contribute toward formation of gas hydrates.
Therefore, there remains an unmet need for more robust upper and lower riser
assembly
designs, particularly when flow assurance is a concern, both during normal
production
operations and during containment and disposal periods.
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SUMMARY
In accordance with the present disclosure, marine subsea assemblies, and
methods of making,
installing, and using same are described which reduce or overcome many of the
faults of
previously known marine subsea assemblies.
A first aspect of the disclosure is an assembly for connecting a subsea riser
to a seabed
mooring and to a subsea hydrocarbon fluid source, comprising:
a generally cylindrical member having a longitudinal bore, a lower end, an
upper end,
and an external generally cylindrical surface, the member comprising
sufficient intake ports
extending from the external surface to the bore to accommodate flow of
hydrocarbons from
the hydrocarbon fluid source as well as inflow of a functional fluid (flow
assurance fluid or
other fluid, for example a corrosion or scale inhibitor, kill fluid, and the
like), at least one of
the intake ports fluidly connected to a production wing valve assembly,
the upper end of the member comprising a profile suitable for fluidly
connecting to a
subsea riser, and
the lower end of the member comprising a connector suitable for connecting to
a
seabed mooring.
In certain embodiments the generally cylindrical member comprises a subsea
wellhead
housing modified by connecting a transition joint thereto, the upper end of
the subsea
wellhead housing fluidly connected to an external tieback connector fluidly
connecting the
subsea wellhead housing to a riser stress joint.
In certain embodiments the subsea wellhead housing comprises an internal seal
profile
adapted to seal with an internal tieback connector, the internal tieback
connector fluidly
connecting an inner subsea riser to the internal seal profile of the subsea
wellhead. In certain
embodiments, the internal tieback connector comprises a nose seal which seals
into the
subsea wellhead profile of the subsea wellhead, the nose seal providing
pressure integrity
between an internal flow path in the inner riser and an annulus between the
inner riser and a
substantially concentric outer riser. In certain embodiments the internal
tieback connector
latches to both the subsea wellhead housing and to a riser stress joint,
creating a preloaded
structural connection between the subsea wellhead housing and the internal and
external
tieback connectors. In certain embodiments the latches comprise dogs.
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Certain embodiments comprise an external connector which latches the internal
tie-back
connector to the subsea wellhead housing.
In yet other assemblies, the production wing valve assembly is fluidly
connected to a subsea
source through one or more subsea flexible conduits.
In yet other assemblies the riser stress joint is in turn fluidly connected to
an outer riser.
In yet other assemblies the transition joint is capped with a first padeye end
forging serving as
an anchor point for a free standing riser.
Yet other assemblies comprise ROV-operated valves for controlling flow through
an internal
flow path in the inner riser and through an annulus between the inner riser
and a substantially
concentric outer riser.
Still other assemblies comprise one or more pressure and/or temperature
monitors.
Yet other assemblies comprise one or more hot stab ports for ROV intervention
and/or
maintenance.
In certain other embodiments the generally cylindrical member comprises a high-
strength
metal forging. These embodiments may comprise two intake ports connected to
respective
wing valve assemblies, and a third port including a sub suitable for
connecting a source of
functional fluid, for example a flow assurance fluid or other fluid. The sub
may include one
or more ROV-operable valves.
Certain embodiments comprise two or more intake ports connected to respective
wing valve
assemblies, and further comprising dual clamp supports for supporting
respective dual subsea
connectors, each fluidly connected to the forged high-strength steel member
through
respective block elbows, wherein each production wing valve assembly includes
at least one
ROV-operable valve.
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In certain embodiments, the generally cylindrical member comprises a third
port suitable for
connecting an annulus vent sub, the annulus vent sub connecting to the third
port of the
forged high-strength steel member through a third block elbow, the annulus
vent sub
providing a fluid connection to a source of a functional fluid, such as a flow
assurance fluid
or other fluid. In some embodiments, the annulus vent sub comprises one or
more ROV-
operable valves.
In certain embodiments, each wing valve assembly comprises a block elbow
connector
connecting the wing valve assembly to the metal forging, at least one ROV-
operable valve
connected to the block elbow, and a subsea connector for connecting to a
subsea flexible
conduit, the block elbow, ROV-operable valve, and subsea connector all fluidly
connected by
central bores allowing fluid communication from the subsea flexible conduit to
the
longitudinal bore of the metal forging.
Certain embodiments comprise a tie-back ring having an external threaded
portion mating
with threads on an internal surface of the metal forging, and an internal
thread portion for
mating with threads of an internal casing string.
In other embodiments, the forged high-strength steel member further comprises
an internal
surface, at least a portion of which is threaded, to threadedly engage mating
threads of a
tieback ring, the tieback ring including at least one set of internal threads
which mate with a
set of threads on the inner riser, and further including a seal element
comprised of Inconel or
other corrosion-resistant metal.
Certain embodiments comprise a hot stab assembly for injection of a functional
fluid, the hot
stab assembly allowing for a smaller flow rate of functional fluid than is
possible through the
annulus vent sub.
In other embodiments, the generally cylindrical member comprises a forged,
high-strength
steel intake spool fluidly connected to a gooseneck assembly, the gooseneck
assembly fluidly
connected to the lower flexible conduit, the intake spool also comprising a
connector
allowing connection to a source of a functional fluid. In embodiments, the
gooseneck
assembly comprises a subsea API flange connected in series to a tubing spool,
a high-
pressure subsea connector, another subsea API flange, and a bend restrictor.
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In other embodiments, the intake spool comprises an internal surface adapted
to accept and
fluidly connect with an internal tieback connector landed in the internal
surface of intake
spool, the intake spool further comprising a latching mechanism allowing the
internal tieback
connector to releasably connect to the intake spool, while an 0-ring seal
provides a fluid-tight
seal between an external surface of the internal tieback connector and the
internal surface of
the intake spool.
Another aspect of this disclosure comprises an assembly suitable for use as a
subsea lower
riser assembly comprising:
a subsea wellhead housing having a lower end and an upper end, the lower end
modified by fluidly and mechanically connecting a transition joint thereto,
the transition joint
in turn fluidly and mechanically connected to a bottom forging, the bottom
forging
comprising sufficient intake ports to accommodate flow of production or
containment fluids
and flow assurance fluid, at least one of the ports connected to a source of a
flow assurance
fluid, at least one other intake port fluidly connected to a production wing
valve assembly,
the upper end of the subsea wellhead housing fluidly connected to an external
tieback
connector fluidly connecting the subsea wellhead housing to a riser stress
joint,
the subsea wellhead housing comprises an internal seal profile adapted to seal
with an
internal tieback connector, the internal tieback connector fluidly connecting
an inner
subsea riser to the internal seal profile of the subsea wellhead,
wherein the internal tieback connector comprises a nose seal which seals into
the
subsea wellhead profile of the subsea wellhead, the nose seal providing
pressure
integrity between an internal flow path in the inner riser and an annulus
between the
inner riser and a substantially concentric outer riser, and
wherein the internal tieback connector latches to both the subsea wellhead
housing
and to a riser stress joint, creating a preloaded structural connection
between the
subsea wellhead housing and the internal and external tieback connectors.
Another aspect of this disclosure comprises an assembly suitable for use as a
subsea lower
riser assembly comprising:
a generally cylindrical high-strength metal forging comprising a longitudinal
bore, a
lower end, an upper end, an external generally cylindrical surface, and
sufficient
intake ports to accommodate flow of production or containment fluids, at least
one of
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the ports connected to a source of a flow assurance fluid, at least one other
intake port
fluidly connected to a production wing valve assembly,
the upper end of the metal forging comprising a profile suitable for fluidly
connecting
to an external subsea riser,
the lower end of the metal forging comprising a connector suitable for
connecting to a
subsea mooring,
a third port suitable for connecting an annulus vent sub, the annulus vent sub
comprising one or more remotely-operated vehicle (ROV)-operable valves, and
a tie-back ring having an external threaded portion mating with threads on an
internal
surface of the metal forging, and an internal threaded portion for mating with
threads
of an internal casing string.
Another aspect of this disclosure comprises an assembly suitable for use as a
subsea
lower riser assembly comprising:
a forged, high-strength steel, generally cylindrical intake spool fluidly
connected to a
gooseneck assembly, the gooseneck assembly fluidly connected to a lower
flexible conduit,
the intake spool also comprising a connector allowing connection to a source
of a functional
fluid;
the gooseneck assembly comprising a subsea API flange connected in series to a
tubing spool, a high-pressure subsea connector, another subsea API flange, and
a bend
restrictor; and
wherein the intake spool comprises an internal surface adapted to accept and
fluidly
connect with an internal tieback connector landed in the internal surface of
intake spool, the
intake spool further comprising a latching mechanism allowing the internal
tieback connector
to releasably connect to the intake spool, while an 0-ring seal provides a
fluid-tight seal
between an external surface of the internal tieback connector and the internal
surface of the
intake spool.
Another aspect of this disclosure is an assembly for connecting a subsea riser
to a subsea
buoyancy device and to a surface structure, comprising:
a generally cylindrical member having a longitudinal bore, a lower end, an
upper end,
and an external generally cylindrical surface, the member comprising
sufficient
outtake ports extending from the bore to the external generally cylindrical
surface to
accommodate flow of hydrocarbons from the riser, and at least one port
allowing flow
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of a functional fluid into the longitudinal bore, at least one of the outtake
ports fluidly
connected to a production wing valve assembly for fluidly connecting the
member to
the surface structure with a subsea flexible conduit,
the upper end of the member comprising a connector suitable for connecting to
a
subsea buoyancy device, and
the lower end of the member comprising a profile suitable for fluidly
connecting to
the riser.
