Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
1~53933
FLOW LINE BUNDLE AND METHOD OF TOWING SAME
Background of the Invention
1. Field of the Invention
This invention relates to flow lines located between two
points within a body of water, and more particularly, but not
by way of limitation, it relates to a flow line bundle including
a plurality of flow lines disposed in a tubular covering member.
2. Description of the Prior Art
U.S. Patents No. 3,677,302 and No. 3,526,086, both to
Morgan, each show pluralities of conduits disposed within a
tubular covering member. In Patent No. 3,526,086, however,
the space between the conduits and the covering member is
filled with a solid material 30, so that such a space could not
be filled with sea water. In Patent No. 3,677,302, the tubular
covering member includes a plurality of articulated joint por-
tions, and the covering member is not sealed at those joint~,
so that the combination of the conduits and the covering member
would never be buoyant. Furthermore, the structure disclosed
in Patent No. 3,677,302 comprises a riser assembly, rather
than a flow line bundle.
U.S. Patents No. 4,120,168 and No, 4,052,862, both to
Lamy, disclose a single conduit located within a tubular cover-
ing. Spacers are connected between the conduit and the
covering, and a space between the conduit and the aovering may
be filled with water.
The prior art includes methods of towing a tubular member
through a body of water by constructing the tubular member so
that it is neutrally buoyant at a position located above a floor
of the body of water, with weight means parti~lly engaging the
floor of the body of the water. Such a structure is shown for
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933
example in U.S. Patent ~o. 4,107,933 to Lamy. Other disclosures of
that yeneral type are shown in U. S. Patent No. 4,135,844 to
Lamy, U. S. Patent No. 4,011,729 to Kermel, U. S. Patent No.
3,262,275 to Perret and U. S. Patent No. 4,145,909 to Daughtry.
Additionally Patent No. 4,145,909 shows, at FIG. 8 thereof,
a method for pulling in an end of a tubular member for connec-
tion to a subsea structure. Another apparatus for pulling in
an end of a tubular member for connection to a subsea structure
is disclosed in Paper No. OIC-3074 entitled "Second End Flowline
Connection Without Length Adjustment" presented at the Tenth
Annual Offshore Technology Conference in Houston, Texas, during
the period of May 8-11, 1978, and that same apparatus is also
disclosed in an article entitled "Laying Underwater Pipelinés
By Float and Chains Method" in the April, 1978 issue of Ocean
Resources Engineering.
U. S. Patent No. 2,297,165 to Ringel shows several versions
of spacer members for locating one tubular member inside another
tubular member.
Summary of the Inventlon
In connecting two points within a body of water, such as
a subsea wellhead and a producing platform, it is generally neces-
sary to lay several lines between the wellhead and the platform~
The present invention provides an imp~oved method of constructing
and installing a flow line bundle including such a plurality of
lines between the subsea wellhead and the platform. A plurality
of fluid conducting conduits is disposed within a tubulax cover-
ing member. A plurality of longitudinally spaced spacer means
are connected to said conduits to retain the conduits in a
spaced relationship from the tubular covering member. A manifold
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member including a plurality of ~orts is attached to each
end of the conduits so as to provide fluid communication be-
tween the ends of the conduits and the ports of the manifold
members. A cap means is sealingly engaged with an end of each
of the manifold members to prevent water from entering said
ports.
The flow line bundle just described is constructed on
land and then is towed to the installation site. The bundle
has a slight positive buoyancy when it is not hampered by
additional weight other than the structure of the bundle just
described. Additional weight means such as chains or the like
are then attached to the bundle to cause it to have a neutral
buoyancy at a point a short distance above a floor of said body
of water with said weight means partially engaging said floor.
Then a towing tug is attached to a leading end of the flow line
bundle by a first flexible line, and a restraining tub is attached
to a trailing end of the flow line bundle by asecond flexible
line.
The flow line bundle is then towed in a catenary fashion
between the two tugs to the point of installation. This may be
done by either of two basic methods.
By a first method, the flow line bundle is towed at a
short, relatively constant distance above the ocean floor with
the chains or other weight means engaging the ocean floor.
