Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND DEVICE FOR INTERFACING WITH SUBSEA PRODUCTION
EQUIPMENT
BACKGROUND OF THE INVENTION
1. FIELD OF THE INVENTION
Generally, the present invention relates to the operation and maintenance of
subsea
production equipment, and more specifically to devices and methods for
interfacing with subsea
production equipment during operation.
2. DESCRIPTION OF THE RELATED ART
In the oil and gas industry, the properties and characteristics of the various
fluids that are
produced from oil wells can be critical for a proper understanding and
assessment of an oil and/or gas
reservoir. For example, in many cases, reliable knowledge of the individual
flow rates of the different
fluid phases that might be produced from a given well, such as liquid
hydrocarbons, gaseous
hydrocarbons, and/or water and the like, is often required to facilitate
proper reservoir management,
optimize overall field development, enable accurate production allocations,
and/or ensure that
operational control and flow assurance are maintained.
One conventional approach employed in the oil and gas industry for collecting
data on the
fluids that are produced from an individual well involves obtaining a material
sample from the
producing well at the wellhead, and then analyzing the sample to determine its
relative multiphase
constituents and characteristics. However, such an approach usually involves
the use expensive
equipment, e.g., test separators, requires periodic intervention by field/test
personnel, and does not
readily lend itself to continuous monitoring or metering. Furthermore, it
should be appreciated that
for applications involving subsea completions, at least some of these issues
may become even more
problematic. For example, the problems associated with obtaining samples from
a subsea facility may
be formidable, which may include thing such as the difficulty and cost
associated with regularly
accessing the subsea facility, the possibility of obtaining contaminated
samples, and the
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environmental concerns associated with sample spillage and/or well leakage at
the point of sampling.
Additionally, the complexity and/or physical geometry of the hardware
associated with a given subsea
facility may substantially affect access to the facility's various sampling
points when conventional
sampling equipment is used. As such, in at least some instances, a test sample
may not be readily
obtained until the produced fluid has reached the surface through a dedicated
test pipeline, where the
sampling conditions may be more manageable. However, test samples obtained in
this fashion may
be degraded to some degree due to changes in temperature or pressure from the
conditions at the
wellhead, and/or the test samples may be contaminated by residual fluids that
might still be present in
the test pipeline from previous well tests or by corrosion byproducts from the
test pipeline.
Furthermore, some subsea facilities involve multiple different wells, each of
which may be
producing fluids from different locations within a given reservoir or
formation, or even from different
formations. Moreover, in such cases each of the several different producing
wells may be owned by
different owners, and/or operated by different operators. However, as is the
case in most subsea
installations, the fluids produced from any one of these several different
wells are usually routed to a
common production manifold or other similar structure, where they are then
mixed with the fluids
from other wells in the field before flowing through a single production
pipeline to a central
production platform. When, as noted above, a fluid sample is then obtained at
the central production
platform and tested, it may provide relative information on the mixture of
fluids being produced from
the subsea installation as a whole, but that information may not be
representative of any one particular
well within the field. The issues associated with obtaining test samples from
a mixture of several
different production fluids are sometimes avoided by utilizing the production
manifold valving to
individually divert the various production fluids from the production manifold
header to a test header.
From there, a second line, e.g., a dedicated test pipeline as noted above, can
be used to send the
individual test samples to the surface. However, the sample degradation and
environmental
contamination issues described above still remain.
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As may be appreciated, the characteristics and quantity of fluids that are
produced from each
of the wells in a given subsea installation may be different ¨ and in some
cases, significantly different.
For example, a first well may produce fluids with a high percentage of liquid
hydrocarbons and a
relatively low percentage of produced water and/or noxious or corrosive gases,
e.g., hydrogen sulfide
and the like. On the other hand, a second well in the same subsea installation
may be drilled to a
different depth within the same formation, or it may be drilled in an entirely
different formation, and it
may therefore produce fluids having substantially different characteristics,
e.g., a lower percentage of
liquid hydrocarbons, or a higher percentage of gaseous hydrocarbons, or more
produced water, or
more hydrogen sulfide, etc. In such cases the second well may be considered to
be less economically
productive, and/or it may have a relatively higher operating and maintenance
costs. Accordingly, it
would be beneficial to have a clear understanding of the quantity and
characteristics of the fluids that
are produced from each individual well before they are combined with the
fluids from other wells in
the same subsea installation in the manifold or the pipeline leading to the
production platform, so that
each well might be properly evaluated on its own merits.
In recent years, the oil and gas industry has increasingly looked to the use
of multiphase flow
meters (MPFM's) in subsea applications as a valuable tool in assisting with
the evaluation and
assessment of the various individual producing wells in given subsea facility,
and to offset the cost of
a dedicated test pipeline. In practice, a different MPFM may be incorporated
into the wellhead
equipment for each individual producing well in a given subsea installation,
where it is able to provide
continuous information on the flow rates of the multiple fluid phases that are
produced from the well,
thereby facilitating at least some of the reservoir management goals described
above. However, it
should be appreciated that the fluid characteristics from any single producing
well may vary over the
effective life of the well, e.g., the liquid hydrocarbon rate may decrease
while the produced water rate
increases, etc. Multiphase flow meters are generally calibrated and adjusted
for greatest accuracy
within a predetermined range of a given well's produced fluid properties, and
when the actual
characteristics of the produced fluids deviates from that predetermined range,
measurement accuracy
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may be compromised. Furthermore, measurement accuracy may also drift over
time, should
recalibration efforts based on actual fluid properties, e.g., from test
samples, become less frequent.
Accordingly, it may still be necessary to periodically obtain specific fluid
samples from each
producing well so as to ensure that calibration and adjustment of a dedicated
MPFM for a particular
well is maintained within the appropriate accuracy range, although typically
the sampling frequency is
not generally as often as may have been previously required.
Figures 1A-1C schematically depict an illustrative prior art sampling system
110 that has
been used in subsea oil and gas applications to obtain test fluid samples from
a producing subsea well.
As shown in Fig. 1A, the sampling system 110 includes a sampling tool 100
that, in a subsea
environment, is typically mounted on and carried by a schematically-depicted
underwater remotely
operated vehicle (ROV) 130. Typically, the sampling tool has a height 109, a
length 117, and a width
116. While different specific design configurations of the sampling tool 100
have been used in some
prior art applications, both the height 109 and the length 117 of the sampling
tool 100 typically range
on the order of approximately 3-4 feet, whereas the width 116 is approximately
6-7 feet.
With reference to Fig. 1B, the ROV 130 is used to position the sampling system
110 adjacent
to a side 159 of a piece of subsea equipment, such as a subsea structure 150,
where a corresponding
interface point, such as, for example, a sample coupling 151, is located. The
sampling tool 100
includes docking probes 105 that are used to dock the sampling tool 100 to the
subsea equipment, e.g.,
the subsea structure 150, as the ROV 130 moves the sampling system 110 into
place adjacent to the
side 159. Also as shown in Fig. 1A, a belly skid 140 is mounted on the bottom
side of the ROV 130,
where additional equipment (not shown) necessary to operate the sampling
system 110 may be
located, such as pumps, valves, hydraulic and/or electrical equipment,
containment bottles, purging
equipment, and the like. In other applications, the sampling tool 100 may be
mounted to the front side
of belly skid 140 instead of to the front side of the ROV 130 as illustrated
in Figs. 1B and 1C, in
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which case the belly skid 140 may still be positioned below and mounted to the
bottom side of the
ROV 130 as shown in Fig. 1A.
The sampling tool 100 includes a sample coupling 101 having and axis 101x, one
or more
sample bottles 102, and a fluid communication system 103 (schematically
depicted in Fig. 1A) that
can provide fluid communication between the sample coupling 101 and the sample
bottles 102. The
fluid communication system 103 may include various pipes, conduits, tubing,
fittings, valves and/or
other typical piping system components and the like, which thereby allow a
flow of a test fluid sample
to move from the sample coupling 101 to the sample bottles 102.
Figure 1B schematically illustrates an elevation view of the sampling system
110 positioned
adjacent to a piece of subsea equipment, e.g., a wellhead 150, with the
sampling tool 100 mounted on
the front side 130a of the ROV 130. The subsea structure 150 is positioned
above the sea floor 190,
and includes a schematically depicted Christmas tree 154 for controlling the
flow of production fluid
out of a producing oil and gas well 170. The subsea structure 150 includes
docking receptacles 155
that are sized and positioned to engage the corresponding docking probes 105
on the sampling tool
100. In one example, the subsea structure 150 also includes a sample coupling
151 that is sized and
positioned to engage the sample coupling 101 on the sampling tool 100 when the
docking probes 105
are docked with the docking receptacles 155, while an axis 151x of the sample
coupling 151 is
aligned with the axis 101x of the sample coupling 101. The subsea structure
150 also includes a fluid
communication system 153 (schematically depicted in Fig. 1B) that can provide
fluid communication
between the production fluid that is being produced from the well 170, e.g.,
from the Christmas tree
154, and the sample coupling 151, thereby allowing a test fluid sample to flow
to the sample coupling
101 on the sampling tool 100, and thereafter to the sample bottles 102 via the
fluid communication
system 103.
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Figure 1C schematically depicts a plan view of the sampling system 110 of Fig.
1B positioned
adjacent to the side 159 of the subsea structure 150. As shown in Fig. 1C, the
side 159 of the subsea
structure 150 has a width 157 as presented to the approaching ROV 130 with the
sampling tool 100
mounted thereon. The docking probes 105 and docking receptacles 155 are
separated along the side
159 of the subsea structure 150 by a distance 156. Furthermore, the sampling
tool 100 has an overall
width 116, and the ROV 130 has an overall width 136.
Depending on the specific design and overall configuration of the subsea
equipment where
test fluid samples are obtained, e.g., the subsea structure 150, the width 157
may be in the range of
approximately 10-12 feet, and the distance 156 between the docking probes 105
and docking
receptacles 155 may be on the order of 5-6 feet. Furthermore, as noted above,
the width 116 of the
sampling tool 100 may be about 6-7 feet, while the width 136 of the ROV 130
may be approximately
7-8 feet. Accordingly, it should be appreciated that in many applications, the
sampling system 110,
which includes both the sampling tool 100 and the ROV 130, can take up a
significant amount of the
available space, e.g., the width 157, of the subsea structure 150 along the
side 159 during the docking
and sampling operations.