In certain embodiments the generally cylindrical member comprises a drilling
spool adapter
having a first end fluidly connected to a tubing head, the tubing head
comprising the one or
more outtake ports, the tubing head connected to a casing head having a stem
joint fastened
(for example, welded) thereto, the casing head also comprising one or more
ports for
admitting a functional fluid, and one or more production wing valve assemblies
fluidly
connected to respective outtake ports.
In certain embodiments of this aspect the stem joint is fluidly connected to
an outer
concentric riser.
In certain embodiments at least one of the production wing valve assemblies
fluidly connects
an outtake port to a collection vessel through a flexible conduit.
In certain embodiments the assembly comprises an adjustable tubing hanger
fluidly
connecting an inner riser to the tubing head.
In yet other embodiments of this aspect, the production wing valve assembly
comprises first
and second flow control valves for controlling flow in the bore of the inner
riser and in an
annulus between the inner riser and the outer riser.
In yet other embodiments, the production wing valve assembly comprises at
least one
emergency shutdown valve (ESD) selected from the group consisting of one
hydraulically-
operated ESD, one electrically-operated ESD, and one hydraulically-operated
ESD and one
electrically-operated ESD.
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In still yet other embodiments the production wing valve assembly comprises
one or more
ROV hot-stab ports allowing a functional fluid to flow into an inner riser and
an annulus
between the inner riser and an outer riser. In certain embodiments, the
functional fluid is a
flow assurance fluid selected from the group consisting of nitrogen or other
gas phase, heated
seawater or other water, and organic chemicals. In certain embodiments, the
flow assurance
fluid consists essentially of nitrogen.
In certain embodiments, the drilling spool adapter is connected to a shackle
flange adapter
capped on its top with a padeye end forging serving as an attachment point of
the assembly to
a near-surface subsea buoyancy assembly.
In other embodiments of this aspect of this disclosure, the generally
cylindrical member
comprises an offtake spool having the upper end and the lower end, a padeye
flange
connected to the upper end of the offtake spool, and a hanger spool connected
to the lower
end of the offtake spool, wherein the offtake spool and the hanger spool
define the
longitudinal bore.
In certain of these embodiments, the offtake spool comprises a second bore
substantially
perpendicular to the longitudinal bore and fluidly connecting the longitudinal
bore to one of
the production wing valve assemblies through one of the outtake ports.
In certain other embodiments, the production wing valve assembly comprises a
gooseneck
conduit and two emergency shutdown (ESD) valves fluidly connected inline of
the gooseneck
conduit, one of the ESDs being hydraulically actuated, and the second ESD
being
electronically actuated.
In certain other embodiments, the hanger spool comprises a third bore
substantially
perpendicular to the longitudinal bore and fluidly connecting an annulus
defined by the
hanger spool and an internal riser joint with an annulus access valve
assembly. The annulus
access valve assembly may comprise one or more ROV-operable valves. The
annulus access
valve assembly may be fluidly connected to a source of functional fluid.
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Certain embodiments comprise a riser locking assembly for interfacing with and
retaining the
internal riser joint within the offtake spool. The riser locking assembly may
comprise a
lockdown ring and a slip with T seals.
In certain embodiments, a dual ring seal and wire retainer arrangement is
positioned on an
inner surface of the offtake spool for providing a dual fluid seal between the
annulus and the
longitudinal bore.
In certain embodiments the URA comprises a production bore offtake spool
fluidly and
mechanically connected to a substantially vertical conduit and to a production
tubing, the
production tubing in turn fluidly connected to a bend restrictor through a
subsea API flange, a
high pressure subsea connector, another subsea API flange connection, and
optionally a QDC
subsea connector. The bend restrictor mechanically connects to the upper
subsea flexible
conduit which extends in a catenary loop to the collection surface vessel, and
the
substantially vertical conduit fluidly connects in series to an adapter which
in turn fluidly
connects to a hanger spool and API flange, a casing head via another API
flange, a stem joint
welded to the casing head, and to the outer riser via a threaded connection
into a stem joint,
the offtake spool including a shackle flange allowing connection to the subsea
buoyancy
device.
In certain embodiments the URA further comprises an ROV-operable ESD fluidly
connected
in a section of the conduit.
In certain embodiments the URA further comprises a support bracket which
supports
production tubing an angle a to the conduit, and also supports a bend shield
which provides a
mechanical barrier between the production tubing and the conduit, where the
angle a ranges
from 0 to about 180 degrees.
In certain embodiments the URA further comprises a connection to the hanger
spool for
connecting a gooseneck for delivery of heated water to the hanger spool from a
surface
vessel.
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In certain embodiments the gooseneck comprises, in order starting at the
hanger spool, an
API flange, a section of tubing, a high pressure subsea connector, a subsea
API connector
and API flange, and a bend restrictor.
In certain embodiments the inner riser is positioned inside of the adapter,
the hanger spool,
and the casing head, creating the annulus between an inner surface of the
hanger spool and
the inner riser.
In certain embodiments the URA comprises a pair of 0-ring seals which seal the
inner riser
into the adapter, and one or more slips which wedge between an inner slanted
surface of the
hanger spool and the inner riser, firmly securing the inner riser in the
hanger spool.
In embodiments, the URA further comprises components allowing circulation of a
functional
fluid, such as heated water, through the annulus.
In other embodiments, the URA also comprises an offtake spool fluidly
connected to a
hanger spool, the hanger spool in turn fluidly connectable to a tapered stress
joint of the riser.
In yet other embodiments, the URA further comprises a shackle and chain tether
allowing the
URA to be mechanically connected to a near-surface buoyancy device.
Certain other embodiments comprise a first block elbow includes an inner bore
which
intersects with and is substantially perpendicular to a bore in the offtake
spool, a second
block elbow having an inner bore which is also substantially perpendicular to
the offtake
spool bore but which does not intersect the offtake spool bore, and a
gooseneck conduit
fluidly connected to the first block elbow providing a flow path for
hydrocarbons in
combination with first block elbow bore. In some instances, the URA comprises
first and
second emergency shutdown valves in the gooseneck conduit, the gooseneck
conduit fluidly
connected to a subsea connector in turn fluidly connected to the subsea
flexible conduit.
In other embodiments, the assembly further comprises a bleed valve in the
gooseneck conduit
allowing shutting in the URA, bleeding off contents of the gooseneck conduit,
and retrieving
the subsea flexible conduit.
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In embodiments, the components allowing circulation of a functional fluid
through the
annulus comprises a subsea connector, a conduit and one or more valves in the
conduit, the
conduit fluidly connected to the hanger spool.
Yet another aspect of this disclosure is an assembly suitable for use as a
subsea upper riser
assembly, comprising
a drilling spool adapter having a first end fluidly connected to a tubing
head, the
tubing head comprising one or more outtake ports, the tubing head connected to
a casing head
having a stem joint fastened thereto, the casing head also comprising one or
more ports for
admitting a flow assurance fluid,
the stem joint fluidly connected to an outer concentric riser,
an adjustable tubing hanger for fluidly connecting an inner riser to the
tubing head,
forming an annulus between the inner riser and the outer concentric riser,
a production wing valve assembly fluidly connected to one of the respective
outtake
ports, the production wing valve assembly comprising first and second flow
control valves
for controlling flow in the inner riser and the annulus, and a hydraulically-
operated
emergency shut-down valve and an electrically-operated emergency shut-down
valve, and
the production wing valve assembly comprising one or more ROV hot-stab ports
allowing a flow assurance fluid to flow into the inner riser and/or the
annulus.
Still another aspect of this disclosure is an assembly suitable for use as a
subsea upper riser
assembly, comprising
an offtake spool having an upper end and a lower end, a padeye flange
connected to
the upper end, and a hanger spool connected to the lower end, wherein the
offtake spool and
the hanger spool define a longitudinal bore,
the offtake spool comprising a second bore substantially perpendicular to the
longitudinal bore and fluidly connecting the longitudinal bore to a production
wing valve
assembly through an outtake port of the offtake spool,
the production wing valve assembly comprising a gooseneck conduit and two
emergency shutdown (ESD) valves fluidly connected inline of the gooseneck
conduit, one of
the ESDs being hydraulically actuated, and the second ESD being electronically
actuated,
the hanger spool comprising a third bore substantially perpendicular to the
longitudinal bore for fluidly connecting an annulus defined by the hanger
spool and an
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internal riser joint with an annulus access valve assembly, the annulus access
valve assembly
comprising one or more ROV-operable valves,
a riser locking assembly for interfacing with and retaining the internal riser
joint
within the offtake spool, the riser locking assembly comprising a lockdown
ring and a slip
with T seals, and
a dual ring seal and wire retainer arrangement on an inner surface of the
offtake spool
providing a dual fluid seal between the annulus and the longitudinal bore.