During the course of the towing operation, if obstacles are
encountered which are located above the ocean floor, the trailing
tug will increase the restraining force being applied to the
second flexible line so as to lift the flow line bundle off
the ocean floor and cause it to "fly" over the obstacle on the
~cean floor.
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The second method is similar to the first, except that
the restraining tug continually applies a restraining force
during the towing operation, sufficient to maintain the flow
line bundle at a controlled distance from the surface of the
body of water. The weight means generally do not engage the
ocean floor during the towing procedure of the second method.
~ hen the bundle is finally brought to the point of installa~
tion, the cap means are removed from the ends of the flow line
bundle and the ends of the bundle are attached to the subsea
wellhead and the producing platform. Then the space between
the conduits and the tubular covering member of the flow line
bundle is flooded with sea water so as to cause the bundle to
sink to the ocean floor.
Additionally, one of the fluid conducting conduits gen-
erally conducts a relatively high temperature fluid. Thepresence of the sea water surrounding the high temperature
conduit serves to transfer that heat relatively evenly to the
other conduits and to the tubular covering. The transfer of
heat to the other conduits causes all the conduits to expand
substantially equally due to the thermal expansion, so that
relative diffexences in the thermal expansion between conduits
are minimized. The transfer of heat to the outer covering
member serves to transfer the heat completely away from the
flow line bundle by conducting it through the covering member
to the body of water.
It is therefore a general object of the present invention
to provide an improved construction for a subsea flow line
bundle.
Yet another object of the present invention is the provi-
sion of a subsea flow line bundle including a plurality of fluidconducting conduits disposed in a tubular covering member.
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Another object of the present invention is the provision
of an improved method for towing a flow llne bundle or other
tubular member through a body of water.
Yet another object of the present invention is the provi-
sion of a towing method for a tubular member through a bodyof water which provides a means for lifting the tubular member
above the obstacles upon the ocean floor.
Yet another object of the present invention is the provi-
sion of an improved method for connecting a subsea flow line
bundle between two points within a body of water.
Other and further objects, features and advantages of
the present invention will be readily apparent to those skilled
in the art upon a reading of the following disclosure in con-
junction with the drawings.
Brlef Description of the Drawings
FIG. 1 is a schematic elevation view of the flow line
bundle suspended a few feet above the ocean floor and being
towed between two tugs in a catenary fashion.
FIG. 2 is a schematic elevation view of the flow line
bundle of FIG. 1 when the trailing tug exerts sufficient
restraining force to lift the flow line bundle above an ob-
stacle on the ocean floor as the flow line bundle is being
towed. FIG. 2 also illustrates the appearance of the flow
line bundle when it is being towed at a controlled depth
below the ocean surface.
FIG. 3 is a cross-sectional view of the flow line bundle
showing the conduits located within the tubular covering mem-
ber and showing one of the spacer members.
FIG. 4 is a side elevation view of the leading sled of the
flow line bundle.
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FIG. 5 is a top plan view of the sled of FIG~ 4, with
the floatation tanks removed to allow the other componentstobe
more clearly seen,
FIG. 6 is an end view of the sled of FIG~ 4.
FIG. 7 is a sectional view, taken along line 7-7 of
FIG. 5, showing a cross-sectional view of one of the manifold
members of the flow line bundle.
FIG. 8 is an end view of the manifold member of FIG. 7
illustrating the location of the various ports within the
manifold member.
FIG. 9 is a schematic elevation view of the sled which has
been connected to a pull-in line connected to the producing
platform.
FIG. 10 is another schematic elevation view similar to
FIG. 9, showing the sled partially in place within the sled
receiving module of the producing platform.
; FIG. 11 is another view similar to FIG. 9, showing the
sled completely pulled lnto the sled receiving module and
showing the fluid connector connected to the manifold member
of the sled,
FIG. 12 is a schematic elevation view taken along line
12-12 of FIG. 15 prior to the connection of the fluid connector
to the manifold member. FIG. 12 shows the cap removing assembly
in its unactuated position.
FIG. 13 is a view similar to FIG. 12 showing the cap
removing assembly in lts downwardmost position with the cap
engaging prongs engaged with the tangentially extending flange
of the cap.