Also as shown in Fig. 1C, sampling system 110 has an overall length 138 that,
in some
applications, may be approximately 15-16 feet, or even greater. Furthermore,
in order to ensure a
proper approach during the docking activity, the sampling system 110 generally
requires an
appropriately sized docking space in front of the side 159 of the subsea
structure 150 that has a
docking space length 139 on the order of 25-30 feet, or even greater,
depending on several factors
such as the class (e.g., size) of the ROV 130, and/or the type and proximity
of any adjacent subsea
equipment, and the like. Moreover, the axis 101x of the sample coupling 101
must be closely aligned
with the axis 151x of the coupling 151, which means that the entire sampling
system 110 ¨ including
the ROV 130 ¨ must also be so aligned during at least the final portion of the
ROV's approach to the
subsea structure 150 during the docking operation. As such, it should be
appreciated that the ROV-
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mounted prior art sampling tool 100 shown in Figs. 1A-1C may not be readily
adaptable to existing
subsea equipment installations, due at least in part to the docking space and
alignment requirements
described above. Furthermore, even in new subsea installations that are
specifically designed to
accommodate an ROV-mounted sampling system, such as the sampling system 110,
the sampling
activities may be subject to some operational restrictions, also due at least
in part to the vehicle
docking limitations noted above.
During the sampling operation, it should be appreciated that any fluid samples
that are taken
from the producing subsea equipment should be extracted in such a state as to
reflect the actual fluid
components and/or conditions or the producing well 170 as closely as possible,
so that any
calibrations and/or adjustment to the MPFM's that are made based on the tested
properties of the fluid
samples result in metering accuracy. However, in some prior art applications,
if the sample bottles
used to store the extracted fluid samples (such as the sample bottles 102 of
the sampling tool 100) are
separated from the sampling point (such as the sample coupling 101) by too
great a distance, some
degree of fluid component separation and/or sample degradation may occur,
which could thereby
affect testing accuracy and subsequent MPFM adjustments. For example, in the
prior art sampling
system 110 illustrated in Figs. 1A-1C, the sample bottles 102 may be separated
from the sample
coupling 101 by a distance 112 such that the total flow distance that a test
sample must flow through
the fluid communication system 103 in order to reach a respective sample
bottle 102 may be in the
range of approximately 4-5 feet or even greater. Such a large flow distance
may be significant enough
to impact the quality of the test sample and the subsequent accuracy of any
testing results.
Figures 2A-2C schematically depict another illustrative prior art sampling
system 210 that
includes a sampling tool 200, which is made up of a sample coupling 201 having
an axis 201x, a
sample bottle 202, and a fluid communication system 203 (schematically
depicted in Fig. 2A) that can
provide fluid communication between the sample coupling 201 and the sample
bottle 202. In some
cases, the sampling tool 200 is held by a robotic manipulator arm 231 that is
mounted an underwater
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ROV 230. The sampling tool 200 generally has a height 209 that is
approximately 5-6 feet, a length
217 of about 21/2-3 feet, and a width 216 that ranges from 2-4 feet, as more
fully described below.
Accordingly, unlike the prior art sampling tool 100 of Figs. 1A-1C described
above, which typically
has its greatest dimension along a substantially horizontal direction, i.e.,
the tool's width 116, the
sampling tool 200 shown in Fig. 2A-2C has its greatest dimension along a
vertical direction, i.e., the
tool's height 209
Figure 2B schematically illustrates an elevation view of the sampling system
210 positioned
adjacent to a piece of subsea equipment, e.g., a wellhead 250, with the
sampling tool 200 being held
by the manipulator arm 231 mounted on the front side of the ROV 230. As with
the prior art
sampling system 110 of Figs. 1A-1C, the ROV 230 is used to position the
sampling system 210
adjacent to a side 259 of, for example, a subsea structure 250, where a
corresponding sampling point,
such as a sample coupling 251, may be located. A belly skid 240 is mounted on
the bottom side of the
ROV 230, where additional equipment (not shown) necessary to operate the
sampling system 210
may be located. The sampling tool 200 is connected to the belly skid 240 by
umbilicals 206, which
provide electrical, hydraulic, and/or fluid communication between the sampling
tool 206 and the
various pieces of support equipment 241 located on the belly skid 240.
With continuing reference to Fig. 2B, the subsea structure 250 includes a
sample coupling
251 for engaging the sample coupling 201 on the sampling tool 200, during
which time an axis 251x
of the sample coupling 251 is aligned with the axis 201x. The subsea structure
250 also includes a
fluid communication system 253 (schematically depicted in Fig. 2B) that can
provide fluid
communication between the production fluid that is being produced from the
well 270, e.g., from a
Christmas tree 254, and the sample coupling 251 so that a test fluid sample
can flow to the sample
coupling 201 on the sampling tool 200, and thereafter to the sample bottle 202
via the fluid
communication system 203.
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As shown in Fig. 2B, the prior art sampling tool 200 has a substantially
vertical packaging
configuration, and the manipulator arm 231 is connected to the sampling tool
200 near an upper end
200 thereof. As noted above, the sampling tool has a height 209 that typically
ranges from
approximately 5-6 feet. Furthermore, the subsea structure 250 has a height
269, which may extend
above the sea floor 290 approximately 8-10 feet, and the sample coupling 251
is positioned on the
subsea structure 250 so as to provide adequate clearance 209c between the
bottom 200b of the
sampling tool 200 and the sea floor 290 while the sampling tool 200 is docked
with the subsea
structure 250. Accordingly, due to the height 209 of the sampling tool 200
relative to the height 269
of the subsea structure 250, viable locations for the sample coupling 251 may
be limited, i.e., to an
upper portion of the subsea structure 250. Moreover, it should also be
appreciated that, when docked,
the sampling tool 200 may take up a significant portion of the vertical space
that is available on the
side 259 of the subsea structure 250, which may thereby limit the positioning
of other equipment
and/or access points on the subsea structure 250.
Figure 2C schematically depicts a plan view of the sampling system 210 of Fig.
2B positioned
adjacent to the side 259 of the subsea structure 250. As shown in Fig. 2C, the
side 259 of the subsea
structure 250 has a width 257 as presented to the approaching sampling system
210 that may be on the
order of 10-12 feet. The sampling tool 200 has an overall width 216 that
ranges from approximately
1-2 feet at the upper end 200u, and approximately 4 feet at a lower end 200b
(see, Fig. 2B), and as
previously noted a length 217 on the order of approximately 2-21/2 feet.
It should be appreciated that, even though the sampling tool 200 is supported
by the
manipulator arm 231 (instead of being directly mounted to an ROV as in the
prior art sampling system
110), the sampling system 210 still requires an appropriately sized docking
space in front of the side
259 of the subsea structure 250 so as to perform the requisite ROV approach
and coupling/docking
activities. Accordingly, the docking space length 239 adjacent to the side 259
may also be
approximately 25 feet or even greater. As such, it should be appreciated that
the manipulator arm-
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supported sampling tool 200 shown in Figs. 2A-2C may not be readily adaptable
to many existing
subsea equipment installations, due at least in part to the docking space
requirements described above.
Additionally, as shown in Fig. 2B, the sample bottle 202 is separated from the
sample
coupling 201 by a distance 212. In some cases, due to the overall size of the
substantially vertically
packaged sampling tool 200 as described above, the distance 212 can correspond
to a total flow
distance that a flow sample must flow through the fluid communication system
203 so as to reach the
sample bottle 202 that is in the range of approximately 5-6 feet, or even
greater. As noted previously,
such a large flow distance can detrimentally affect the quality of the test
sample the resulting accuracy
of any testing.
Moreover, as may be appreciated by those of ordinary skill in the art, the
strength and load-
carrying capacity of robotic manipulator arms that might typically be used on
ROV's in subsea
applications, such as the manipulator arm 231, is somewhat limited. For
example, a typical ROV-
supported manipulator arms may have a maximum load capacity of approximately
250-600 pounds
while undergoing an arm extension in the range of approximately 4-6 feet. On
the other hand, in
some cases the prior art sampling tool 200 may weigh as much as 500-1000
pounds. As such, the
capabilities of the manipulator arm 231, including how far it may have to
reach, can limit how and
where the sampling tool 200 may be positioned relative to the ROV 230, due at
least in part to the
load-carrying capacity of the manipulator arm 231. Furthermore, the size of
the load and the distance
it may have to be extended during the docking operation can also adversely
affect the pitch (tilt) of the
ROV 230, or change the center of buoyancy/gravity of the ROV 230. Accordingly,
in the prior art
sampling system 210 illustrated in Figs. 2A-2C, the manipulator arm 231 is
generally only used to
extend to sampling tool 200 relatively short distances away from the ROV 230,
such as in the range of
about 2-3 feet. Furthermore, due to the relatively large overall size and
weight of the sampling tool
200, the manipulator arm 231 generally does not have sufficient strength to
rotate the sampling tool
200 into a non-vertical, e.g., substantially horizontal, orientation, and as
such the sampling tool 200 is
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typically only supported and maintained in a substantially vertical
orientation (as shown in Figs. 2A
and 2B).
As may be appreciated, the overall size and maneuverability of the prior art
systems described
above present various restrictions and limitations on their use in at least
some subsea production
applications. Additionally, sample spillage and/or well leakage to the
surrounding environment
during the docking and sampling operations remains a matter of great concern.
Accordingly, there is
a need to develop equipment and methods that may overcome, or at least
mitigate, one or more of the
problems associated with the subsea production equipment interfacing
operations outlined above.
SUMMARY OF THE DISCLOSURE
The following presents a simplified summary of the present disclosure in order
to provide a
basic understanding of some aspects disclosed herein. This summary is not an
exhaustive overview of
the disclosure, nor is it intended to identify key or critical elements of the
subject matter disclosed
here. Its sole purpose is to present some concepts in a simplified form as a
prelude to the more
detailed description that is discussed later.
Generally, the present disclosure is directed to systems and methods for
interfacing with
subsea production equipment during operation. In one illustrative embodiment,
a fluid sealing and
transfer element is disclosed that includes, among other things, a flow body
having a first end and a
second end, a first flow groove proximate the first end, and a second flow
groove proximate the
second end. The illustrative fluid sealing and transfer element further
includes first and second flow
passages passing through the flow body, wherein the first flow passage
intersects the first flow groove
and the second flow passage intersects the second flow groove. Moreover, the
fluid sealing and
transfer element disclosed herein also includes and a third flow passage
passing through the flow
body, wherein the third flow passage intersects the first and second flow
passages and facilitates fluid
communication between the first and second flow grooves.
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Also disclosed herein is an illustrative flow control system that is adapted
to establish fluid
communication between an interface tool and an equipment item, the flow
control system comprising
a movable transfer tube sealing cartridge having a first end, a second end,
and a plurality of flow
passages that are adapted to facilitate fluid flow between the first end and
the second end.
Additionally, the disclosed flow control system includes a movement apparatus
that is adapted to
move the movable transfer tube sealing cartridge to a flow position so as to
facilitate fluid flow
between a first flow channel of the equipment item and a second flow channel
of the interface tool.