Another aspect of the disclosure is an assembly suitable for use as a subsea
upper riser
assembly, comprising:
a production bore offtake spool fluidly and mechanically connected to a
substantially
vertical conduit and to a production tubing, the production tubing in turn
fluidly connected to
a bend restrictor through a subsea API flange, a high pressure subsea
connector, another
subsea API flange connection, and optionally a QDC subsea connector, the bend
restrictor
connected to the upper subsea flexible conduit which extends in a catenary
loop to a surface
structure,
wherein the substantially vertical conduit fluidly connects in series to an
adapter
which in turn fluidly connects to a hanger spool of an API flange, a casing
head via another
API flange, a stem joint welded to the casing head, and to an outer riser via
a threaded
connection into a stem joint, the offtake spool including a shackle flange
allowing connection
to a subsea buoyancy device;
an ROV-operable ESD fluidly connected in a section of the conduit;
a support bracket which supports production tubing an angle a to the conduit,
and also
supports a bend shield which provides a mechanical barrier between the
production tubing
and the conduit, where the angle a ranges from 0 to about 180 degrees;
a connection to the hanger spool for connecting a gooseneck for delivery of
heated
water to the hanger spool from a surface vessel, wherein the gooseneck
comprises, in order
starting at the hanger spool, an API flange, a section of tubing, a high
pressure subsea
connector, a subsea API connector and API flange, and a bend restrictor;
wherein the inner riser is positioned inside of the adapter, the hanger spool,
and the
casing head, creating the annulus between an inner surface of the hanger spool
and the inner
riser; and
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a pair of 0-ring seals which seal the inner riser into the adapter, and one or
more slips
which wedge between an inner slanted surface of the hanger spool and the inner
riser, firmly
securing the inner riser in the hanger spool.
In certain embodiments, the subsea flexible conduits each comprise a lazy wave
flexible
jumper with distributed buoyancy modules connected to the subsea flexible
conduit randomly
or non-randomly from a point of connection of the subsea flexible conduit to
the base of the
free standing riser to a subsea manifold on the seafloor, the manifold fluidly
connected to the
subsea source or sources.
In certain embodiments including an internal tieback connector fluidly
connecting the inner
riser to the LRA, the internal tieback connector comprising a nose seal, in
some embodiments
the nose seal is an Inconel nose seal, which seals into a subsea wellhead
profile of the subsea
wellhead, the connector also latching with dogs both to the subsea wellhead
and to the stress
joint in order to create a preloaded structural connection between the subsea
wellhead and the
internal and external tieback connectors. Certain embodiments also comprise an
additional
external connector latch which latches the internal tie-back connector to the
subsea wellhead.
The nose seal provides pressure integrity between the internal flow path in
the inner riser and
the annulus between the inner and outer risers.
Certain embodiments include those wherein the URA production wing valve
assembly
comprises both hydraulically and manually operated emergency shutdown valves.
Certain embodiments include those wherein the URA production wing valve
assembly
comprises one or more subsea vessel hot-stab ports allowing a functional fluid
to be injected
into either one or both of the inner riser and the annulus. Examples of
suitable functional
fluids include flow assurance fluids such as a gas atmosphere, heated seawater
or other water,
or organic chemicals such as methanol, and the like. The gas atmosphere may be
selected
from nitrogen of various degrees of purity, such as nitrogen-enriched air, a
noble gas such as
argon, xenon and the like, carbon dioxide, and combinations thereof; hot
seawater or other
water pumped in the annulus and out the annulus vent sub, and methanol pumped
in the
annulus and out the vent sub. Certain hydrate inhibition fluids include liquid
chemicals
selected from the group consisting of alcohols and glycols. The flow assurance
fluid may
consist essentially of nitrogen, meaning the gas atmosphere comprises nitrogen
and may
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include impurities which do not contribute to formation of, or themselves
form, hydrates, and
substantially excludes impurities that do form or contribute to forming
hydrates.
Certain embodiments comprise external wet insulation adjacent at least a major
portion of the
outer surface of one or more of the wellheads, wing valves, casing heads,
tubing heads, metal
forgings, offtake spools, hanger spools, and the like. In certain embodiments
the wet
insulation comprises a polymeric material. The polymeric material may comprise
a plurality
of layers of polypropylene.
Certain URA and LRA embodiments include subs for allowance of a functional
fluid, such as
a flow assurance fluid, to flow into an inner riser and/or annular spaces
between risers, and
into the bores of the URA and LRA. Certain embodiments include subs for
allowance of flow
of hydrate inhibition fluid in these spaces. Certain embodiments include subs
for allowance
of hydrate remediation fluid in these spaces. Certain embodiments include subs
for allowance
of fluids for all of these uses. Once introduced into the inner riser and/or
annular space, the
flow assurance fluid, hydrate inhibition fluid, and/or hydrate remediation
fluid may be
stagnant or flowing, however mass and heat transfer favors a flowing fluid.
Certain other embodiments include those wherein at least some of the
components of the
LRA and/or URA comprise high-strength steel, although the use of steel is not
required, other
metals being possible for use. As used herein the term "high-strength steel"
includes steels
such as P-110, C-110, Q-125 and C-125, and titanium steels.
The assemblies described herein may be used with single or concentric risers
systems. The
assemblies described herein may be used with wet tree developments, including
those
employing an FPSO or other floating production systems (FPS), including, but
not limited to,
semi-submersible platforms. The assemblies described herein may also be used
with dry tree
developments, including those employing compliant towers, TLPs, spars or other
FPSs. The
assemblies described herein may also be used with so-called hybrid
developments (such as
TLP or spar with an FPSO or FPS). The assemblies described herein may be used
with risers
tensioned by air-can systems, hydro-pneumatic tensioners, or combinations
thereof.
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These and other features of the systems, 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.
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BRIEF DESCRIPTION OF THE DRAWINGS
The manner in which the objectives of this disclosure and other desirable
characteristics can
be obtained is explained in the following description and attached drawings in
which:
FIGS. 1, 1A, and 1B illustrate schematically, FIG. lA in detailed cross-
section, one
embodiment of a riser system in which the assemblies of the present disclosure
may be
useful;
FIGS. 2A and 2B are schematic side-elevation and cross-sectional views,
respectively, of a
general embodiment of a lower riser assembly in accordance with the present
disclosure;
FIGS. 3A-3G include various views, some in cross-section, of another
embodiment of a
lower riser assembly in accordance with the present disclosure;
FIGS. 4A is a perspective view, FIG. 4B a cross-sectional view, and FIG. 4C a
more detailed
cross-sectional view of a portion of the lower riser assembly embodiment of
FIG.3;
FIGS. 5A and B illustrate schematic perspective views of another lower riser
assembly in
accordance with the present disclosure, and FIG. 5C is a schematic perspective
view of an
internal component useful with the lower riser assembly illustrated in FIGS.
5A and 5B;
FIGS. 5D and 5E are cross-sectional views, and FIG. 5G is a plan view of the
lower riser
assembly illustrated in FIGS. 5A and 5B; and FIG. 5F is a detailed schematic
view of a
portion of the lower riser assembly illustrated in FIG. 5E;
FIG. 6 is a schematic side-elevation view, with portions cut away, of a
general embodiment
of an upper riser assembly in accordance with the present disclosure;
FIGS. 6A-6G include various views, some in cross-section, of another
embodiment of an
upper riser assembly in accordance with the present disclosure;
FIG. 6H is a schematic perspective view, and FIGS. 61 and 6J are cross-
sectional views, of a
portion a of the upper riser assembly embodiment of FIG. 6; FIG. 6K is a
perspective view of
a seal test port;
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FIGS. 7A and 7B are schematic perspective views of another upper riser
assembly
embodiment in accordance with the present disclosure;
FIGS. 7C-7D are cross-sectional views of the embodiment of FIG. 7, and FIG. 7E
is a
detailed cross-sectional view of a portion of that embodiment; and
FIGS. 8A and 8B are schematic side elevation and cross-sectional
illustrations, respectively,
of another URA embodiment, and FIGS. 8C and 8D are schematic side elevations
and cross-
sectional illustrations, respectively, of another LRA embodiment in accordance
with the
present disclosure.
It is to be noted, however, that the appended drawings are not 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.
Identical
reference numerals are used throughout the several views for like or similar
elements.
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DETAILED DESCRIPTION
In the following description, numerous details are set forth to provide an
understanding of the
disclosed methods, systems, and apparatus. However, it will be understood by
those skilled in
the art that the methods, systems, and apparatus may be practiced without
these details and
that numerous variations or modifications from the described embodiments may
be possible.
All U.S. published patent applications and U.S. Patents referenced herein, as
well as any non-
published U.S. aptent applications and published non-patent literature 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.
The primary features of various embodiments of the present disclosure will now
be described
with reference to the drawing figures. The same reference numerals are used
throughout to
denote the same items in the figures, unless otherwise noted.
As noted previously, marine subsea assemblies, and methods of making,
installing, and using
same are described which may reduce or overcome many of the faults of
previously known
marine subsea assemblies.
As used herein the term "surface structure" means a surface vessel or other
structure that may
function to receive one or more fluids from one or more free-standing risers.
In certain
embodiments, the surface structure may also include facilities to enable the
surface structure
to perform one or more functions selected from the group consisting of
storing, processing,
and offloading of one or more fluids. As used herein the term "offloading"
includes, but is
not limited to, flaring (burning) of gaseous hydrocarbons. Suitable surface
structures include,
but are not limited to, one or more vessels; structures that may be partially
submerged, such
as semi-submersible structures; floating production and storage (FPS)
structures; floating
storage and offloading structures (FS0); floating production, storage, and
offloading (FPSO)
structures; mobile offshore drilling structures such as those known as mobile
offshore drilling
units (MODUs); spars; tension leg platforms (TLPs), and the like.
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As used herein the phrase "subsea source" includes, but is not limited to: 1)
production
sources such as subsea wellheads, subsea blow out preventers (B0Ps), 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 leaking
or damaged subsea BOPs, risers, manifolds, tanks, and the like; and 3) natural
sources.
Certain system embodiments include those wherein the containment source is a
failed subsea
blowout preventer.