FIG, 14 is a view similar to FIG. 12 with the cap removing
assembly once again moved to itæ uppermost position having
pulled the cap out of engagement with the manifold membex~
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FIG. 15 is a schematic elevation view, similar to FIG. 11,
illustrating the fluid connector and illustrating the spring
loaded sled locking assembly.
FIG. 16 is an elevation view of the fluid connector, taken
along line 16-16 of FIG. 15.
FIG. 17 is a sectional schematic elevation view of the fluid
connector, taken along line 17-17 of FIG. 16.
Detailed Description of the Preferred Embodiments
Referring now to the drawings and particularly to FIG. 1
and 2, the flow line bundle of the present invention is shown
and generally designated by the numeral 10. Flow line bundle
10 may be a mile or more in length.
As is best shown in FIG. 3, the flow line bundle 10 includes
a plurality of fluid conducting condu1ts 12, 14, 16, 18, 20
and 22. The conduits 12-22 are located within an outer tubular
covering member 24. By way of example only, in one embodiment
of the present invention, conduits 12 and 14 are 3 1/2 inch
diameter flow lines. Conduits 16, 18, 20 and 22 are 0~84 inch
diameter hydraulic control lines. Tubular covering 24 has a
12 3/4 inch outside diameter.
Due to the remote location of the subsea well, and the
difficulty of servicing the same, it is desirable that conduits
12 and 14 be constructed to allow pump down type service tools
to pass therethrough. To that end the welds on conduits 12 and
14 should not protrude inward past the inner surface thereof.
A polyurethane spacer, generally designated by the numeral
26, is connected about the conduits 12-22 and holds the same
in a spaced relationship from an inner surface of the outer cover-
ing member 24. The spacer member 26 includes first and second
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spacer components 28 and 30 which are connected together by a
plurality of bolts (not shown), or the like. A plurality of
similar spacer members (not shown) are longitudinally spaced
from spacer member 26 at intervals of approximately fifteen feet
along the length of the conduits 12-22.
As seen in FIG. 3, it is desirable to locate the conduits
12-22 toward the bottom side of covering 24 so that the center of
gravity of the flow line bundle is below the center of buoyancy
of the flow line bundle.
Referring again to FIGS. 1 and 2, the flow line bundle 10
includes at its leading end a leading flow line sled assembly
32. At its trailing end the flow line bundle 10 includes a
trailing flow line sled assembly 34.
A first flexible line 36 is connected between the leading end
of the flow line bundle 10 and a towing tug 38 which may also
be described as a powered floating vessel. A second flexible
line 40 is connected between the trailing end of flow line bundle
10 and a trailing tug 42.
The flowline bundle 10 is constructed on land and the ends
thereof are sealed as will later be described. $he conduits
and the space between the conduits and the tubular coverlng
member 24 is then generally pressurized to around 200 psig with
nitrogen gas or the like. The flow llne bundle 10 is constructed
so as to have a positive buoyancy of approximately 1/2 pound
per foot when submerged in the body of water 44 prior to the
addition of any weight means.
It is desired that when the flow line bundle 10 is being
towed through the body of water 44, that the flow line bundle
10 float either just above a floor 46 of the body of water 44,
or at a controlled depth below the surface of the body of
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water as shown in FIG. 2. This is referred to as a buoyant
off-bottom tow method.
A plurality of weight means 48 are attached to the flow
line bundle 10 to cause the flow line bundle to have a neutral
buoyancy, at a position such as that illustrated in FIG. 1,
several feet above the ocean floor 46, with the weight means
48 partially engaging the ocean floor. Similar weight means are
shown for example in U.S. Patent No. 4,145,909 to Daughtry.
By a first method, the flow bundle 10 is towed in the manner
illustrated in FIG. 1, with the towing force being exerted by
the towing tug 38 and with the trailing tug 42 exerting slight
restraining force on second flexible line 40 to control the
trailing end of flow line bundle 10.
It is not uncommon, as the flow line bundle 10 is being
towed through the body of water 44, for obstacles such as ship-
wreck 49 or the like, which are located above the ocean floor 46,
to be encountered. Other such obstacles might also include
subsea pipelines (not shown) or the like.