In another illustrative embodiment, an interface tool that is adapted to
interface with an
equipment coupling on subsea equipment is disclosed, the interface tool
including an interface
coupling that is adapted to be removably coupled to the equipment coupling on
the subsea equipment
during a coupling operation. Additionally, the interface tool also includes,
among other things; and a
flow control system that is adapted to establish fluid communication between
the interface tool and
the subsea equipment after the coupling operation. Moreover, the flow control
system of the
illustrative interface tool includes a fluid sealing and transfer element that
is adapted to replace a
replaceable fluid sealing and transfer element that, prior to the coupling
operation, is positioned in the
equipment coupling.
The present subject matter also discloses a system that is adapted to
interface with subsea
equipment, wherein the system includes an interface tool having an interface
coupling, the interface
coupling being adapted to be removably coupled to an equipment coupling on the
subsea equipment
during a coupling operation. Furthermore, the interface tool of the
illustrative system disclosed herein
also includes a fluid transfer element that is adapted to facilitate fluid
communication between the
interface tool and the subsea equipment after the coupling operation, the
fluid transfer element being
further adapted to replace a replaceable fluid transfer element that, prior to
the coupling operation, is
positioned in the equipment coupling. Additionally, the illustrative system
disclosed herein also
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includes, among other things, a manipulator arm that is adapted to support and
position the interface
tool during the coupling operation.
BRIEF DESCRIPTION OF THE DRAWINGS
The disclosure may be understood by reference to the following description
taken in
conjunction with the accompanying drawings, in which like reference numerals
identify like elements,
and in which:
Figures 1A-1C schematically illustrate a representative prior art system for
obtaining
production fluid test samples from a subsea structure;
Figures 2A-2C schematically illustrate another representative prior art system
for obtaining
production fluid test samples from a subsea structure;
Figures 3A-3E schematically depict an embodiment of an illustrative system
that is used to
interface with subsea production equipment in accordance with the presently
disclosed subject matter;
Figure 4A is a component block diagram of an illustrative interface system of
the present
disclosure;
Figure 4B is a fluid schematic diagram of the interface system illustrated in
Fig. 4A;
Figures 5A-5G depict various aspects of an illustrative interface system
disclosed herein;
Figures 6A-6H illustrate various aspects of an embodiment of a transfer tube
sealing cartridge
that may be used in conjunction with some illustrative embodiments of the
present disclosure;
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Figures 7A-7C shows some aspects of yet another illustrative interface
configuration of the
present disclosure;
Figure 8 schematically depicts various illustrative interface points for some
illustrative types
of subsea production equipment; and
Figure 9 schematically depicts various illustrative interface points for an
illustrative subsea
separator vessel.
While the subject matter disclosed herein is susceptible to various
modifications and
alternative forms, specific embodiments thereof have been shown by way of
example in the drawings
and are herein described in detail. It should be understood, however, that the
description herein of
specific embodiments is not intended to limit the invention to the particular
forms disclosed, but on
the contrary, the intention is to cover all modifications, equivalents, and
alternatives falling within the
spirit and scope of the invention as defined by the appended claims.
DETAILED DESCRIPTION
Various illustrative embodiments of the present subject matter are described
below. In the
interest of clarity, not all features of an actual implementation are
described in this specification. It
will of course be appreciated that in the development of any such actual
embodiment, numerous
implementation-specific decisions must be made to achieve the developers'
specific goals, such as
compliance with system-related and business-related constraints, which will
vary from one
implementation to another. Moreover, it will be appreciated that such a
development effort might be
complex and time-consuming, but would nevertheless be a routine undertaking
for those of ordinary
skill in the art having the benefit of this disclosure.
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The present subject matter will now be described with reference to the
attached figures.
Various structures and devices are schematically depicted in the drawings for
purposes of explanation
only and so as to not obscure the present disclosure with details that are
well known to those skilled in
the art. Nevertheless, the attached drawings are included to describe and
explain illustrative examples
of the present disclosure. The words and phrases used herein should be
understood and interpreted to
have a meaning consistent with the understanding of those words and phrases by
those skilled in the
relevant art. No special definition of a term or phrase, i.e., a definition
that is different from the
ordinary and customary meaning as understood by those skilled in the art, is
intended to be implied by
consistent usage of the term or phrase herein. To the extent that a term or
phrase is intended to have a
special meaning, i.e., a meaning other than that understood by skilled
artisans, such a special
definition will be expressly set forth in the specification in a definitional
manner that directly and
unequivocally provides the special definition for the term or phrase.
Generally, the subject matter disclosed herein is directed to various devices
and methods for
interfacing with subsea production equipment during operation. For example, in
some illustrative
embodiments, a subsea equipment interface system is disclosed that may be used
to extract production
fluid test samples from equipment in a subsea oil and gas installation during
equipment operation
without contaminating the sample to any appreciable degree, and without
causing or permitting
spillage of any appreciable amount of the production fluid to the subsea
environment. Additionally,
the disclosed system may also have fluid reservoirs of such a size so that any
contaminants that may
be present in various the lines that are used to extract the test fluid
samples may be substantially
flushed and/or isolated prior to sample extraction. Furthermore, the disclosed
equipment system may
also be arranged in a substantially compact configuration so as to minimize
the length of the flow path
along which the test samples must flow during sample extraction, thereby
reducing sample separation,
degradation, and/or contamination and the like.
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In other embodiments, the disclosed subsea equipment interface system may also
be used to
perform equipment clean-out operations, e.g., removing sand and/or other
solids materials from
separator equipment and the like. In still other illustrative embodiments, the
subsea equipment
interface system of the present disclosure may be used to perform other
intervention activities on
subsea equipment, such as, chemical injection and/or hydrate remediation at,
for example, pipeline
end termination (PLET) structures, subsea piping manifolds, and the like.
It should be noted that, where appropriate, like reference numbers shown in
Figs. 3A-7C and
used to describe the various embodiment set forth below generally refer to
like elements. For
example, the sampling tool "300" substantially corresponds to the sampling
tools "400," "500,"
"600," and "700," the sample coupling "301" substantially corresponds to the
sample couplings
"401," "501," "601," and "701," the umbilicals "302" substantially correspond
to the umbilicals
"402," "502," "602," and "702," and so on. Accordingly, the reference number
designations used to
identify some elements of the presently disclosed subject matter may be
illustrated in Figs. 3A-7C, but
may not be specifically described in the following disclosure. In those
instances, it should be
understood that the numbered elements shown in Figs. 3A-7C which are not
specifically described in
detail below may substantially correspond with their like-numbered
counterparts illustrated in other
illustrative embodiments and described in the associated disclosure.
Figures 3A-3E depict various aspects of various embodiments of a subsea
equipment interface
system disclosed herein. Figures 3A and 3B schematically depicts an
illustrative subsea equipment
interface system 310 of the present disclosure that, in certain embodiments,
may be adapted to obtain
production fluid test samples from a piece of subsea production equipment,
such as the subsea
structure 350, which may be for example, a wellhead structure and the like.
The interface system 310,
may include an interface tool 300, which in the present embodiment may be, for
example, a sampling
tool (hereinafter, a sampling tool 300). The sampling tool 300 may include,
among other things, an
interface coupling 301, e.g., a sample coupling 301, that has an axis 301x and
is adapted to interface
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with a corresponding sample coupling 351 (see, Fig. 3B) on the subsea
structure 350. Furthermore,
the sampling tool 300 may also include one or more sample bottles 302, and in
some embodiments
may also include a fluid communication system 303 (schematically depicted in
Fig. 3A) that may be
adapted to provide fluid communication between the sample coupling 301 and the
one or more sample
bottles 302. In certain illustrative embodiments, the sample bottles 302 may
have a volume of
approximately 0.5 liters so as to provide a sufficient sample size for all
requisite testing, although
sample bottles 302 having either a larger or a smaller volume may also be
used. The fluid
communication system 303 may include various piping system components (not
shown) as may
typically be used in a representative fluid communication system, such as
pipes, tubing, conduits,
flow channels, fittings, valves and the like, which may be adapted to control
a flow of a fluid test
sample from the sample coupling 301 to the one or more sample bottles 302. The
fluid
communication system 303 schematically depicted in Fig. 3A will be described
in further detail with
respect to Figs. 4A and 4B below.
In certain embodiments, the interface system 310 includes a robotic
manipulator arm 331 that
is adapted to support the sampling tool 300 by a handle 307, such as a T-bar
handle and the like, that
is adapted to releasably grasp the sampling tool 300. In some illustrative
embodiments, the
manipulator arm 331 may be operatively mounted on an underwater remotely
operated vehicle (ROV)
330, both of which may be operated by personnel located on surface ship, a
production platform, and
the like, in a typical manner as is well known in the art. The interface
system 310 may also include
belly skid 340 that is removably coupled to the bottom side of the ROV 330,
and which may contain
additional equipment 341 (schematically shown in Figs. 3B-3E) that may be
necessary to operate
and/or control the sampling tool 300, such as pumps, valves, hydraulic and/or
electrical equipment,
containment bottles, purging equipment, and the like. Additionally, in at
least some embodiments, the
sampling tool 300 may be operatively connected to the belly skid 340 by a
plurality of umbilicals 306,
which may include hoses that can be used to flush or purge the fluid
communication system 303,
electrical cables to provide power to the sampling tool 300, and/or hydraulic
or pneumatic lines to
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provide operational control. Furthermore, in those embodiments wherein the
umbilicals 306 include
hoses for flushing or purging the fluid communication system 303, the
umbilicals 306 may be heated,
e.g., with electrical heating coils (see, e.g., Fig. 4A, described below),
and/or wrapped in insulation,
so as to substantially prevent or at least reduce the possibility that any
hydrates that may be present in
the production fluid may freeze as the production fluid travels from the
sample coupling 301 to the
equipment located in the belly skid 340 during the purging process.
Generally, the sampling tool 300 is significantly smaller than the comparable
prior art
sampling tools 100 and 200 described above. For example, in some illustrative
embodiments, the
sampling tool 300 may have length 317 and width 316 dimensions on the order of
approximately
2 feet or less, and a height 309 of about 1-11/2 feet or even smaller,
although other sizes may also be
used. Furthermore, in certain embodiments the sampling tool 300 may weigh
approximately 50-100
pounds or even less, depending on the specific design of the sample coupling
301, the number of
sample bottles 302, the size and extent of the fluid communication system 303,
and the like.
Accordingly, it should be appreciated that the smaller, lighter sampling tool
300 may impose
significantly fewer limitations and/or restrictions on the manipulator arm
331, as compared to, for
example, the prior art system 210 described above.