The term "wellhead" is well-known in the hydrocarbon drilling and production
art as a
structure having a central bore and end connectors on both ends of varying
nature, such as
hubs, mandrel, dogs, and the like, and meeting API standards for strength and
other
parameters for wellheads, such as detailed in API specification 6A. As used
herein, the terms
"tubing head" and "casing head" are wellheads having relative strength
ratings, such that a
tubing head is generally stronger than a casing head, although this is not
always the case. A
subsea wellhead may either be a tubing head or a casing head, but is typically
a casing head
or even more robust construction due to conditions found subsea.
The terms "flow assurance" and "flow assurance fluid" includes assurance of
flow in light of
hydrates, waxes, asphaltenes, and/or scale already present, and/or prevention
of their
formation, and are considered broader than the term "hydrate inhibition",
which is used
exclusively herein for prevention of hydrate formation. The term "hydrate
remediation"
means removing or reducing the amount of hydrates that have already formed in
a given
vessel, pipeline or other equipment. The term "functional fluid" includes flow
assurance
fluids, as well as fluids which may provide additional or separate functions,
for example,
corrosion resistance, hydrogen ion concentration (pH) adjustment, pressure
adjustment,
density adjustment, and the like, such as kill fluids.
As used herein the term "substantially vertical" means having an angle to
vertical ranging
from about 0 to about 45 degrees, or from about 0 to about 20 degrees, or from
about 0 to
about 5 degrees. As such the term "substantially vertical" includes and is
broader than the
term "near-vertical", as that term is used in describing the angle a riser may
make with
vertical.
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FIGS. 1, 1A, and 1B illustrate schematically (FIG. lA in detailed cross-
section) one
embodiment of a subsea riser system in which the assemblies described herein
may be useful.
It will be recognized that various other subsea riser systems may also benefit
from use of the
assemblies described herein. A free-standing riser (FSR) 2 is illustrated at
an angle a with
respect to vertical. Angle a may range from 0 to 90 degrees, or from 0 to 45
degrees, or from
0 to 20 degrees (considered "near vertical"). Another angle, 13, is defined as
the angle between
vertical and a tangent line to flexible conduit 12 near the water surface 20.
Angle 0 may range
from 0 to about 90 degrees, or from 0 to about 45 degrees, or from 0 to about
20 degrees. A
third angle y, defined as the angle between a chain or other tether 58 (which
may or may not
be vertical) and an end section of a flexible conduit 14 near the base of the
FSR, may range
from about 5 to about 60 degrees, or from about 5 to about 30 degrees. A pile
16 is illustrated
submerged into the seabed 10, and a chain tether 58 connects pile 16 to lower
riser assembly
8 as further described herein. Subsea conduit 14 fluidly connects lower riser
assembly 8 to a
source of hydrocarbons, in this case a subsea manifold 26. An upper riser
assembly 6 fluidly
connects riser 2 with a flexible subsea conduit 12, which in turn fluidly
connects to a surface
vessel 32. Upper riser assembly 6 is also connected to primary and secondary
air cans 18 and
19 in this embodiment.
FIG. lA illustrates the relative locations of an inner riser 60, a
substantially concentric outer
riser 70, an outer surface 62 of inner riser 60, an outer surface 72 of outer
riser 70, an inner
surface 74 of outer riser 70, an annulus 76, and a flow path 64 in inner riser
60. Solid
insulation 80 is placed adjacent at least a major portion of outer surface 72
of outer riser 70,
and in certain embodiments, this solid insulation is adjacent the entire outer
surface 72 of
outer riser 70. Electrically heated risers may be an option in certain
embodiments, although
for operational reasons associated with the emergency quick disconnect (QDC)
or hurricane
evacuation scenarios, this option may not be attractive. Electrical heating
may significantly
complicate the QDC design.
Circulation of hot water in annulus 76 or other flow assurance fluid described
herein, and
insulation on the subsea manifolds, flowlines (including flexible subsea
conduits 12 and 14,
and flexible jumpers and goosenecks mentioned herein), and connectors, in
addition to the
free standing riser, may be included in many embodiments. "Circulation" may be
continuous
or discontinuous. In certain embodiments, the flow assurance fluid may be
stagnant after
filling the annulus. The ability to pump or otherwise inject one or more flow
assurance fluids
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into one or more ROV hot stab receptacles is another option, as is the ability
to pump or
otherwise inject nitrogen or other gas phase into the bottom of the inner
riser or at a subsea
manifold into the flexible subsea conduits as a way to get the flow assurance
fluid underneath
an actual or potential, complete or partial hydrate plug. In certain
embodiments such as
illustrated in the figures, flow assurance fluid may be pumped or otherwise
injected into a
variety of locations, for example, but not limited to, the bottom of the inner
riser 60, in the
bottom of annulus 76, into the bottom (subsea) flexible 14, at the top of
inner riser 60 and
annulus 76 and into upper flexible conduit 12.
FIG. 1B also illustrates schematically a tension monitoring system 52 on FSR
2. The location
of the tension monitoring system is typically near the top of FSR 2, although
the location may
be anywhere along FSR 2, and may comprise a plurality of such monitoring
systems
randomly or non-randomly spaced along FSR 2. FIG. 1B schematically illustrates
a detail of
the tension monitoring system illustrating a connector 54 and tension
monitoring module 56.
Lower Riser Assembly (LRA)
FIGS. 2A and 2B are schematic side-elevation and cross-sectional views,
respectively, of a
general embodiment of a lower riser assembly (LRA) in accordance with the
present
disclosure. LRA 8 includes a generally cylindrical body CB, an upper end 8UE
and a lower
end 8LE, and five connections Cl, C2, C3, C4, and C5 in this embodiment.
Connection Cl is
a mechanical and fluid connection of cylindrical body CB to riser 2.
Connection C4 is a
mechanical connection of cylindrical body CB to a subsea mooring (not
illustrated) through a
chain or other functional tether 58. Connections C2, C3, and C5 are mechanical
and fluid
connections of conduits 8A, 8B, and 8C to cylindrical body CB though ports 8P
in cylindrical
body CB. Ports 8P extend from an inner surface 8IS to an external surface 8E5
of cylindrical
body CB.
Conduits 8A, 8B, and 8C may be, for example, wing valve assemblies connecting
to subsea
hydrocarbon sources, connections to sources of functional fluids such as flow
assurance
fluids, or connections to other subsea or surface equipment. Connections C2,
C3, and C5
between ports 8P and conduits 8A, 8B, and 8C may be threaded connections,
flange
connections, welded connections, or other connections, and they may be the
same or different
with respect to type of connection, diameter and shape, depending on diameter
and shape of
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ports 8P; for example, ports 8P could have a shape selected from the group
consisting of slot,
slit, oval, rectangular, triangular, circular, and the like. Connection Cl may
be a threaded,
flanged, welded, or other connection, and may include one or more dogs,
collet, split ring, or
other features. In certain embodiments, the LRA may have the ability to
connect to
manifolds and other equipment, such as flexibles, within 270 degrees radius
angle of
approach.
Another embodiment of an LRA is illustrated in various views in FIGS. 3A-3G.
FIG. 3A is a
front elevation view of LRA 8, which in this embodiment comprises an external
tie-back
connector 102 connected to a subsea wellhead 104 (as further explained in
relation to FIGS.
4A-C) and transition joint 105. Transition joint 105 is welded on its top end
in this
embodiment to the bottom of subsea wellhead 104, and to a bottom forging 106
including
two machined flange connections 108A and B and a padeye. Machined flanged
connections
108A and B are substantially perpendicular to a longitudinal axis common to
wellhead 104,
transition joint 105 and forging 106, and machined flanged connections 108A
and B define
LRA intake ports. Bottom forging and padeye are one piece 106 in this
embodiment, and
transition joint 105 is a separate piece that welds bottom forging 106 to
subsea wellhead 104.
Transition joint 105 includes a padeye end forging 106, which engages a U-
connector 119
and tether chain 58, leading to suction pile assembly 16 (not illustrated).
LRA 8 further comprises an ROV hot stab panel 110 for operating external tie-
back
connector 102 when making connection with subsea wellhead 104. External
tieback
connector 102 may be a slimline or ultra-slimline tieback connector such as
available
commercially from GE Oil and Gas, Houston, TX (formerly Vetco); FMC
Technologies, Inc,
Houston, TX; and possibly other suppliers. One such tieback connector is
described in U.S.
Pat. No. 7,537,057. Those skilled in the art will understand that known
external tieback
connectors are engineered with the understanding that as the design tension on
the connector
increases, the allowable bending moment decreases in an inverse relationship.
Specific curves
for these capacity relationships are available from the manufacturers.
A flange 111 connects a bend restrictor 112 and subsea flexible conduit 14 to
a high-pressure
subsea bend stiffener 180, the latter having an internal profile 81 (see FIG.
3F) allowing
subsea flexible conduit 14 to fluidly connect with LRA gooseneck assembly 107.
As
illustrated schematically in FIG. 3F, bend stiffener 180 encases a flange
connection 81
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connecting subsea flexible conduit 14 to a high-pressure subsea connector 181,
the latter used
to mechanically and fluidly connected to conduit 107B of LRA 8. Bend stiffener
180 may
take the moment off of flange connection 81 so that it is transferred directly
from bend
restrictor 112 to high-pressure subsea connector 181, which is coming out of
the upper end of
bend stiffener 180. Containment or production fluids flow upward through
subsea flexible
conduit 14 and flange connection 81 into a hub assembly 116B (two hub
assemblies 116A
and B are indicated in this embodiment), and further through an LRA production
wing valve
assembly 114B (two production wing valve assemblies 114A and B are indicated
in this
embodiment, FIG. 3A).