The present invention provides a novel method of avoiding
underwater obstruction 49 in a manner illustrated in FIG. 2. As
the flow line bundle 10 approaches the obstacle 49, the trailing
tug 42 increases a reverse thrust thereof to increase a retard-
ing force applied to second flexible line 40 so as to lift the
flow line bundle 10 to a position, illustrated in FIG~ 2, a
considerable distance above the ocean floor 46, so that ths
flow line 10 is located above the obstacle 49 as it passes
thereover.
The manner of towing the flow line bundle 10 illustrated in
FIGS. 1 and 2 is often referred to as towing the flow line in a
catenary configuration. That is, the first and second flexible
llS3~33
lines 36 and 40 and the flow line bundle 10 roughly approximate
the shape of a catenary suspended between the leading and trailing
vessels 38 and 42. Of course they do not form a true catenary
due to the lack of flexibility and the nonuniformity of the weight
distribution across the entire system suspended between the
towing and trailing vessels, 38 and 42.
When the retarding force on the second flexible line means
40 is increased, the shape of the catenary is changed causing it
to have a much larger radius of curvature along its various points
and thereby causing the middle portion of the catenary defined
by the flow line bundle 10 to be raised above the ocean floor 46.
Alternatively, by a second method, the trailing vessel 42
continually applies a restraining farce sufficient to maintain
the flow line bundle 10 at a controlled distance below the
surface of the body of water 44, i.e. the flow line bundle 10
is generally maintained in the configuration shown in FIG. 2
throughout the towing procedure.
The specific depth below the surface at which the flow
line bundle 10 should be towed depends upon many factors, one
of which is the roughness of the sea at the time of the towing
operation. Generally, the rougher the surface conditions are,
the greater the towing depth should be so that the affect upon
the flow line bundle 10 from the rough sea is minimized.
The depth at which the flow line bundle 10 i8 towed may
be controlled in many ways. One way is to measure the depth
by sonic means or by pressure sensing means. Another way is
to control the distance between the leading and trailing vessels
38 and 42, which may be done with the aid of a radar type appa-
ratus located on the vessels to measure that distance,
Referr~ng now to FIGS. 4-7, the leading sled 32 is thereshown~
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11~39;33
Leading sled 32 includes a fram~ assembly 50 with floatation
tanks 52 and 54 attached thereto. Frame 50 includes lugs 53 to
which flexible line 36 may be attached.
FIG. 5 is a plan view of sled assembly 32 with the floatation
tanks 52 and 54 removed.
A manifold member 56 is attached to frame 50. Manifold me~ber
56 includes a manifold block 58 which has a plurality of ports
55, 57, 59, 60, 61, and 62 disposed therethrough, as seen in FIG.8,
for communication with conduits 16, 18, 20, 22, 12 and 14, res-
pectively. It is noted that FIG. 7 is a schematic illustration,
and the ports 57 and 62 thereshown are actually oriented in
accordance with FIG. 8. An end 64 of manifold block 58 is at-
tached to a manifold extension 66 by a clamping ring 68 which
engages outwardly extending flanges 70 and 72 of manifold block 58
and manifold extension 66, respectively.
Manifold extension 66 includes ports 74 and 76 communicating
with ports 57 and 62, respectively, of manifold block 58. Stub
extensions 78 and 80 extend from manifold extension 66 and
communicate with ports 74 and 76, respectively. Manifold extension
66 includes other ports and stub extensions corresponding to
ports 55, 59, 60 and 61.
Each of the relatively smaller conduits 16, 18, 20 and 22
has an end thereof welded to a stub extension such as stub ex-
tension 78. This provides fluid communication between the small
conduits and one of the relatively smaller ports such as port 74of manifold extension 66.
Each of the relatively larger conduits 12 and 14 is welded
to a stub extension such as stub extension 80 to provide fluid
communication with one of the relatively larger ports, for example,
port 76 of manifold extension 66.
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After the welding of the conduits 12-22 to the stub exten-
sions, such as extensions 78 and 80, of manifold extension 66
of manifold member 56, a tubular covering extension 82 is then
welded at its first end 84 to manifola extension 66 and at its
second end 86 to tubular covering 24~ The tubular covering
extension 82 may be considered to be a portion of the tubular
covering member 24.
Another end 88 of manifold block 58 is sealingly engaged
by a cap means 89 when the flow line bundle 10 is first assembled.