Figure 3B schematically depicts an elevation view of the interface system 310
of Fig. 3A as
the sampling tool 300 is being positioned adjacent to a side 359 of the subsea
structure 350. The
subsea structure 350 is positioned above the sea floor 390 and has an overall
a height 369 relative to
the sea floor 390 that, depending on the wellhead design, may range from 8-10
feet. Additionally, the
subsea structure 350 may include flow control equipment 354, e.g., a subsea
Christmas tree 354, for
controlling the flow of production fluid out of an oil and gas well 370. As
previously noted, the
subsea structure 350 may include a respective sample coupling 351 having an
axis 351x that is
adapted to engage the sample coupling 301 on the sampling tool 300 so that a
production fluid test
sample may be obtained from the well 370. The subsea structure 350 may also
include a fluid
communication system 353 (schematically depicted in Fig. 3B) that may be
adapted to provide fluid
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communication between the production fluid that is being produced from the
well 370, e.g., from the
Christmas tree 354, thereby allowing a fluid test sample to flow to the sample
coupling 301 on the
sampling tool 300, and thereafter to the one or more sample bottles 302 via
the fluid communication
system 303.
As noted previously, the sampling tool 300 may be substantially smaller than,
for example,
the prior art sampling tool 200 described above. It should therefore be
appreciated that the relatively
smaller size of the sampling tool 300 may thereby facilitate easier handling
and manipulation of the
sampling tool 300 by the manipulator arm 331 during docking operations of the
sample coupling 301
to the sample coupling 351 on the subsea structure 350. For example, in
certain illustrative
embodiments, the reduced size of the sampling tool 300 may enable the
manipulator arm 331 to more
readily align the axis 301x of the sample coupling 301 with the axis 351x of
the sample coupling 351
during the coupling operation.
Figure 3C is a plan view of the illustrative embodiment depicted in Fig. 3B,
and shows the
sampling tool 300 positioned adjacent to the side 359 of the subsea structure
350. The side 359 of the
subsea structure 350 has a width 357 that, in some embodiments, may be on the
order of
approximately 10-12 feet, although the various types of equipment that may be
used in subsea
application may have a variety of different widths 357. As shown in Fig. 3C,
the sampling tool 300
has a width 316 as presented to the side 359 of the subsea structure 350,
which, in some illustrative
embodiments may be approximately 2 feet or even less, as previously described.
Therefore, the width
316 of the sampling tool 300 may be significantly less than the comparable
widths 116 and 216 of the
prior art sampling tools 100 and 200, respectively, as shown in Figs. 1A-1C
and 2A-2C. As a result,
less space may have to be made available along the side 359 of the subsea
structure 350 so as to dock
the sampling tool 300 and to perform the test fluid sampling activities
described herein.
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Moreover, due to the substantially compact design of the sampling tool 300,
the distance 312
between the sample coupling 301 and the sample bottle 303 may be substantially
less than, for
example, the comparable distances 112 and 212 of the prior art sampling
systems 100 and 200,
respectively. As such, the total flow distance that a test sample must flow
through the fluid
communication system 303 in order to reach a respective sample bottle 302 may
be also be
substantially reduced, and in certain illustrative embodiments may be on the
order of only 2-3 feet, or
even less. Furthermore, in at least some embodiments the flow distance may be
less than
approximately 1 foot. As such, the possibility that some amount of fluid
component separation and/or
sample degradation may occur when using the sampling tool 300 to extract test
fluid samples from the
well 370 may be substantially reduced when compared to the prior art sampling
systems 100 and/or
200. Furthermore, as previously noted, in at least some illustrative
embodiments, the sampling tool
300 may also include heating blankets and/or coils (see, e.g., Fig. 4A,
described below) and insulation
so as to prevent the temperature of the sampling tool 300 or any fluids
passing therethrough (e.g.,
production test fluids, system purge fluids, etc.) from dropping below a
predetermined temperature,
such as approximately 70 F. In this way, it may be possible to substantially
reduce the likelihood that
hydrate freezing, sample separation, and/or sample degradation, may
inadvertently occur.
As shown in the illustrative embodiment of Figs. 3B and 3C, the manipulator
arm 331 may be
adapted to extend away from the ROV 330 and manipulate the sampling tool 300
so that the tool 300
can be docked with the subsea structure 350. Accordingly, after the ROV 330
has approached and is
positioned adjacent to the subsea structure 350, the manipulator arm 331
holding the sampling tool
300 may be operated so that sample coupling 301 engages with the sample
coupling 351. The sample
coupling 301 may then be secured in place on the side 359 of the subsea
structure 350, as will be
further described with respect to Fig. 6D below, and the manipulator arm 331
may thereafter release
the handle 307 of the sampling tool 300, as shown in Fig. 3D. In this
configuration, the only
connection between the subsea structure 350 and the ROV 330 may therefore be
by way of the
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umbilicals 306 that connect the sampling tool 300 to the equipment 341 mounted
in the belly skid
340.
As may be appreciated, in those embodiments of the present disclosure wherein
the
manipulator arm 331 is used to move the sampling tool 300 into position so
that the sample coupling
301 engages the sample coupling 351, the production fluid test samples may be
extracted from the
well 370 without having to dock the entire ROV 330 on the side 359 of the
subsea structure 350, as
would be required with the prior art sampling system 110 illustrated in Figs.
1A-1C. Accordingly,
substantially less space immediately adjacent to the subsea structure 350 may
need to be dedicated for
maintaining the position of the ROV 330 during test fluid sampling activities,
as compared to the prior
art systems 110 and 210. Furthermore, since, as noted above, the manipulator
arm 331 does not need
to support the sampling tool 300 throughout the test fluid sampling operation,
the ROV 330 may be
free to move away from a position that is substantially directly in front of
the sample coupling 351
and the side 359 of the subsea structure 350 (as shown in Figs. 3B and 3C). In
certain embodiments,
this may provide adequate space so that other equipment, e.g., another
remotely operated subsea
vehicle (not shown), may be moved into place adjacent to the subsea structure
350, thereby
facilitating other maintenance and/or operating activities on the subsea
structure 350.
Figure 3E schematically depicts another illustrative configuration of the
sampling system 310
illustrated in Figs. 3A-3D. As shown in Fig. 3E, the manipulator arm 331 may
be adapted so that at
least part of the arm 331 can be adjusted at an angle relative to an axis 330x
of the ROV 330, wherein
it should be understood that the axis 330x is substantially aligned with a
direction of forward travel of
the ROV 330. Accordingly, the ROV 330 may therefore be allowed to approach the
subsea structure
350 along a path 360x that is oriented along a plane that may not be
substantially parallel to the axis
351x of the sample coupling 351, i.e., is at a non-zero approach angle 360
relative to the axis 351x.
By comparison, the prior art system 110 must generally approach a subsea
structure, such as the
subsea structure 150, along a path that is substantially parallel to the axis
151x, so that the docking
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probes 105 of the sampling tool 100 can properly engage with the docking
receptacles 155 on the
subsea structure 150. See, e.g., Fig. 1C.
For example, in some illustrative embodiments, the ROV 330 may approach the
subsea
structure 350 such that the axis 330x of the ROV 330 moves substantially along
either a normal (i.e.,
substantially perpendicular) or a non-normal path 360x relative to the side
359 of the subsea structure
350 where the sample coupling 351 is located. In certain embodiments of the
present disclosure, the
approach angle 360 of the ROV 330 relative to the axis 351x that may range,
for example, from
approximately 0 (i.e., wherein the ROV 330 takes a substantially parallel
approach relative to the
axis 351x) to approximately 90 (i.e., wherein the ROV 330 takes a
substantially perpendicular
approach relative to the axis 351x). Furthermore, in at least some
embodiments, once the ROV 330 is
positioned adjacent to the subsea structure 350, at least part of the
manipulator arm 331 may be
adjusted so that the sampling tool 300 is presented to the side 359 with the
axis 301x substantially
parallel to the axis 351x, so that the manipulator arm 331 can properly engage
the sample coupling
301 with the sample coupling 351 on the subsea structure 350.
As thus configured, it may therefore be possible to have adequate access to,
and obtain test
fluid samples from, subsea production equipment, such as the subsea structure
350 and the like,
without having a large space available in front of the side 359 of the subsea
structure 350 so as to
move and/or dock the ROV 330 with the subsea structure 350, such as the
docking space length 139
that is required to maneuver the ROV 130 in the prior art system 110
illustrated in Fig. 1C.
Furthermore, the enhanced ability of the sampling tool 300 to access the
sample coupling 351 on the
subsea structure 350 as depicted in illustrative embodiments of Figs. 3A-3E
may be additionally
advantageous in those situations wherein existing subsea equipment may have
been modified to
facilitate the extraction test fluid samples, but where full and/or
unrestricted access to the sample
coupling 351 from in front of the side 359 (see, e.g., the docking space
length 139 in the prior art
system shown in Fig. 1C) may not be possible.
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Figures 3B-3E schematically depict various illustrative embodiments of the
present disclosure
wherein the sample coupling 351 on the subsea production equipment, e.g., the
subsea structure 350,
is configured such that the axis 351x of the sample coupling 351 is oriented
substantially parallel to a
horizontal reference plane 391. However, as may be appreciated by those having
ordinary skill in the
art, an axis 370x of the well 370 may not always be substantially aligned
along a perfectly vertical
orientation in an actual subsea installation. Accordingly, it should also be
appreciated that the subsea
structure 350 may not always project from the sea floor 390 such that the
various working surfaces of
the subsea structure 350 ¨ e.g., those surfaces where interface equipment
and/or interface connections
may be located, such as the side 359 ¨ are substantially parallel to a
perfectly vertical plane.
Therefore, for purposes of the present disclosure, it should be understood
that the horizontal reference
plane 391 is defined as a plane that, in certain illustrative embodiments, may
be substantially normal
to a respective working surface of the subsea structure 350, e.g., relative to
the side 359, even though
the axis of an actual oil and gas well, such as the axis 370x of the well 370,
may not be substantially
vertical.
As illustrated in Figs. 3B-3E, the manipulator arm 331 may be operated to
bring the
corresponding sample coupling 301 on the sampling tool 300 into position
adjacent to the sample
coupling 351 so that the sample coupling 301 can be moved in a substantially
horizontal direction,
e.g., in a direction that is substantially parallel to the horizontal
reference plane 391, so as to engage
the sample coupling 351. It should be appreciated, however, that typical ROV-
mounted robotic
manipulator arms, such as the manipulator arm 331 may be adapted to have
multiple degrees of
freedom. Accordingly, the sample coupling 301 on the sampling tool 300 may be
moved in
substantially any direction so as to engage a corresponding sample coupling
351 that may be oriented
along virtually any plane.