As illustrated in FIGS. 3A and 3F, LRA production wing valve assemblies 114A
and B each
comprise respective block elbows 109A and 109B, and ROV-operated manual gate
valves
115A and B as well as respective flow paths 115C and 115D (FIG. 3F). ROV hot
stab panels
150A and B, respectively, may be provided for temperature and pressure
monitoring. A
subsea clamp structural support 118 provides support for subsea connectors
119A and 119B
(such as available from Vector Subsea, Inc. under the trade designation
OPTIMA). An ROV
hot stab panel 121 with a mount to blind hub assembly 116A is provided, which
may
accommodate pressure and/or temperature monitoring sensors. Four swivel hoist
rings 123
are also provided on structural support 118 in this embodiment.
FIG. 3C is a detailed view illustrating schematically hex bolts 94 welded at
93 to a clamp bolt
retaining block 95. Block 95 is also welded at locations 97 to the body of
subsea connector
119B. A similar arrangement is included on subsea connector 119A, but is not
illustrated.
FIG. 3D is a side elevation view, and FIG. 3E is a plan view of LRA 8.
Gooseneck 107 may
swivel through a wide angle as may be required during connection of flexible
conduit 14, as
viewed from the plan view, but once secured by connector 119B this motion is
restricted.
FIG. 3F is a cross-sectional view taken along the dotted line of FIG. 3E, and
illustrates
certain internal features of LRA 8, most particularly the containment or
production fluid flow
path, as indicated by reference numerals 113, gooseneck conduit 107B (through
connector
107A), 116C, 115C (through valve 115B and block elbow 109B), and finally flow
path 64
through internal tieback connector 92 and inner riser 60. FIG. 3F also
illustrates five casing
(sometimes referred to in the art as lockdown) hangers 103 pre-installed into
subsea wellhead
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104, the upper most hanger latching internal tieback connector 92 into subsea
wellhead 104,
as explained further in reference to FIGS. 4A, B and C. In certain embodiments
there may be
one, two, three, or more hangers 103. FIG. 3G indicates position of thermal
insulation,
designated INS, on portions of LRA 8.
Further details of this embodiment of an LRA are illustrated in FIGS. 4A, B,
and C, which
illustrate use of two locking hangers 704, 724. In addition to previously
detailed features,
FIGS. 4A, B, and C illustrate a plurality of connector lock indicator rods 720
that travel up
and down and show whether external tieback connector 102 is open or fully
locked. Also
illustrated are one of two secondary mechanical lockdown plates 702 (the other
being hidden
in FIG. 4A), as well as tubing 110A for flow of hydraulic fluid via hot stabs
110. Hot stabs
and tubing 110A, which passes through end cap 110B (or through other exterior
ports in
connector 102) are parts of an upper active locking system 102A for external
tieback
connector 102. A lower passive locking system 102F is also included in this
embodiment. An
example of mechanical details and operation of upper active locking system
102A and lower
passive locking system 102F are provided in U.S. Pat. No. 6,540,024. Briefly,
upper active
locking system 102A comprises an inner sleeve 102C, a hydraulically, axially
movable piston
102D, and an upper locking element 102E, which may be a split ring, collet, or
plurality of
dogs circumferentially disposed within a chamber formed between an inner
surface of outer
tieback connector 102 and a lower portion of piston 102D.
Some details of lower passive locking system 102F of external tieback
connector 102, as well
as some details of inner tieback connector 92, are illustrated schematically
in cross-section in
FIG. 4C. Lockdown hangers 704 and 724 are provided, hanger 704 providing about
2 million
lbf (about 0.9 million Kgf) of lockdown capacity in this embodiment. FIG. 4C
further
illustrates an internal tieback connector outer body or sleeve 708, and an
inner body or
mandrel 709. A set of lock down dogs 717 is provided to lock lockdown casing
hanger 704 to
subsea wellhead housing 104. Another set of locking dogs 901 are provided for
locking
external tieback connector 102 to subsea wellhead housing 104. A lower set of
locking dogs
706 lock sleeve 708 of internal tieback connector 92 to lockdown casing hanger
704, and thus
also locking to subsea wellhead housing 104.
Still referring to FIG. 4C, a similar set of upper locking dogs 740 lock
internal tieback
connector 92 to stress joint 2FJB and thus to external tieback connector 102.
The lower and
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upper sets of dogs provide a secondary lock of the riser to subsea wellhead
104 and may
maintain pressure integrity with the nose seal 92A fully engaged should
external tieback
connector 102 become unlocked from subsea wellhead 104 for whatever reason.
Also illustrated schematically in FIG. 4C are packoff assemblies 710, 711, and
715, and a
landing surface 712 on an internal portion of casing hanger 704 for landing
internal tieback
connector nose seal 92A. Packoff 711 includes a wedge 711A which forces dogs
717 into a
set of internal mating grooves 717A of wellhead housing 104. Dogs 901 are
positioned within
a grooved window 902 in external tieback connector 102. FIG. 4C further
illustrates a
wellhead gasket 716. As will be understood by those of skill in the art, one
or more of the
dogs described herein maybe replaced by a split ring, collet or other
functional equivalent.
Internal tieback connector 92 has a nose seal 92A, which may be Inconel, which
seals into
landing surface 712 of lockdown hanger 704. Internal tieback connector 92
latches with dogs
706 both to lockdown hanger 704 and to stress joint 2FJB in order to create a
preloaded
structural connection between subsea wellhead 104 and internal and external
tieback
connectors 102 and 92 (in addition to the external active connector latch to
the wellhead ¨ so
there is multiple redundancy). Nose seal 92A may provide pressure integrity
between the
internal flow path 64 and annulus 76 between the inner and outer risers 60,
70. Hence, as
illustrated in FIG. 3F, oil and gas to be contained or produced coming up
through subsea
flexible jumper 14 through a passage defined by inner surface 113 of flexible
14, enters the
wing valve assembly through passages 107B and 116C, and flows through elbow
block 109B
and forging 106. With nose seal 92A engaged, the produced fluids have only one
way to go
and that is up through inner riser 60 through passage 64 to the URA and
ultimately through
flexible conduit 12 to containment vessel 32 in this embodiment.
Another embodiment of a lower riser assembly is provided schematically in
FIGS. 5A-5G. In
this embodiment, a substantially cylindrical member 220 is provided, which is
a forged high-
strength steel member. Member 220 is fluidly connected to a production riser
pup joint 221
via a lower cross-over joint 222 and threaded connector 242. A padeye flange
223 allows
connection of member 220 to a pile assembly on the seabed. Dual clamp supports
224A and
224B support subsea connectors 225A and 225B, respectively. Two production
wing valves
assemblies 226A and 226B are provided, each fluidly connected to member 220
through
respective block elbows 230A and 230B. Each assembly 226A and B includes an
ROV-
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operable valve 227A and 227B. An additional assembly or sub 228 is provided,
fluidly
connecting to member 220 through a block elbow 229. Assembly or sub 228 may
provide a
fluid connection to a source of a functional fluid, such as a flow assurance
fluid or other fluid.
In this embodiment, block elbow 229 is smaller than block elbows 230A and
230B, but this is
not necessarily so. Another assembly 231 is a hot stab assembly for injection
of a functional
fluid. In this embodiment, hot stab assembly 231 provides for a smaller flow
rate of
functional fluid than is possible through assembly 228, but once again this is
not necessarily
so in all embodiments. A small diameter conduit 241 (FIG. 5F) allows delivery
of the
functional fluid.
FIG. 5C illustrates a perspective view of a production tubing or casing 232
that connects to
an internal surface of member 220. Production tubing 232 includes a tieback
ring 233 and a
seal element 234, which may be an S-type seal element. Seal element 234 may be
comprised
of Inconel or other corrosion-resistant metal. As further illustrated
schematically in FIGS. 5D
and 5E, tieback ring 233 includes at least one set of internal threads 235
which mate with a
set of threads on production tubing 232. Tieback ring 233 also includes at
least one set of
external threads 236 which mate with threads on an internal surface of member
220. FIG. 5E
illustrates dual inline ROV-operable valves 237A and 237B for functional fluid
injection (or
circulation out) included in annulus vent sub 228, which includes a bore 238
providing access
to an annulus between production tubing 232 and member 220 and lower cross-
over joint
222. A flange connection 239 or other connection may be provided for this
purpose. Each
production wing valve assembly 226 includes a connector 240 (240A and B) which
allows
connection to subsea flexible conduits, as illustrated in the plan view of
FIG. 5G. Connectors
240A and 240B may be connectors known under the trade designation OPTIMA,
available
from Vector Subsea, Inc.
FIG. 8C is a side elevation view of another LRA assembly in accordance with
the present
disclosure. This LRA embodiment may include a forged, high-strength steel
intake spool 920,
a connector 921 and gooseneck 944, subsea API flange 945, tubing spool 946,
high-pressure
subsea connector 180, another subsea API flange 111, bend restrictor 112, and
subsea flexible
conduit 14 which may connect to a subsea source of hydrocarbons (not
illustrated). Another
connector 947 on intake spool 920 may allow connection to a source of
functional fluid.
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FIG. 8D illustrates, in cross-section denoted 8D-8D in FIG. 8C, details of
this embodiment of
LRA, illustrating an internal tieback connector 92 landed in an internal
surface of intake
spool 920. A latching mechanism 930 allows internal tieback connector 92 to
releasably
connect to intake spool, while an 0-ring seal 928 may provide a fluid-tight
seal between the
bore of internal tieback connector 92 and annulus 76. Flex joint 2FJB is
connected to intake
spool in known fashion, for example by split rings, collets, or dogs as
described herein for
other embodiments.