The cap means 89 is connected to manifold block 58 by a cap
retaining collar assembly 90, and prevents sea water from enter-
ing conduits 12-22 and covering 24 so that flow line bundle 10
has a positive buoyancy when submerged in water.
As may best be seen in FIG. 12, the cap retaining collar
assembly 90 includes first, second and third arcuate collar
portions 92, 94 and 96.
The first arcuate collar portion 92 includes a tangentially
extending flange 98. The second and third collar portions 94
and 96 are each hingedly connected to first collar portion 92
at hinge points 100 and 102, respectively.
Each of the second and third arcuate collar assembly portions
94 and 96 include radially outward extending flanges 104 and 106.
As is best seen in FIG. 7, the flanges 104 and 106 are con-
nected by a shear bolt 108. Attached to flange 104 of arcuate
portion 94 is a sliding shear member 110 which includes slots
112 and 114 disposed about connecting bolts 116 and 118.
The shear pin 108 may be sheared by moving sliding shear
member 110 longitudinally relative to cap retaining collar as-
sembly 90. When shear bolt 108 is sheared, the second and third
arcuate collar portions 94 and 96 separate and the collar assembly
90 may be removed~
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FIG. 8 is an enlarged ~iew of second end 88 of manifold
block 58 showing the various ports thereof. Additionally align-
ment blind bores 120, 122 and 124 are included for engagement
with alignment stubs 125 of a fluid conductor assembly 126 at-
tached to production platform 128. The fluid conductor assembly
126 is best illustrated in FIGS. 15-17.
After the flow line bundle 10 has been towed through the
body of water 44 to a location closely adjacent the two points
to be connected within the body of water, i.e. adjacent the sub-
sea wellhead (not shown) at one end, and adjacent the producing
platform 128 at the other end, the ends of the flow line bundle
are connected to the subsea wellhead and the producing platform
128 in substantially the following manner.
The manner of connection of the leading end of flow line
bundle 10 to the producing platform 128 will be described for the
purpose of this disclosure. The connection of the other end is
done in a similar manner.
As shown in FIG. 9, a pull-in cable 130 is connected between
leading sled 32 and a sled receiving module 132 of producing
platform 128. The pull-in cable 130 is preferrably connected
between a leading nose portion of a cylindricalframe extension
134 offrame S0 of sled assembly 32, and is then threaded through
a cylindrical frame extension receiver 136 and then is threaded
through a system of pulleys 138 and guides 140 which direct the
cable 130 to a position on producing platform 128 located above
the surface of the body of water 44. Then the first flexible line
36 is disconnected from flow line bundle 10.
The pull-ln cable 130 is then rétrieved, thereby pulling
leading sled assembly 32 into place within sled receiving module
132. FIG. 10 shows leading sled assembly 32 partially pulled
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into sled receiving module 132 so that the cylindrical frame
extension 134 is just engaged with the cylindrical frame exten-
sion receiver 136. FIG. 11 shows leading sled assembly 32 pulled
completely into its final position within sled receiving module
132.
FIG. 15 is a view similar to FIG, 11 showing æome additional
components of the sled receivingmodule 132. It will be under-
stood that both FIGS. 9-11 and FIG. 15 are schematic in form and
no attempt has been made to superimpose all of the apparatus of
the sled receiving module 132 in any one figure.
In FIG~ 15 the leading sled assembly 32 is shown in its
fully pulled-in position, in place within sled receiving module
132. When lead sled assembly 32 is in the fully pulled-in posi-
tion, a latching member 142 is resiliently urged by means of
spring member 144 into engagement with a latching cam 146 of frame
50 of sled assembly 32.
FIG. 15 illustrates leading sled assembly 32 with the cap
means 89 still retained in place upon manifold member 56 by
cap retaining collar assembly 90. That is the position those com-
ponents will be in when the leading sled assembly 32 is firstpulled into place within sled receiving module 132. Then the
other end of the flow line bundle 10 will be similarly pulled
into place withln a similar sled receiving module (not shown)
of the subsea wellhead assembly (not shown). It is noted that
it may sometimes be preferrable to pull-in the end adjacent the
subsea wellhead first.