For example, in some applications, a respective sample coupling, such as the
sample coupling
351 shown in Figs. 3B-3E, may be positioned on a respective piece of subsea
production equipment,
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e.g., a separator vessel, a pipeline end termination (PLET) structure, a flow
module of a subsea
Christmas tree, or a piping manifold such as a pipeline end manifold (PLEM)
structure, and the like,
such that the sample coupling 351 may be oriented in a substantially
vertically upward direction. In
such cases, an ROV, such as the ROV 330 of Figs. 3A-3E, may approach the
subsea production
equipment and/or the sample coupling 351 from above (rather than from the
side, as shown in
Figs. 3B-3E) and a manipulator arm, such as the manipulator arm 331 described
above, may be
operated so as to move the sample coupling 301 on the sampling tool 300
substantially vertically
downward so as to properly engage the sample coupling 351. In other
applications, the sample
coupling 351 may be oriented in a substantially vertically downward direction,
in which case the
ROV 330 may approach the respective subsea production equipment and/or the
sample coupling 351
from below, and the manipulator arm 331 may be operated so as to move the
sampling tool 300 with
the sample coupling 301 thereon in a substantially vertically upward
direction. As may be
appreciated, a sample coupling 351 located on a piece of subsea production
equipment may therefore
be oriented along almost any angle with respective to a horizontal or vertical
plane, substantially
without affecting the ability of the manipulator arm 331 to position and move
a respective sample
coupling 301 along a requisite axis so as to properly engage the sample
coupling 301 with the sample
coupling 351.
Figure 4A schematically depicts a component block diagram of one illustrative
embodiment
of an interface system 410 according to the present disclosure that may
include an interface tool 400,
a manipulator arm 431, and an ROV 430, on which may be mounted a belly skid
440 containing
various support and/or operational equipment 441, as will be further described
below. Additionally,
in at least some embodiments, the interface tool 400 may be operatively
connected to the equipment
441 on belly skid 440 by umbilicals 406, which may include a plurality of
umbilicals 406a-e, as
described in further detail below.
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In the illustrative embodiment of Fig. 4A, the interface tool 400 may be, for
example, a
sampling tool (hereinafter, a sampling tool 400) as previously described with
respect to Figs. 3A-3E
above. In some illustrative embodiments, the sampling tool 400 may include an
interface coupling
401 (e.g., a sample coupling 401) that is adapted to interface with an
interface coupling 451 (e.g., a
sample coupling 451) on a respective piece of subsea equipment (e.g., a subsea
structure; see,
Figs. 3B-3E). Furthermore, in certain embodiments, the sampling tool 400 may
include sample
bottles 402a and 402b, and a fluid communication system 403. The fluid
communication system 403
may be made up of, among other things, a plurality of 2-position/3-way valves
that are adapted to
direct fluid flows between the sample coupling 401, the sample bottles 402a/b,
and various pieces of
the equipment 441 on the ROV/belly skid 430/440, the operation of which will
be further described
below.
In some embodiments, the sample bottles 402a and 402b may each include a
piston 402p that
is adapted to minimize an amount of dead space within the sample bottles
402a/b prior to obtaining
test fluid samples from a piece of subsea production equipment (not shown).
Additionally, the
samples bottles 402a and 402b are connected to and in fluid communication with
metering valves
404a and 404b, respectively, which, in conjunction with the pistons 402p, may
be adapted to facilitate
a regulated flow of a respective test fluid sample into each of the test
bottles 402a/b during a test fluid
sampling operation, as will be further described below. The sampling tool 400
may also include
heating coils 446c in appropriate locations as needed so as to maintain the
sampling tool 400 and/or
various components thereof above a predetermined temperature so as to thereby
prevent hydrate
freezing during the sampling operation.
It should be appreciated that, while two sample bottles 402a and 402b have
been
schematically depicted Fig. 4A, the total number of sample bottles used in any
illustrative
embodiment of the present disclosure may be varied as may be required by the
specific system design
parameters. For example, in certain embodiments, the sampling tool 400 may
only include a single
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sample bottle, e.g., a sample bottle 402a, such as when overall equipment size
restrictions may limit
how many sample bottles can be packaged in the sampling tool 400. In other
illustrative
embodiments, three or more sample bottles, e.g., sample bottles 402a-c, may be
used when a larger
equipment size can be effectively justified, or when specification
requirements dictate additional
samples. As such, for any embodiment disclosed herein that may use more or
fewer than two sample
bottles, the number of pieces of additional equipment, such as 2-position/3-
way valves and metering
valves, may also be commensurately adjusted. However, for illustrative
purposes only, the following
discussion shall be directed to those embodiments having two sample bottles
402a/b.
In one illustrative embodiment, the manipulator arm 431 is operatively mounted
on the ROV
430, and furthermore holds and supports the sampling tool 400. In another
illustrative embodiment,
the ROV 430 also supports a belly skid 440, which may contain various support
and/or operational
equipment 441 as noted above. The equipment 441 may include, among other
things, a methanol
(Me0H) pump 442p and a supply of methanol in an Me0H supply reservoir 442. In
some
embodiments, the methanol may be used for cleaning and/or purging the fluid
communication system
403, any flow lines that provide fluid communication between the sample
coupling 451 and an
isolation valve (not shown) on the subsea production equipment (not shown),
and any umbilicals 406
that may provide fluid communication between the equipment 441 and the fluid
communication
system 403. In certain embodiments, the Me0H supply reservoir 442 may be in
fluid communication
with the 2-position/3-way valve 403c of the fluid communication system 403 of
the sampling tool 400
by way of an umbilical 406a, which may be a suitable member such as a hose and
the like.
Additionally, the system may include a one-way valve 442a that is located
downstream of the Me0H
pump 442p, and that is adapted to prevent a backflow of methanol to the Me0H
pump 442p.
The equipment 441 on the belly skid 440 may further include a purge reservoir
443 that is
adapted to receive and store various fluids that are flushed or purged through
sampling tool 400, such
as, for example, seawater (which may be naturally present), Me0H (as indicated
above), and/or old
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production fluids that may be present in flow lines (not shown) between an
isolation valve (not
shown) on the subsea production equipment (not shown) and the sample coupling
451. In some
embodiments, the purge reservoir may include an internal piston 443p, which,
in conjunction with a
metering valve 443a, may be adapted to facilitate a regulated flow of purge
materials into the purge
reservoir 443, as will be further described below. Furthermore, the purge
reservoir 443 may be in
fluid communication with the 2-position/3-way valve 403c of the fluid
communication system 403 by
way of an umbilical 406b, which may also be a suitable flow member, such as a
hose and the like.
In certain embodiments, the support and/or operational equipment 441 may also
include an
ethylene glycol (MEG) supply reservoir 444, which may be used as in
conjunction with the metering
valves 404a/b for regulating a flow of test fluid samples into the sample
bottles 402a/b during the
sampling operation. Similarly, the MEG supply reservoir 444 may also be used
in conjunction with
the metering valve 443a so as to regulate a flow of purge material into the
purge reservoir 443 during
purging operations. Furthermore, in some embodiments, the MEG supply reservoir
444 may be in
fluid communication with the metering valves 404a/b by way of an umbilical
406c (e.g., a hose), and
in fluid communication with the metering valve 443a by way of the flow line
443b.
Also as shown in Fig. 4A, the equipment 441 on the belly skid 440 may include
a
schematically-depicted valve control unit 445, which may be adapted to control
the positions of the 2-
position/3-way valves 403a-c of the fluid communication system 403 of sampling
tool 400 during the
various sampling and/or purging operations of the sampling system 410. The
valve control unit 445
may be operatively coupled to the valves 403a-c of the fluid communication
system 403 by way of an
umbilical 406d, which may include, among other things, pneumatic, hydraulic,
and/or electrical cables
for providing signals and/or control influences to the 2-position/3-way valves
403a-c. Furthermore, in
those embodiments of the present disclosure where heating coils 446c may be
used to moderate or
control the temperature of the sampling tool 400 and associated equipment, a
schematically-depicted
heating control unit 446 may also be included on the belly skid 440. In
certain embodiments, the
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heating control unit 446 may be operatively coupled to the heating coils 446c
by way of an umbilical
406e, such as, for example, an electrical cable and the like.
In certain illustrative embodiments, the 2-position/3-way valve 403a of the
fluid
communication system 403 may be adapted to provide fluid communication between
the sample
coupling 401 and the 2-position/3-way valve 403b while in a first position,
and to provide fluid
communication between the sample coupling 401 and the sample bottle 402a while
in a second
position. In other embodiments, the 2-position/3-way valve 403b may be adapted
to provide fluid
communication between the 2-position/3-way valve 403a and the 2-position/3-way
valve 403c while
in a first position, and to also provide fluid communication between the 2-
position/3-way valve 403a
(as well as the sample coupling 401) and the sample bottle 402b while in a
second position. In still
other embodiments, the 2-position/3-way valve 403c may be adapted to provide
fluid communication
between the 2-position/3-way valve 403b (as well as the 2-position/3-way valve
403a and the sample
coupling 401) and the Me0H pump 442p while in a first position, and to provide
fluid communication
between the 2-position/3-way valve 403b and the purge reservoir 443 while in a
second position.
Figure 4B is a fluid flow schematic of the system 410 that is schematically
illustrated in
Fig. 4A, and which will hereafter be used to describe one illustrative
operational embodiment of the
system 410.
As a preliminary step to performing a purging and sampling operation on a
piece of subsea
production equipment (see, e.g., the subsea structure 350 of Figs. 3B-3E,
described above) with the
sampling system 410, fluid communication is first established between the
sample coupling 401 on
the sampling system 410 and the sample coupling 451 on the respective piece of
subsea equipment.
See, for example, the subsea structure 350 shown in Figs. 3B-3E, described
above. In certain
illustrative embodiments of the present disclosure, this may be accomplished
by a flow control system
that is adapted to properly position an appropriately designed sealing and
fluid transfer element, such
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as the flow control system 680 and the transfer tube sealing cartridge 656
illustrated in Figs. 6B-6H,
which will be described in further detail below.
After fluid communication has been established between the sample couplings
401 and 451,
an isolation valve (not shown) positioned on or near the subsea production
equipment may then be
opened so that the sampling system 410 is in fluid communication with the
production fluid in the
subsea production equipment. Furthermore, the 2-position/3-way valves 403a-c
of the fluid
communication system 403 are each placed in the first positions described
above, so that fluid
communication is established between the subsea production equipment and the
one-way valve 442a.
In this configuration, flow is permitted from the Me0H pump 442p, through the
one-way valve 442a
and each of the 2-position/3-way valves 403a-c, and to the sample coupling
401, while flow is
blocked to the sample bottle 402a by the 2-position/3-way valve 403a, to the
sample bottle 402b by
the 2-position/3-way valve 403b, and to the purge reservoir 443 by the 2-
position/3-way valve 403c.