Upper Riser Assembly (URA)
FIG. 6 is a schematic side-elevation view, with portions cut away, of a
general embodiment
of an upper riser assembly 6 in accordance with the present disclosure. Upper
riser assembly
(URA) 6 in this embodiment is a generally cylindrical member including an
upper end 6UE
and a lower end 6LE, and defines an inner bore 6IB. URA 6 shares a common bore
with outer
riser 70 in this embodiment and may share more than one common bore therewith.
Conduits
6A and 6B are fluidly connected to URA through offtake ports 60T, conduit 6A
being fluidly
connected to the inner bore of inner riser 60 while conduit 6B fluidly
connects with an
annular space created by URA inner bore 6IB and inner riser 60. URA upper end
6UE is
connectable to a near-surface buoyancy device (not illustrated) through a
chain tether or other
connector 127.
FIGS. 6A-6G include various views, some in cross-section, of another
embodiment of an
upper riser assembly in accordance with the present disclosure. FIG. 6H is a
schematic
perspective view, and FIGS. 61 and 6J are cross-sectional views, of a portion
of the upper
riser assembly embodiment of FIG. 6; FIG. 6K is a perspective view of a seal
test port. URA
6 in this embodiment includes a tubing head 122, which serves as fluid
connection between a
casing head and stem joint 124 manufactured by GE Oil & Gas, and a drilling
adapter spool
120. Drilling adapter spool 120 and tubing head 122 are mechanically connected
together
using a plurality of lockdown assemblies 120A, while tubing head 122 and
casing head and
stem joint 124 are also mechanically connected using a second plurality of
lockdown
assemblies 122B. Lockdown assemblies 120A and 122B may be the same or
different, and
may be lockdown screw assemblies or other locking assemblies known in the art.
One non-
limiting example of a lockdown screw assembly is provided in U.S. Pat. No.
4,606,557. Also
included are a shackle adapter flange 126, padeye end forging 128, and U-link
125 which
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provides a connection for tether chain 127. All of these items (except the
shackle flange) are
available from GE Oil & Gas.
Tubing head 122 may be machined with a 5-1/8" 10K API flange connection, and
production
wing valve assembly 136 attached with one hydraulically actuated 5-inch (13cm)
10,000 psi
(69 MPa) emergency shutdown valve, 137B, and one ROV-operated 10,000 psi (69
MPa)
emergency shutdown valve, 131. A pressure and temperature monitoring ROV hot
stab port
panel 139 may be provided in certain embodiments, and a nitrogen (or other
fluid) injection
ROV panel 152 may be provided in certain embodiments for injection of nitrogen
or other
gas atmosphere into the riser annulus. Tubing 158 for nitrogen or other gas
atmosphere
injection into the annulus may be included in this embodiment, as well as
pressure,
temperature and bleed ports (through ROV access panel 153) between the valves
on the
production flow path. A burst disc 156 on ROV panel 152 may be provided. ROV
hot stab
ports and pressure gauges may be provided in between the two ESD valves on the
URA in
order to circulate functional fluid back through flexible conduit 12 to the
surface structure
and to bleed pressure from the line if necessary (while keeping the first
valve closed). An
umbilical mounting bracket 155 is supplied. A series of outtake ports 130 may
be provided in
tubing head 122 (see FIG. 6A), as well as a plurality of intervention ports
135.
As illustrated in FIG. 6B, a flange connection 133 may connect a high pressure
subsea
connector 184 to a bend restrictor 134. Also provided are a kick-off spool 138
and bend
restrictor adapter 157. A lifting eye 129A may be provided for lifting the
production wing
valve assembly 136, but not when subsea flexible conduit 12 is attached.
FIG. 6D is a side elevation view of the URA 6, and FIG. 6E is a cross-
sectional view through
section A-A of FIG. 6D. As illustrated in FIG. 6E, a URA adjustable hanger 159
is provided
in this embodiment. Also indicated is the containment fluid flow path, first
upward through
bore 64, then laterally through passage 137D in block elbow 137A and
connection 132, then
downward through a passage 137C in valve 137B and passage 131A in valve 131,
and finally
out URA through flow path 184B in subsea connector 184A, which is connected to
flexible
conduit 12 through flange 184C, and flow path 12A through flexible conduit 12
to
containment vessel 32 at the sea surface in this embodiment.
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[0128] FIG. 6F is a plan view of URA 6, illustrating in more detail some of
the previously
mentioned features. Further details of this embodiment of an URA are
illustrated in FIGS.
6H-K. A nitrogen injection port 158A is illustrated, as well as a lower
portion 122A of tubing
head 122, the lower portion including a seal test port 718. Further
illustrated is a seal ring 720
between tubing head 122 and casing head 124; a metal-to-metal seal 722; a
torque tool profile
724, a crossover connection 726, and a hanger support load ring 728, as well
as a packoff
730. FIG. 6J further illustrates a URA forging 734 having ports 732 therein
suitable for
attaching pressure and temperature gauges. Finally, a seal ring 736 is
illustrated positioned
between drilling adapter spool 120 and tubing head 122. FIG. 6H and 61
illustrate casing head
and stem joint 124 comprise a casing head lower portion 124A and a stem joint
124B welded
at 124C to casing head lower portion 124A.
FIG. 6G is a schematic perspective view of the URA 6, illustrating the
placement of
insulation material, INS, around valves 137B and 131, as well as associated
piping.
FIGS. 7A and 7B are schematic perspective views of another upper riser
assembly (URA)
embodiment in accordance with the present disclosure, FIGS. 7C-7D are cross-
sectional
views of the embodiment of FIGS. 7A and 7B, and FIG. 7E is a detailed cross-
sectional view
of a portion of this embodiment. This URA embodiment is a different from the
URA
embodiment illustrated in FIGS. 6A ¨ 6K primarily as it allows circulating a
functional fluid,
such as heated water, through the annulus. The URA embodiment illustrated
schematically in
FIGS. 7A ¨ 7E, replaces two of the large wing valves and the large diameter
passages of the
embodiment schematically illustrated in FIGS. 6A ¨ 6K with ROV stab
functionality to inject
a functional fluid such as nitrogen. In the embodiment illustrated in FIGS. 7A-
E, another
flexible conduit (not illustrated for clarity) may be connected to the URA via
subsea
connector 818 and extend to a surface vessel if continuous or semi-continuous
circulation in
or through the annulus is desired.
An offtake spool 804 is fluidly connected to a hanger spool 803. Hanger spool
in turn is
connected in this embodiment to a tapered stress joint 802, which is not a
part of the URA per
se but is illustrated for completeness and to show how the URA may connect to
a riser
system. A shackle 806 and chain tether 807 allow the URA to be mechanically
connected to a
near-surface buoyancy device (not illustrated). As best illustrated in FIG.
7D, block elbow
808 includes an inner bore 808A which intersects with and is substantially
perpendicular to a
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bore 804A in offtake spool 804. Also included in this embodiment is a block
elbow 809 and
inner bore 809A which is also substantially perpendicular to bore 804A but
which does not
intersect bore 804A.
A gooseneck conduit 810 provides, in embodiments, a flow path for hydrocarbons
in
combination with elbow bore 808A, first emergency shutdown (ESD) valve 811 and
second
ESD valve 812. An outlet 813 in connector 813A may connect to a subsea
flexible conduit 12
for production or containment operations. Connector 813A may be a connector
known under
the trade designation OPTIMA, or other connector suitable for subsea use. An
ROV
connection 814 is provided for operation of connector 813A. A bleed valve 815
may also be
provided, serving to allow shutting in the URA, bleeding off contents of the
gooseneck
assembly 810, and retrieving the subsea flexible, for example for a hurricane
or other
unplanned event, or a planned event.
Valves 816 and 817 are provided for annulus circulation and/or production
and/or functional
fluid injection through connector 818. Valves 816 and 817 may be ROV-operable.
A
functional fluid may also be injected into the annulus via another ROV-
operable valve 819
and connector 820, which may be a flange connector.
FIG. 7E is a detailed cross-sectional view of an area where offtake spool 804
and hanger
spool 803 connect. Two ring seal and wire retainer arrangements 822 provide
dual seals
between fluid flowing in bore 825A in tubing 825 and chamber 827 holding slips
824.
Further included may be a passage 826 allowing access arrangements 822.
Another embodiment of an upper riser assembly in accordance with the present
disclosure is
illustrated schematically in side elevation in FIG. 8A. URS 6 includes, in
embodiments, a
production bore offtake spool 910 fluidly connected to a conduit 911 and to a
production
tubing 913. Production tubing 913 is fluidly connected to a bend restrictor
134 through a
subsea API flange 905, a high pressure subsea connector 184, another subsea
API flange
connection 133, and optionally a subsea connector (such as available from
Vector Subsea,
Inc. under the trade designation OPTIMA). Bend restrictor 134 may connect to a
subsea
flexible conduit 12, which extends in a catenary loop to a surface structure
in known fashion.
An ESD 915 is provided in this embodiment in tubing section 911, which may be
ROV-
operable. A support bracket 916 is provided in this embodiment, which in
addition to
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supporting tubing 913 at an angle a, also supports a bend shield 942 that
provides a
mechanical barrier between wing assemblies. Angle a may range from 0 to about
180
degrees, or from about 30 degrees to about 90 degrees, or from about 30 to
about 45 degrees.
Tubing 911 fluidly connects to an adapter 926, which in turn fluidly connects
to a hanger
spool 912 via an API flange 917, casing head 124 via another API flange 918,
stem joint
124B welded to casing head 124, and riser 2 threaded into stem joint 124B.
Offtake spool 910
may include a shackle flange 127 allowing connection to a chain tether 125 and
near-surface
buoyancy device (not illustrated).