~ he next operation which must be conducted is to remove the
sealing cap means 89 from manifold member 56 so that the manifold
member 56 may then be connected to f luid connector assembly lZ6.
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The manner in which cap retaining collar assembly 9Q and
sealing cap means 89 are removed is best described with relation
to FIG. 12-15. FIG. 12 is an elevational view taken along line
12-12 of FIG. 15. An end view is thereshown of sealing cap means
89 and cap retaining collar assembly 90, the components of which
have been previously described. For purpose of a clear illustra-
tion, the other components of leading sled assembly 32 have not
been shown in FIG. 12.
Located about cap retaining collar assembly 90 is a cap
removal apparatus assembly 148 which is attached to producing
platform 128. The cap removal apparatus 148 includes a frame
150 having vertical frame legs 152 and 154. A sliding cap re-
trieval frame 156 is slidably disposed upon vertical legs 152
and 154. First and second hydraulic cylinders 158 and 160 are
extendably connected between cap removal apparatus frame 150
and cap retrieval frame 156 so that cap retrieval frame 156 may
be moved downward from the position shown in FIG. 12 by extension
of pistons 162 and 164 of hydraulic cylinders 158 and 160, res-
pectively.
Cap retrieval frame 156 includes first and second prongs
166 and 168 for engaging first and secondprong receiving boles
170 and 172, respectively, of tangential flange 98 of cap re-
taining collar assembly 90.
The lowermost position of cap retrieval frame 156 with the
prongs 166 and 168 engaging flange 98 of cap retaining collar
assembly 90 is illustrated in FIG. 13.
The next step is to shear the shear bolt 108, shown in FIG.
7, connecting the second and third arcuate collar portions 94
and 96 of cap retaining collar assembly 90. This is best under-
stood by viewing FIGS. 15 and 7. The relative initial position
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between fluid connector assembly 126 and sealing cap means 89
is approximately shown in FIG, 15.
The fluid connector assembly 126 is slidably mounted
within a fluid connector assembly frame 186 so that the fluid
connector assembly 126 may be moved toward manifold member 56
by extension of a hydraulic cylinder 187 connected between
fluid connector assembly 126 and frame 186.
When hydraulic cylinder 187 is extended, fluid connector
assembly 126 is moved toward manifold member 56 and engages a
forward end 184 of sliding shear member 110 and pushes sliding
shear member 110 toward cap retaining collar assembly 90 so as
to shear the shear bolt 108. Fluid connector assembly 126 then is
moved out of engagement with manifold member 56 by retracting
hydraulic cylinder 187.
The cap retaining collar assembly 90 and sealing cap means
89 are then lifted out of engagement with manifold means 56 by
retracting the pistons 162 and 164 of hydraulic cylinders 158
and 160.
Generally, when the first one of the sealing cap means 89
is removed the flow line bundle 10 will at least partially fill
with water and sink to the ocean floor.
Next the fluid connector assembly 126 and manifold member
56 must be connected for fluid communication therebetween. The
construction of the fluid connector assembly 126 is best shown
in FIGS. 16 and 17. FIG. 16 is an end view taken along line
16-16 of FIG. 15.
It is noted that FIGS, 16 and 17 are only schematic illus-
trations of fluid connector assembly 126. Fluid connector assembly
126 includes an annular body member 174 connected to an end frame
176 by hydraulic rams 180 and 182.
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Located within annular body 174 are a plurality of longi-
tudinally extending fingers 188 which are resiliently connected
to fluid connector assembly 126 so that the free ends of 190
of fingers 188 may be deflected radially outward and inward.
Fluid connector assembly 126 includes an inner body 192
having a plurality of ports 189, 191, 193, 194, 195 and 196, for
fluid communication with ports 55, 57, 59, 60, 61, and 62,
respectively, of manifold member 56. A platform conduit bundle
197, as seen ~n FIG. 15, is connected at one end to the ports
of fluid connector assembly 126 and has a second end connector
assembly 199 for connection to a riser tube assembly (not shown)
leading to the surface of the body of water 44.
Adjacent an end face 198 of inner body 192 is a metal gasket
200. Metal gasket 200 ir.cludes a plurality of holes 202 disposed
therein for allowing alignment stubs 125 of inner body 192 to
protrude therethrough.