Thereafter, in some illustrative embodiments, the Me0H pump 442p is activated
at a
discharge pressure that is higher than the pressure of the subsea equipment so
as to push a flow of
Me0H from the Me0H supply reservoir 442, through the one-way valve 442a,
through the 2-
position/3-way valves 403a-c, through the sample couplings 401 and 405, and
into the subsea
production equipment (not shown). During this initial purge step, any
seawater, solids particles (e.g.,
sand, etc.), and/or residual production fluids that may be present in the
respective flow lines of the
sampling system 410 and/or the subsea production equipment (such as, for
example, the fluid
communication system 353 of Figs. 3B-3E) is substantially cleared from the
flow lines. In certain
embodiments, the Me0H pump 442p is operated until an amount of Me0H equal to
at least one times
(1x) the total volume of the respective valves, fittings, and flow lines on
both the sampling system 410
and the subsea production equipment has been pumped through the system. In
other embodiments, an
amount of Me0H equal to approximately 2-3x the total volume may be pumped to
provide a greater
likelihood that all flow lines are substantially cleared of particulates
and/or residual production fluids.
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The Me0H pump 442p is then shut in so that the pressure in the sampling system
410 is balanced
with the pressure in the subsea production equipment.
As a next step, the 2-position/3-way valve 403c is moved from the first
position to the second
position (as described above) so that fluid communication is established
between the subsea
production equipment and the purge reservoir 443, and so that flow is blocked
to and/or from the
Me0H pump 442p. In this configuration, a flow of fluid from the subsea
production equipment (not
shown) is permitted to flow back through the sample couplings 451 and 401,
through each of the 2-
position/3-way valves 403a-c, and into the purge reservoir 443. In some
embodiments, fluid flow into
the purge reservoir 443 is permitted until an amount of fluid that is at least
equal to lx the total
volume of all flow lines has passed through the sampling system 410, so as to
increase the likelihood
that a substantially "pure" sample of production test fluid can be obtained in
the sample bottles
402a/b. In other embodiments, as much as 2-3x the system volume is allowed to
flow into the purge
reservoir 443.
In certain embodiments, fluid flow into the purge reservoir 443 is regulated
by the piston
443p, the metering valve 443a, and the MEG supply reservoir 444 (see, Fig.
4A). In operation, an
amount of MEG 444a may be present in the purge reservoir 443 behind the piston
443p, i.e., on the
side of the piston 443p opposite of an inlet 443i where the purge material
enters the purge reservoir
443 from the 2-position/3-way valve 403c. As the purge material enters the
purge reservoir 443 at the
inlet 443i, the piston 443p is displaced, and the MEG 444a is forced out of
the purge reservoir 443
through an outlet 443o. The metering valve 443a may be adapted to control the
flow rate and pressure
of the MEG 444a as it flows out of the purge reservoir 443 and into the MEG
supply reservoir 444,
thereby facilitating a controlled influx of purge material into the purge
reservoir 443, and/or a
controlled discharge of MEG 444a out of the purge reservoir 443.
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As noted above, an initial purge step may be performed so as to substantially
remove fluids
and other materials that may be present in the respective flow lines of the
sampling system 410 and a
fluid communication system on the subsea production equipment ¨collectively
referred to hereinafter
as a sampling/purging system circuit (not shown) ¨ from the flow lines. In at
least some embodiments
of the present disclosure, the various several components that make up the
sampling system 410 may
be designed and operated such that any "dead," or "trapped," volumes that are
not fully
purged/flushed from the sampling/purging system circuit during the above-
described purging
operations may be substantially minimized. For example, the sampling system
410 may be adapted
such that at least approximately 70% of the total pre-purged volume of fluids
and other materials
contained with the sampling/purging system circuit may be purged/flushed,
whereas less than
approximately 30% of the total pre-purged volume may remain trapped within the
system after
completion of the purging operations. Accordingly the likelihood that
contaminated test samples may
be acquired during a subsequently performed sampling operation may be
substantially reduced.
After the sampling system 400 has been purged, and a substantially "pure"
sample production
fluid may now be present in the sampling system 400 downstream of the sample
couplings 451 and
401, the 2-position/3-way valve 403a is then moved from the first position to
the second position (as
described above) so that fluid communication may be established between the
subsea production
equipment and the sample bottle 402a and flow is blocked to the 2-position/3-
way valve 403b. In this
configuration, a first test sample of substantially "pure" production fluid
may then be allowed to flow
into the sample bottle 402a. In some embodiments, the flow of the first
production fluid test sample
into the sample bottle 402a is substantially regulated by the piston 402p, the
metering valve 404a, and
the MEG supply reservoir 444, similar to the regulated flow of purge material
into the purge reservoir
443. Prior to obtaining the first test sample, the piston 402p may be
positioned close to an inlet 402i
to the sample bottle 402a so as to minimize an amount of "dead," or "trapped,"
volume within the
sample bottle 402a that may not be flushed or purged during the above-
described purging operations.
For example, in certain embodiments, the relative configurations of the sample
bottle 402a and its
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associated components ¨ such as the 2-position/3-way valve 403a, the metering
valve 404a, the piston
402p, and any inlet/outlet piping system components and the like ¨ may be
adapted such that any
unpurged/unflushed trapped volume that may remain within the sample bottle
402a after completion
of the purging operation may be less than approximately 2% of a total sample-
receiving volume
contained within the sample bottle 402a. See, e.g., the sample-receiving
volume 502v shown in
Figs. 5D-5G and the detailed discussion thereof below.
As schematically shown in Figs. 4A and 4B, an amount of MEG 444b may also be
present in
the sample bottle 402a on the side of the piston 402p opposite of the inlet
402i. As the first test
sample enters the test bottle 402a through the inlet 402i, the piston 402p is
displaced, and the MEG
444b is forced out of the sample bottle 402a through an outlet 402o. As with
the metering valve 443a
on the purge reservoir 443, the metering valve 404a may be adapted to control
the flow rate and
pressure of the MEG 444b as it flows out of the sample bottle 402a and into
the MEG supply reservoir
444 (see, Fig. 4A), until the sample bottle 402a is substantially completely
filled. Furthermore, due to
the minimized amount of unpurged/unflushed trapped volume that may remain
within the sample
bottle 402a as previously described, it should be appreciated that at least
approximately 98% of the
sample-receiving volume within the bottle 402a, such as the sample-receiving
volume 502v shown in
Figs. 5D-5G, may be filled with the first test sample, thus substantially
reducing the likelihood of
sample contamination.
In certain illustrative embodiments disclosed herein, after the test bottle
402a has been
substantially filled with the first production fluid test sample, a second
production fluid test sample
may then be obtained in the sample bottle 402b. As a first step of obtaining a
sample in the sample
bottle 402b, flow to the sample bottle 402a may be blocked by moving the 2-
position/3-way valve
403a from the second position back to the first position, so that fluid
communication is re-established
to the 2-position/3-way valve 403b. Next, the 2-position/3-way valve 403b is
moved from the first
position to the second position (as described above) so that fluid
communication is established
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between the subsea production equipment and the sample bottle 402b and flow is
blocked to the 2-
position/3-way valve 403c. In this configuration, a second test sample of
substantially "pure"
production fluid may then be allowed to flow into the sample bottle 402b. Flow
is regulated into the
sample bottle 402b via the metering valve 404b, piston 402p, and MEG supply
reservoir 444 in
substantially the same fashion as described above with respect to the first
test sample, until the sample
bottle 402b is substantially completely filled.
It should be appreciated that sampling sequence described above, i.e., filling
the sample bottle
402a first and filling the sample bottle 402b second, may be reversed. For
example, after the fluid
communication system 403 has been flushed with Me0H, and a reverse flow of
production fluid been
allowed to flow from the subsea production equipment into the purge reservoir
443 until a
substantially "pure" production fluid sample is present in the fluid
communication system 403, the 2-
position/3-way valve 403b may be operated so as to establish fluid
communication between the
subsea production equipment and the sample bottle 402b. The sample bottle 402b
may then be filled
with a first production fluid test sample in the manner described above.
Thereafter, the 2-position/3-
way valves 403b and 403a may be re-positioned so that the second production
fluid test sample is
obtained in the sample bottle 402a.
In at least some illustrative embodiments, and after both substantially "pure"
production fluid
test samples have been obtained in the sample bottles 402a/b, each of the 2-
position/3-way valves
403a-c may be re-positioned to the first position so as to re-establish fluid
communication between the
subsea production equipment and the one-way valve 442a that is downstream of
the Me0H pump
442p. Furthermore, in this configuration, flow is once again blocked to the
sample bottle 402a by the
2-position/3-way valve 403a, to the sample bottle 402b by the 2-position/3-way
valve 403b, and to
purge reservoir 443 by the 2-position/3-way valve 403c. Then, the Me0H pump
442p is once again
activated so as to push a flow of methanol from the Me0H supply reservoir 442,
through the one-way
valve 442a, through the 2-position/3-way valves 403a-c, through the sample
couplings 401 and 405,
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and back into the subsea production equipment. In this way, the substantially
"pure" production fluid
that may still be present in sampling system 410 and in the flow lines between
the sample coupling
451 and the isolation valve (not shown) on the subsea production equipment can
be removed from the
system so that it does not contaminate the subsea environment when the sample
coupling 401 of the
sampling tool 400 is disconnected from the sample coupling 451 on the subsea
production equipment.
After a sufficient volume of Me0H is pumped through sampling tool 400 and the
flow lines
on the subsea production equipment so as to reduce the likelihood that any
production fluid remains in
either system (e.g., at least lx the total volume of both systems), the
isolation valve on the subsea
production equipment may be closed and the Me0H pump 442p shut in. Thereafter,
fluid
communication between the sample couplings 451 and 401 is discontinued and the
sample coupling
401 is disconnected from the sample coupling 451. In certain illustrative
embodiments disclosed
herein, fluid communication between the sample couplings 451 and 401 may be
discontinued by
properly positioning an appropriately designed sealing and fluid transfer
element, such as the transfer
tube sealing cartridge 656 illustrated in Figs. 6A-6H, which will be described
in further detail below.
Figures 5A-5G depict additional aspects of some illustrative embodiments of an
interface
system 510 that is adapted to interface with subsea production equipment.
Figure 5A is a perspective
view of a portion of an illustrative interface system 510 that may include an
interface tool 500 that is
adapted to be held and supported by a manipulator arm 531, which in turn may
be operatively
mounted on an ROV 530 (see, Fig. 5B). In at least some embodiments, the
interface system 510 may
be, for example, a sampling system (hereinafter, sampling system 510) and the
interface tool 500 may
be a sampling tool (hereinafter, sampling tool 500), as previously described
with respect to Figs. 3A-
3E and Figs. 4A-4B. The sampling tool 500 may have a housing 500h and a handle
507 mounted to
the housing 500h, the handle 507 being adapted to be gripped by an
appropriately designed gripper
532 coupled to the end of the manipulator arm 531. As previously described
with respect to Figs. 3A-
3E above, the manipulator arm 531 may also adapted to move the sampling tool
500 while in a subsea
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environment and position the interface tool 500 adjacent to a piece of subsea
production equipment,
such as a subsea structure and the like (see, e.g., the subsea structure 350
in Figs. 3B-3E).