Another feature of this embodiment, illustrated in FIG. 8A, is provision of a
connection 906
in hanger spool 912 for connecting a gooseneck 907, API flange 908, tubing
909, high
pressure subsea connection 940, another subsea API connector 940 and API
flange 941, and
bend restrictor 923 for a subsea flexible 919 for delivering heated water (or
other flow
assurance fluid) to hanger spool 912 from a surface structure. The heated
water (or other
flow assurance fluid) may then either circulate in the annulus, or traverse
through the annulus
generally downward toward an LRA and exit the annulus through one or more
annulus vent
sub valves, such as illustrated at 142, 144 in FIG. 8C.
FIG. 8B illustrates, in cross-section denoted 8B-8B in FIG. 8A, details of
this embodiment of
URA. An inner riser 60 is illustrated positioned inside of adapter 926, hanger
spool 912, and
casing head 124, creating an annular space 76 between in inner surface 912A of
hanger spool
912 and inner riser 60. A pair of 0-ring seals 925 seal inner riser 60 into
adapter 926 in this
embodiment. One or more slips 924 wedge between an inner slanted surface 943
of hanger
spool 912 and inner riser 60, firmly securing inner riser 60 in hanger spool
912.
FIG. 8C is a side elevation view of another LRA assembly in accordance with
the present
disclosure. This LRA embodiment includes a forged, high-strength steel intake
spool 920, a
connector 921 and gooseneck 944, subsea API flange 945, tubing spool 946, high-
pressure
subsea connector 180, another subsea API flange 111, bend restrictor 112, and
subsea flexible
conduit 14 which connects to a subsea source of hydrocarbons (not
illustrated). Another
connector 947 on intake spool 920 allows connection to a source of functional
fluid.
FIG. 8D illustrates, in cross-section denoted 8D-8D in FIG. 8C, details of
this embodiment of
LRA, illustrating an internal tieback connector 92 landed in an internal
surface of intake
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spool 920. A latching mechanism 930 allows internal tieback connector 92 to
releasably
connect to intake spool, while an 0-ring seal 928 provides a fluid-tight seal
between the bore
of internal tieback connector 92 and annulus 76. Flex joint 2FJB is connected
to intake spool
in known fashion, for example by split rings, collets, or dogs as described
herein for other
embodiments.
Flow assurance calculations may indicate that an FSR could be designed with a
5-layer, 3-
inch (7.6cm) thick polypropylene thermal insulation coating applied to the
outer riser, while
the annulus between the inner and outer riser would be displaced with low
pressure nitrogen.
During operation, this scheme may substantially maintain the temperature of
the
hydrocarbons from a subsea source to their arrival on the surface structure.
Materials, Methods of Construction, and Installation
Aside from gaskets, hoses, flexible conduits and other components which are
not considered
a part of the present disclosure, the primary components of the LRAs and URAs
described
herein (offtake spools, intake spools, hanger spools, generally cylindrical
members, riser
sections, tubing heads, casing heads, tubing spools, high pressure subsea
connectors, stem
joints, riser stress joints, and the like) may largely be comprised of steel
alloys. While low
alloy steels may be useful in certain embodiments where water depth is not
greater than a few
thousand feet, activities in water of greater depths, with wells reaching
20,000 ft (6000
meters) and beyond may result in above-normal operating temperatures and
pressures. In
these "high temperature, high pressure" (HPHT) applications, high strength low
alloy steel
metallurgies such as C-110 and C-125 steel may be more appropriate.
The Research Partnership to Secure Energy for America (RPSEA) and Deepstar
programs
have initiated a long term, large scale prequalification program to develop
databases of
fatigue data and derive derating factors on high strength materials for riser
applications with
the contribution of major operators, engineering firms and material vendors.
High-strength
steels (such as X-100, C-110, Q-125, C-125, V-140), Titanium (such as Grade 29
and
possibly newer alloys) and other possible material candidates in the higher
strength category
may be tested for pipe applications, and pending those results, they may be
useful as
materials for risers, LRAs, and URAs as described herein. Higher strength
forging materials
(such as F22, 4330M, Inconel 718 and Inconel 725) either have been or will
soon be tested
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for component applications in the coming years, and may prove useful for one
or more
components of the described LRA and/or URA assemblies, and/or risers. The test
matrix may
be designed to reflect various production environments and different types of
riser
configurations such as single catenary risers (SCR's), dry tree risers,
drilling and completion
risers. The project is currently scheduled to be divided into 3 separate
Phases: Phase 1 will
address tensile and fracture toughness, FCGR and S-N tests (both smooth and
notched) on
strip specimens of high strength pipes, high strength forging materials and
nickel base
alloy forgings in air, seawater, seawater plus Cathodic Protection (CP) and
sour
environment (non-inhibited) and a completion fluid known as INSULGEL (BJ
Services
Company, USA) with sour environment (non-inhibited) contamination (2008).
Phase 2 is
scheduled to be Intermediate Scale Testing (2009), and Phase 3 Full Scale
Testing with
H25/CO2/Sea water (2010). For further information, please see Shilling, et
al., Development
of Fatigue Resistant Heavy Wall Riser Connectors for Deepwater HPHT Dry Tree
Riser
Systems, OMAE (2009) 79518 (copyright 2009 ASME). See also RPSEA
RFP2007DW1403,
Fatigue Performance of High Strength Riser Materials, Nov. 28, 2007. The
skilled artisan,
having knowledge of the particular depth, pressure, temperature, and available
materials, may
design a system for each particular application without undue experimentation.
Over the past several years, the assignee herein has participated in
development of a
comprehensive 15/20Ksi (103/138 MPa) dry tree riser qualification program
which focuses
on demonstrating the suitability of using high strength steel materials and
specially designed
thread and coupled (T&C) connections that are machined directly on the riser
joints at the
mill. See Shilling et al., "Development of Fatigue Resistant Heavy Wall Riser
Connectors for
Deepwater HPHT Dry Tree Riser Systems", OMAE2009-79518. These connections may
eliminate the need for welding and facilitate the use of high strength
materials like C-110 and
C-125 metallurgies that are NACE qualified. (As used herein, "NACE" refers to
the
corrosion prevention organization formerly known as the National Association
of Corrosion
Engineers, now operating under the name NACE International, Houston, Texas.)
Use of high-strength steel and other high-strength materials may limit the
wall thickness
required, enabling riser systems to be designed to withstand pressures much
greater than can
be handled by X-80 materials and installed in much greater water depths due to
the reduced
weight and hence tension requirements. The T&C connections may reduce the need
for third
party forgings and expensive welding processes ¨ considerably improving system
delivery
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time and overall cost. Using these materials and connectors to design a fully
rated second
generation 15Ksi (103/138 MPa) FSR containment system, the outer riser can
actually be
downsized from the 13.813 inch (35.085cm) OD to 10.75 inch (27.305cm) OD x
0.75 inch
(1.91cm) WT with a 7 inch (17.8cm) OD x 0.453 inch (1.15cm) WT C-110 inner
riser. It will
be understood, however, that the use of third party forgings and welding is
not ruled out for
URAs, LRAs, and risers described herein, and may actually be preferable in
certain
situations. The skilled artisan, having knowledge of the particular depth,
pressure,
temperature, and available materials, may design a system for each particular
application
without undue experimentation.
Connections of assemblies described herein to risers, and intra-assembly
connections, such as
drilling spool adapter to tubing head connections, and connections of
substantially cylindrical
members to risers, and the like, may include threading such as described in
the above-
mentioned Shilling et al., article, as well as those described in the
following patent
documents: W02005093309; W02005059422; U.S. Pat. Nos. 6,752,436
and
6,729,658. Further information may be found in the following publications:
Sches et al.;
Fatigue Resistant Threaded and Coupled Connectors: the New Standard for Deep
Water
Riser Applications, OMAE 2007-29263; Sches et al., Fatigue Resistant Threaded
and
Coupled Connectors for Deepwater Riser Systems: Design and Performance
Evaluation by
Analysis and Full Scale Tests, OMAE 2008-57603; and Shilling et al.,
Developments in Riser
Technology for the Next Generation Ultra-Deep HPHT Wells, DOT Conference, 2008
Proceedings.
Materials of construction for gaskets, flexible conduits, and hoses useful in
conjunction with
the assemblies and methods described herein will depend on the specific water
depth,
temperature and pressure at which the assemblies are employed. Although
elastomeric
gaskets may be employed in certain situations, metal gaskets have been
increasingly used in
subsea application. For a review of the art circa 1992, please see Milberger,
et al., "Evolution
of Metal Seal Principles and Their Application in Subsea Drilling and
Production", OTC-
6994, Offshore Technology Conference, Houston Texas, 1992. See also API Std
601 -
Standard for Metallic Gaskets for Raised-face Pipe Flanges & Flanged
Connections and API
Spec 6A - Specification for Wellhead and Christmas Tree Equipment.
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Gaskets are not, per se, a part of the assemblies and methods of the present
disclosure, but as
certain LRA and URA embodiments may employ gaskets (such as wellhead gasket
716
mentioned in connection with the LRA embodiment of FIG. 3J), mention is made
of the
following U.S. Patents which describe gaskets which may be suitable for use in
particular
embodiments, U.S. Pat. No. 3,637,223, 3,918,485, 4,597,448, 4,294,477, and
7,467,663. In
certain embodiments, the gasket material known as DX gasket rated for 20 ksi
may be
employed.
Another gasket that may be used subsea is that known under the trade
designation Pikotek
VCS, available from Pikotek, Inc., Wheat Ridge, Colorado (USA). This type of
gasket is
believed to be described in U. S. Pat. No. 4,776,600, incorporated by
reference herein.