Adjacent each of the ports 191 and 194 are frustoconical
raised portions 204 and 206 for sealing engagement with the ports
57 and 60, respectively, of manifold member 56, Similar frusto-
conical surfaces are located adjacent ports 189, 192, 195 and 196.
Each of the frusto-conical sections preferrably includes a resil-
ient sealing ring (not shown) disposed therein as will be under-
stood by those skilled in the art.
The free ends 190 of longitudinally extending fingers 188
all include radially inward projecting tongue portions 208 which
engage an annular groove 210 disposed about a cylindrical outer
surface of manifold member 56. To lock fingers 188 into engage-
ment with groove 210, the pistons of hydraulic rams 180 and 182
are extended to the position shown in FIG. 17, so that a tapered
annular surface 209 of annular body 174 engages tapered radially
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outer surfaces 211 of fingers 188 and deflects fingers 188
toward groove 210.
When tongue portions 208 engage groove 210, the manifold
member 56 is locked in sealing engagement with metal gasket 200
so that fluid ccmmunication is provided between the conduits
12-22 and their respective ports within inner body 192 of fluid
connector assembly 126 through the ports of manifold member 56.
After the ends of the flow line bundle 10 have been connected
to the subsea wellhead (not shown) and the producing platform 128,
it is desirable to insure that all of the space between conduits
12-22 and outer tubular covering member 24 is completely filled
with sea water. This is accomplished in the following manner.
As is seen in FIG. 5, a first valve means or bleed-off
orifice 212 is connected to tubular covering extension 82,
and upon opening of first valve means 212 the space between con-
duits 12-22 and tubular covering 24 is communicated with the
body of water 44.
:`::
As is best seen in FIGS. 1 and 2, a second valve means 214
is longitudinally spaced from first valve means 212 away from
leading sled assembly 32. Upon opening the second valve means
the space between conduits 12-22 and outer covering 24 is placed
in fluid communiaation with the body of water 44.
The purpose of having first and second valve means 212 and
214 is to insure that all of the gases contained within the
~; 25 tubular covering 24 may be eas~ly bled off. The connections to
- the subsea ~ellhead assembly (not shown) and the producing
platform 128 are typically located approximately 10 feet above
the ocean floor 46. Therefore, when the middle portion of flow
line bundle 10 is laying on the ocean floor the first valve means
212 is the high point in the bleed-off system~ Sea water enters
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the second valve means 214 and gases within the co~ering member
24 escape through the first valve means 212. A s~milar bleed~
off is performed at the other end of flow line bundle 10.
At about the same time that covering 24 is flooded, the
buoyancy tanks 52 and 54 of sleds 32 and 34 are also flooded.
Typically one of the relatively large conduits 12 and 14 is
used to conduct hydrocarbons produced from the subsea well to
the producing platform. These hydrocarbons often have a temp-
erature relatively higher than that of the body of water 44 and
of the other conduits and tubular covering member disposed in
the body of water.
By flooding the space between conduits 12-22 and covering
member 24 with sea water, the heat fro~ the relatively high
temperature conduit, for example conduit 12, is transmitted to
the other conduits 14-22 and to the outer covering member 24.
The outer covering member 24 in turn conducts much of this heat
outward to the body of water. The flooding of the space between
conduits 12-22 and covering member 24 with water provides an
advantage, as opposed to the situation which would exist with
a similar system without the flooding, in that by transmitting
heat from ¢onduit 12 to the other conduits, the temperature of
the conduits is maintained much more nearly equal than would
otherwise be the case, so that differences in thermal expansion
~ of the conduits are minimized. Additionally by conducting heat
to the tubular covering 24 and outward into the body of water 44,
problems of thermal expansion are further reduced~
Thus, the flow line bundle and method of installing the
same of the present invention are well adapted to carry out the
objects and attain the ends and advantages mentioned, as well
asthose inherent therein. While presently preferred embodiments
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~lS3933
of the invention have been described for the purpose of this
disclosure, numerous changes in the construction and arrangement
of parts can be made by those skilled in the art, wh;ch changes
are encompossed with the spirit of this invention as defined
by the appended claims.
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