In certain embodiments, the sampling tool 500 may include an appropriately
designed
interface coupling 501 having an axis 501x that is adapted to be removably
coupled to a
corresponding interface coupling (not shown) on a respective piece of subsea
production equipment.
For example, in some embodiments, such as the illustrative embodiment shown in
Fig. 5A, the
interface coupling 501 may be adapted so that it can be removably coupled to a
standard interface
connection, such as an API 17H type B interface flange and the like. The
interface coupling 501 of
Fig. 5A may include, among other things, a pair of symmetrical flange ring
sections 501f that, when
viewed together, form a substantially annular shape that is adapted to
substantially encompass a
corresponding API 17H type B interface flange. In some embodiments, the two
flange ring sections
501f may be separated at the top by top space 501t, and in certain other
embodiments, separated at the
bottom by a bottom space 501z, wherein a latching mechanism, such as a latch
SOIL, may be
positioned in the bottom space 501z. Furthermore, each flange ring section
501f may also include
catch tab 501q at a top end thereof, the two catch tabs 501q straddling the
top space 501t between the
two flange ring sections 501f. Additional details and an operational discuss
of the interface coupling
501 illustrated in Fig. 5A will be further described with respect to Figs. 6A-
6H below.
It should be appreciated that other standard interface coupling configurations
may also be
used, such as, for example, an API 17H high-torque rotary interface and the
like, as will also be
described with respect to Figs. 7A-7C below. It should be further appreciated
that, depending on the
specific docking and interfacing requirements of the interface tool 500, other
configurations, such as
specially designed interface couplings, may also be used.
In some embodiments of the present disclosure, such as when the interface
system 510 is
adapted to be a sampling system 510 and the interface tool 500 is adapted to
be a sampling tool 500 as
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described with respect to Figs. 3A-3E and Figs. 4A-4B above, the sampling tool
500 may also include
sample bottles 502a and 502b (see, Fig. 5D). Additionally, the interface tool
may also include 2-
position/3-way valves 503a and 503b, that may be used to facilitate a sampling
operation for
obtaining production fluid test samples, as previously described. Furthermore,
the sampling system
510 may also include umbilicals 506, such as fluid transfer hoses, electrical
cables, pneumatic and/or
hydraulic lines and the like, which may be used to operatively couple the
sampling tool 500 to support
and/or operational equipment 541 positioned on a belly skid 540 that is
mounted on the ROV 530
(see, Figs. 5B and 5C).
Figure 5B is a perspective view of another portion of the sampling system 510
of Fig. 5A,
which may also include the ROV 530 with a belly skid 540 mounted to the bottom
side thereof. As
noted above, in some embodiments, the belly skid 540 may include support
and/or operational
equipment 541, which may be operatively connected to the sampling tool 500 via
the umbilicals 506.
Typically, the ROV 530 is linked to a support vessel or production platform
(not shown) by a tether or
umbilical 533, which may include a group of cables that carry electrical
power, video and data signals
back and forth between an operator on the vessel or platform and the ROV 530.
Figure 5C is a perspective view of the belly skid 540, which may be removably
mounted to
the ROV 530 shown in Fig. 5B by a plurality of connection posts 549. The belly
skid 540 may be
made up of a structure 547 having a plurality of equipment bays, such as the
equipment bays 547a and
547b shown in Fig. 5C. As noted above, the belly skid 540 may be adapted to
contain various pieces
of support and/or operational equipment 541 (see, Fig. 5B), such as purge
reservoirs 543, an Me0H
pump (not shown), an electrohydraulic control package (not shown), a heating
control unit (not
shown) and the like. Additionally, the belly skid 540 may also be adapted to
contain Me0H supply
bags 542, which may be used to facilitate system purging operations, and/or
MEG supply bags 544,
which may be used to facilitate the regulation of fluid flows into the purge
reservoirs 543, and/or the
sample bottles 502a/b, as described with respect to Figs. 4A-4B above. In
certain illustrative
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embodiments, the Me0H/MEG supply bags 542/544 may be contained with perforated
containment
baskets 548 so as to expose the supply bags 542 and 544 to the surrounding
subsea hydrostatic
pressure, which, depending on the system design, may thereby balance the
pressure of the system
piping (not shown) and assist with Me0H pumping and/or MEG flow regulation.
Figure 5D is partial exposed view of the interface (e.g., sampling) tool 500
shown in Fig. 5A
from a front perspective and Fig. 5E is a partial exposed view of the sampling
tool 500 from a rear
perspective, wherein the manipulator arm 531 has been removed from both views
for clarity. As
shown in Figs. 5D and 5E, the sampling tool 500 may be includes a suitably
designed interface
coupling 501, which may be adapted to interface with, for example, a standard
interface connection
such as an API 17H type B flange interface. Furthermore, the sampling tool 500
may include sample
bottles 502a/b and 2-position/3-way valve assemblies 503a/b, and the valve
assemblies 503a and 503b
may include valve actuators 508a and 508b, respectively.
In some embodiments, the sample bottles 502a/b may be removably attached to
the housing
500h by, for example, a plurality of fasteners (not shown) at the fastener
holes 562a. Similarly, the 2-
position/3-way valve assemblies 503a/b, including the valve actuators 508a/b,
may also be removably
attached to the housing 500h by a plurality of fasteners (not shown) at the
fastener holes 562b.
The sample bottles 502a/b may each include an internal piston 502p, which is
shown in
Figs. 5D and 5E in an un-stroked position, i.e., before a production fluid
test sample has been
obtained from a sampling point on a respective piece of subsea production
equipment (not shown).
The piston 502p is configured so as to substantially minimize the amount of
trapped volume, or dead
space, within the sample bottles 502a/b prior to obtaining samples, as is
further illustrated in Fig. 5F
and described below. Accordingly, at this stage of system operation, the
sample-receiving volume
502v in the sample bottles 502a/b behind the piston 502p is substantially
filled with MEG, which, as
is described with respect to Figs. 4A and 4B above, may be used in conjunction
with metering valves
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(see, e.g., metering valves 404a/b of Figs. 4A and 4B) to help regulate a flow
of the production fluid
test samples into the sample bottles 502a/b.
It should be further appreciated that the sampling tool 500 may also include,
among other
things, a third 2-position/3-way valve and associated valve actuator (not
shown), such as the 2-
position/3-way valve 403c schematically depicted in Figs. 4A and 4B, that may
be adapted to
facilitate the cleaning and/or purging operations, as previously described.
Figures 5F and 5G are sectional perspective views of the sample bottle 502a,
the 2-position/3-
way valve assembly 503a, and valve actuator 508a of the sampling tool 500
shown in Figs. 5A, 5D
and 5E. In certain embodiments of the present disclosure, the 2-position/3-way
valve assembly 503a
may include, for example, a ball 565 having a right-angled flow channel 565a
passing therethrough, a
valve stem 564 that is attached to and adapted to rotate the ball 565, and a
stem gear 563c that is
attached to and adapted to rotate the valve stem 564 and ball 565. The 2-
position/3-way valve
assembly 503a also includes a flow channel 567 that may provide fluid
communication with a sample
point on a piece of subsea production equipment (not shown), and a flow
channel 566 that may
provide fluid communication with an Me0H/purge system (see, e.g., Me0H pump
442p and purge
reservoir 443 in Figs. 4A and 4B). In at least some embodiments, the 2-
position/3-way valve
assembly 503a may further include a flow channel 502i that provides fluid
communication with the
sample bottle 502a.
As noted above, the sample bottle 502a may include an internal piston 502p
that is adapted to
separate and isolate a production test fluid sample from the supply of MEG
that may be used to help
regulate flow of the test sample into the sample bottle 502a, as previously
described with respect to
Figs. 4A and 4B. Accordingly, the piston 502p may also have a groove 502g for
a seal ring (not
shown), such as an o-ring seal and the like, that may be used so as to
substantially prevent MEG from
leaking into the test sample, or vice versa. In order to minimize the trapped
volume within the sample
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bottle 502a prior to obtaining a test sample, the piston 502p may also include
a stem 502s having a
shape and size that is adapted to substantially fill the inlet flow channel
502i (see, Fig. 5G), thereby
substantially eliminating to a large degree any "dead" volumes within the
sampling system that cannot
be flushed or purged during a purging operation. In certain embodiments, the
sample bottle 502a may
also include a flow channel 502o that is adapted to provide fluid
communication between the sample-
receiving volume 502v of the sample bottle 502a on the back side of the piston
502p (i.e., opposite the
flow channel 502i) to an MEG supply via a metering valve (see, e.g., the MEG
supply reservoir 444
and metering valve 404a of Figs. 4A and 4B), thus regulating flow to the
sample bottle 502a.
In at least some embodiments, the valve actuator 508a may be made up of, among
other
things, a cylindrically shaped gear-toothed rack 563a that is adapted to
engage a pinion gear 563b.
The pinion gear 563b is in turn adapted to engage the stem gear 563c of the 2-
position/3-way valve
assembly 503a. In certain embodiments, the rack 563a is further adapted to be
axially actuated so as
to turn the pinion gear 563b, which correspondingly turns the stem gear 563c,
the valve stem 564, and
the ball 565, thus moving the right-angled flow channel 565a that passes
through the ball 565 from a
first ball position to a second ball position. Furthermore, and as required,
the rack 563a may be
axially actuated in an opposite direction so as to move the right-angled flow
channel 565a from the
second ball position to the first ball position.
The 2-position/3-way valve assembly 503a is adapted so that when the ball 565
is set in the
first ball position, the right-angled flow channel 565a may facilitate fluid
communication between the
above-noted sample point on a respective piece of subsea production equipment
and the above-noted
Me0H/purge stem, via the flow channels 567 and 566, respectively. Furthermore,
in the first ball
position, flow to the sample bottle 502a (via the flow channel 502i) is
blocked by the ball 565. The 2-
position/3-way valve assembly 503a is further adapted so that when the ball
565 is rotated to the
second ball position, the right-angled flow channel 565a may facilitate fluid
communication between
the subsea production equipment and the sample bottle 502a (via the flow
channels 567 and 502i,
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respectively), and flow to or from the Me0H/purge system (via the flow channel
566) is blocked by
the ball 565.