In certain embodiments the URA may have a retrievable burst disk, allowing
venting of the
URA to the atmosphere. In certain embodiments this burst disk may be a
retrievable burst
disk. Burst disks may allow, among other things, venting of the annulus above
the LRA, and
in certain embodiments may allow pumping of a functional fluid such as
nitrogen into the
annulus near the top of the FSR. Burst disks may allow pressure and/or
temperature
measurement of the flow stream (inside inner riser) or annulus between inner
and outer risers.
In addition to burst disks, high flow hot stabs may be employed in various
types of
equipment, for example, in the emergency disconnect systems.
Subsea flexible conduits, sometimes referred to herein as simply as
"flexibles", or "flexible
jumpers", are known to skilled artisans in the subsea hydrocarbon drilling and
production art.
For example, U.S. Pat. No. 6,039,083 discloses that flexible conduits are
commonly
employed to convey liquids and gases between submerged pipelines and offshore
oil and gas
production facilities and other installations. These conduits are subjected to
high internal and
external pressures, as well as chemical actions associated with the seawater
surrounding the
submerged conduits and the fluids being transported within the conduits. U.S.
Pat. No.
6,263,982 discloses subsea flexible conduits may comprise a flexible steel
pipe such as
manufactured by Coflexip International of France, under the trademark
"COFLEXIP", such
as their 5-inch (12.7cm) internal diameter flexible pipe, or shorter segments
of rigid pipe
connected by flexible joints and other flexible conduit known to those of
skill in the art.
Other patents of interest, assigned to Coflexip and/or Coflexip International,
include U.S. Pat.
Nos. 6,282,933; 6,067,829; 6,401,760; 6,016,847; 6,053,213 and 5,514,312.
Other possibly
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useful flexible conduits are described in U.S. Pat. No. 7,770,603, assigned to
Technip, Paris,
France. U.S. Pat. No. 7,445,030, also assigned to Technip, describes a
flexible tubular pipe
comprising successive independent layers including helical coils of strips or
different sections
and at least one polymer sheath. At least one of the coils is a strip or
strips of
polytetrafluoroethylene (PTFE). This list is not meant to be inclusive of all
flexible conduits
useable in systems and methods of the present disclosure.
Hoses, which may also be referred to herein as flexible jumpers in certain
embodiments,
suitable for use in the systems and methods of this disclosure may be selected
from a variety
of materials or combination of materials suitable for subsea use, in other
words having high
temperature resistance, high chemical resistance and low permeation rates.
Some
flouropolymers and nylons are particularly suitable for this application
except for conduits of
extremely long length (several kilometers or more) where permeation may be
problematic. A
good survey of hoses and materials may be found in US Pat. No. 6,901,968,
presently
assigned to Oceaneering International Services, London, Great Britain, which
describes so
called "High Collapse Resistant Hoses" of the type used in deep sea
applications, which, in
use, must be able to resist collapsing due to the very large pressures exerted
thereon.
In certain embodiments it may be necessary or desirable to splice one hose to
another hose, or
to replace a damaged hose. In these instances, the ROV-operable hose splicing
devices of
assignee's serial numbers 61479486 and 61479489, both filed April 27, 2011 may
be useful.
The '486 application describes ROV-operable hydraulically-powered hose
splicing devices,
while the '489 application describes ROV-operable non-hydraulically-powered
(mechanical)
hose splicing devices. Each device provides a full-bore connector while
allowing full-
pressure service that may be preferred for applications that require high flow
rates and high
pressure. A simple stab motion employing a guide funnel minimizes the
dexterity required of
the ROV pilot. The hydraulically-powered devices include at least two chambers
and a least
one self-engaging mechanical lock per chamber, wherein after a hose is stabbed
into a
chamber, the ROV pilot energizes the device and the connection is made without
further need
to move the ROV manipulators, and the hydraulic pressure can be released from
the
chambers. An ROV hot stab may be used in certain embodiments to connect the
device to an
ROV hydraulic power unit to energize and operate the device.
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The assemblies described herein may be useful with either a single pipe
(Single Line Offset
Riser ¨ SLOR) or a pipe in pipe design (Concentric Offset Riser - COR) that
provides
additional insulation and allows riser base gas lift or active heating through
the annulus.
These risers can be either welded or threaded construction and may be
tensioned by an upper
aircan located at 50-150m below the surface depending on the environmental
conditions, or
by hydro-pneumatic tensioners, or both. Each freestanding riser may be
connected to the
surface structure (for example, a surface vessel or production platform) by a
shallow water
flexible jumper.
In certain embodiments, riser tension is maintained using a non-integral
aircan system chain
tethered above the riser string. The aircans provides the necessary buoyancy
upthrust required
for global stability and motion performance control and ensures that positive
100 kips
(45,000 Kg) effective tension is experienced at the base of the riser under
all loading
conditions, including failure of one or more aircan chambers. In one
embodiment, an LRA
manufactured generally in accordance with FIGS. 3 and 4 weighs approximately
30 kips
(13,600 Kg) in air, 26 kips (11,800 Kg) submerged. It may be attached to the
suction pile
with 90 feet (27 m) of 117mm R-4 studless chain with a breaking strength of
2,915 kips
(1,300,000 Kg) and a 250 ton (230,000 Kg) Crosby G-2140 shackle with a
breaking strength
of 2,750 kips (1,230,000 Kg). The LRA in this embodiment is comprised of a
15Ksi (103
MPa) GE Oil & Gas (Vetco) H-4 subsea wellhead, specially machined with 2 x 7-
1/6 inch
(5.08 x 18.2cm) 10,000 psi (69 MPa) inlets to accommodate either multiple
flexible jumper
connections, or as illustrated in FIG. 3, one production jumper and an ROV
interface for
methanol injection.
The FSR containment or production concept which employs the assemblies
disclosed herein
is scalable over a wide range of water depths and well pressures and
conditions. Flow
assurance calculations indicate that the FSRs, and LRA and URA employed, are
capable of
handling over 40,000 bbls per day (6400 m3/day) each with a 6-inch (15cm) ID
flow path.
Existing dry tree riser hardware may be used to construct the FSRs as it is
readily available.
The outer riser joints may be 13.813-inch (35.085cm) OD x 0.563-inch (1.43cm)
wall X-80
material and rated to 6,500 psi (45 MPa). X-80 material may be used to weld on
premium
riser connectors with external and internal metal to metal seals and fatigue
performance for
the anticipated service life.
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Riser systems employing URA and/or LRA assemblies of the present disclosure
may be
installed, in certain embodiments, by a MODU and then accommodate upper
flexible jumper
installation after the riser has been run. The upper flexible may be connected
to the URA
during installation from the drilling MODU and optionally clamped at intervals
hanging
vertically along the riser. The lower subsea flexible may be connected several
days later to
the LRA by subsea installation vessels after the FSR is connected and
tensioned to the
suction pile.
The surface structure may be equipped with a quick disconnect system (QDC) for
the upper
flexible. Embodiments of a quick connect/disconnect coupling feature are
described in
assignee's United States provisional application serial number 61480368, filed
April 28,
2011. A disconnectable buoy may be used to support the surface structure end
of the upper
flexible during an emergency disconnect. The buoy may be attached to provide
both
buoyancy and drag and ensure the upper flexible is not damaged by too rapid a
decent (i.e.
excessive compression exceeding the minimum bend radius) after it released to
free fall. In
the event of a hurricane or a planned disconnect, the 6- inch (15cm) upper
flexible is
disconnected from the surface structure in a controlled manner and lowered by
a support
vessel to hang along the side of the FSR, where it is clamped in place via
ROV.
In certain concentric riser embodiments in which one or more of the LRAs
and/or URAs
described herein may be useful, the URA may allow for flow control of both the
inner riser,
as well as, the annulus between the inner and outer risers. The inner riser
flow path may have
provisions for pressure and temperature sensors; a fail close hydraulic
actuated ESD valve
controlled from the surface structure; a ROV hot stab pressure bleed port;
and/or an ROV
operated manual gate valve. The annulus may incorporate provision for ROV hot
stab
nitrogen injection, and a temperature and pressure sensor. A pressure safety
valve (PSV) set
at 4,500 psi (31 MPa) on the riser annulus may prevent failure due to over
pressure of the
outer riser in the event of a hydrocarbon leak from the inner riser.
In certain embodiments the LRA provides ROV hot stab access to both the riser
annulus and
production flow path for injection, venting, pressure and temperature
monitoring. Two ROV
operated 3-inch (7.5cm) valves on the annulus vent sub provide larger bore
access to the
annulus for nitrogen purging and venting operations, or other functional
operation. In certain
embodiments, the LRA flow path is comprised of two spools, each equipped with
an ROV
39
CA 02811110 2013-03-11
WO 2012/051148 PCT/US2011/055693
operated 5-inch (13cm) 10Ksi (69 MPa) valve and ROV operated clamps (such as
supplied
by Vector Subsea) for subsea connection of flexible production jumpers.
In certain embodiments, LRA and URA assemblies described herein may be used as
components of a containment and disposal, or production, system. In such
systems, a hydrate
inhibition system (HIS) may be integrated into the systems and methods.
Hydrate inhibition
chemical supply lines from a surface vessel may supply chemical to a subsea
BOP stack cap,
BOP, and to subsea flexible conduits through a subsea manifold. When
circulating the
chemical, it may return to the vessel through a return line. Chemical may also
be delivered to
choke and kill lines of the subsea BOP via a choke/kill manifold.
From the foregoing detailed description of specific embodiments, it should be
apparent that
patentable assemblies 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
apparatus, and is not
intended to be limiting with respect to the scope of the assemblies and
methods. 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.