As shown in Fig. 5F, the ball 565 of the 2-position/3-way valve assembly 503a
is in the first
ball position, so that flow is blocked to the flow channel 502i (see, Fig. 5G)
and the sample bottle
502a. In this configuration, the various flow lines through the sampling tool
500 can be cleaned and
purged as described with respect to Figs. 4A and 4Babove. Figure 5F also shows
the piston 502p in
the un-stroked position, so that the stem 502s of the piston 502p
substantially fills the flow channel
502i, and the sample-receiving volume 502v of the sample bottle 502a on the
back side of the piston
502p is substantially filled with MEG.
As shown in Fig. 5G, the valve actuator 508a has been actuated so as axially
move the rack
563a and turn the pinion gear 563b and the stem gear 563c so as to move the
ball 565 of the 2-
position/3-way valve assembly 503a to the second ball position. In this
configuration, fluid
communication may be established between the subsea production equipment and
the sample bottle
502a via the flow channels 567, 565a and 502i. Thereafter, a metering valve
(not shown) downstream
of the flow channel 502o may be opened, and a production fluid test sample may
be pushed into the
sample bottle 502a in a regulated manner via the concerted action of the
piston 502p, the MEG on the
back side of the piston 502p, and the metering valve. Figure 5G also shows the
piston 502p in a fully-
stroked position, i.e., indicating that the piston 502p has been displaced by
a flow of production fluid
into the sample-receiving volume 502v of the sample bottle 502.
It should be appreciated that the various components and operational
configurations of the
sample bottle 502b, the 2-position/3-way valve assembly 503b, and the valve
actuator 508b may be
substantially the same as is described above for the sample bottle 502a, the 2-
position/3-way valve
assembly 503a, and the valve actuator 508a, respectively
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Figures 6A-6H depicts various aspects of some illustrative equipment interface
systems
disclosed herein. Figure 6A is a perspective view of an illustrative interface
tool 600 that is being
positioned by an ROV-mounted manipulator arm (not shown; see, e.g., the
manipulator arm 531
shown in Figs. 5A-5B) adjacent to an interface coupling 651 that is located on
a representative piece
of subsea production equipment 650, such as, for example, a subsea structure
and the like. In some
illustrative embodiments, the interface coupling 651 may be a standard
interface connection, such as
an API 17H type B interface flange, and may therefore include an interface
flange 651f that is adapted
to be removably coupled to a corresponding interface coupling 601 on the
interface tool 600.
Additionally a removable transfer tube sealing cartridge 656 positioned in a
bore 651b of the interface
coupling 651, the configuration and operation of which will be described in
further detail below.
In those embodiments of the present disclosure wherein the interface coupling
651 may be a
standard API 17H type B interface flange, the interface coupling 601 on the
interface tool 600 may
include, among other things, a pair of symmetrical flange ring sections 601f
that, when viewed
together, form a substantially annular shape that is adapted to substantially
encompass the API 17H
type B interface flange. See, e.g., Fig. 5A. In some embodiments, the two
flange ring sections 601f
may be separated at the top by top space 601t, and in certain other
embodiments, separated at the
bottom by a bottom space 601z, wherein a latching mechanism 601L may be
positioned in the bottom
space 601z. Each flange ring section 601f may also include catch tab 601 q at
a top end thereof, the
two catch tabs 601q straddling the top space 601t between the two flange ring
sections 601f.
Furthermore, the interface coupling 601 may have an axis 601x that may be
aligned with an axis 651x
of the interface coupling 651 on the subsea production equipment 651 during a
coupling operation,
which will be further described with respect to Figs. 6D-6E below.
In some illustrative embodiments, the interface tool 600 may also include a
housing 600h and
a handle 607 mounted thereto that is adapted to be gripped by an appropriately
designed gripper
coupled to an ROV-mounted manipulator arm (see, e.g., the gripper 532 and
manipulator arm 531
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shown in Figs. 5A-5B), which may then be used to move and position the
interface tool 600 as noted
above. In those embodiments wherein the interface tool 600 may be, for
example, a sampling tool
that is adapted to obtain production fluid samples from a piece of subsea
production equipment during
operation, the interface tool 600 may also include sample bottles 602a/b, as
well as 2-position/3-way
valve assemblies 603a/b and valve actuators 608a/b, that may be adapted for
directing a flow of a
production fluid test samples into the sample bottles 602a/b. Furthermore, it
should be appreciated
that the interface tool 600 may also include a third 2-position/3-way valve
and associated valve
actuator (not shown), such as the 2-position/3-way valve 403c schematically
depicted in Figs. 4A and
4B, that may be adapted to facilitate the previously described cleaning and/or
purging operations.
Figure 6B shows an illustrative transfer tube sealing cartridge 656
(hereinafter, transfer tube
656) that may be used in conjunction with any of the embodiments disclosed
herein so as seal a bore
65 lb of the interface couplings 651 located on the subsea production
equipment 650, as shown in
Figs. 6D-6E and described below. It should be further appreciated that Fig. 6B
is also representative
of a replacement transfer tube sealing cartridge 656r (hereinafter,
replacement transfer tube 656r), that
may be used to establish fluid communication between the interface couplings
651 on the subsea
production equipment 650 and the interface coupling 601 on the interface tool
600 as shown in
Figs. 6F-6G, and to replace the sealing cartridge 656 positioned in the bore
65 lb, as shown in Fig. 6H
and described below. Furthermore, Fig. 6C is a cross-sectional view of the
transfer tube 656 and
replacement transfer tube 656r shown in Fig. 6B. Accordingly, it should be
understood that, while the
description of Figs. 6B-6C set forth below may only specifically refer to the
transfer tube 656, the
discussion is equally applicable to the replacement transfer tube 656r.
As shown in Figs. 6B and 6C the transfer tube 656 has a first end 656m and a
second end
656n, as well as a plurality of seal rings 656s that are spaced over the
length 656L of the transfer tube
656, each of which seals 656s is positioned in a respective seal ring groove
656t that runs
continuously around the perimeter of the transfer tube 656. In at least some
embodiments, the transfer
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tube 656 may have a substantially cylindrical shape, as illustrated in Figs.
6B and 6C, such that the
seal rings 656s run continuously around the circumference of the transfer tube
656. It should be
appreciated, however, that shapes other than the cylindrical shape depicted in
Figs. 6B and 6C may
also be used for the transfer tube 656, depending on the design and shape of
the bores 651b and/or
601b (see, Figs. 6D-6H) in which the transfer tube 656 may eventually be
positioned, as described
below.
In certain embodiments, each end 656m, 656n of the transfer tube 656 may have
a chamfer or
radius 656x, and in other embodiments, the transfer tube 656 may also have a
flow groove 656g
disposed proximate each end 656m and 656n. In some embodiments, the transfer
tube 656 may also
include flow blocking portions 656z that are positioned between the flow
grooves 656g. Furthermore,
at least some of the seal rings 656s (and associated seal ring grooves 656t)
may be positioned adjacent
to and on either side of each flow groove 656g, such that a pair of seal rings
656s straddles each flow
groove 656g, whereas other seal rings 656s may be positioned so as separate
the flow block portions
656z. In some embodiments, a first pair of intersecting flow passages 656a and
656b may be
positioned in the flow groove 656g proximate the first end 656m and a second
pair of intersecting
flow passages 656c and 656d may be positioned in the flow groove 656g
proximate the second end
656n. Each of the respective flow passages 656a-d extends in a substantially
radial direction across
the circumference of the respective flow grooves 656g, thereby providing fluid
communication
between the respective flow grooves 656g and the respective intersection
points of each respective
first and second pairs of intersecting flow channels 656a/b and 656c/d.
Additionally, the transfer tube 656 may also include an axial flow passage
656e that extends
in a substantially axial direction between the respective intersection point
of the first pair of
intersecting flow passages 656a/b and the respective intersection point of the
second pair of
intersection flow passages 656c/d. Accordingly, fluid communication is thereby
established between
the flow groove 656g proximate the first end 656m and the flow groove 656g
proximate the second
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end 656n by way of the first pair of intersecting flow passages 656a/b, the
axial flow passage 656e,
and the second pair of intersecting flow passages 656c/d.
It should be appreciated that in at least some illustrative embodiments, the
transfer tube 656
may be radially symmetrical with respect to a centerline axis running from the
first end 656m to the
second end 656n and along the axial flow passage 656e. Furthermore, the
transfer tube 656 may also
mirror symmetry with respect to a plane that is perpendicular to the
centerline axis, such that the first
end 656m, including the flow groove 656g and intersecting flow passages 656a/b
adjacent thereto, is
symmetrical the second end 656n, including the flow groove 656g and
intersecting flow passages
656c/d adjacent thereto. Accordingly, in certain embodiments, the transfer
tube 656 is substantially a
reversible transfer tube, so that it can be inserted into a respective bore of
a respective interface
coupling, such as the bore 65 lb of the interface coupling 651 (see, Figs. 6D-
6G) with the first end
656m inserted into the bore first, or with the second end 656n inserted into
the bore first.
Figures 6D-6H illustrate an illustrative flow control system 680 that may be
used in
conjunction with one or more of the equipment interface systems of the present
disclosure so as to
establish fluid communication between an illustrative interface tool, such as
the interface tool 600,
and an illustrative piece of subsea production equipment, such as the subsea
production equipment
650. Furthermore, in some embodiments, the flow control system 680 may be
adapted to establish
fluid communication is such a manner so as to substantially avoid leakage of
production fluid from
the interface tool and/or the subsea production equipment, thereby reducing
the likelihood that
contamination of the surrounding subsea environment may occur.
Figure 6D is a cross-sectional perspective view of the interface tool 600 of
Fig. 6A during an
initial step of removably coupling the interface coupling 601 to the interface
coupling 651 on the
subsea production equipment 650. In the illustrative embodiment shown in Fig.
6D, a flow channel
651a intersects the bore 651b of the interface coupling 651 at an opening
651o. In at least some
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embodiments, the flow channel 651a is adapted to provide fluid communication
between the bore
65 lb and an isolation valve (not shown) on the subsea production equipment
650 that, when opened,
may allow a flow of production fluid to flow from the subsea production
equipment 650, e.g., subsea
structure of an oil and gas well, to the opening 651o, and in certain
configurations (see, e.g., Figs. 6F
and 6G), into to the bore 651b.
As shown in Fig. 6D, a transfer tube 656 may initially be positioned in the
bore 65 lb such
that the second end 656n of the transfer tube 656 is positioned proximate the
face of the interface
flange 651f, and so that neither of the flow grooves 656g on the transfer tube
656 are aligned with
and/or positioned above the opening 6510 of the flow channel 651a, and so that
a flow blocking
portion 656z blocks flow from the opening 651o. In at least some embodiments,
the transfer tube 656
may also be positioned so that a pair seal rings 656s straddles the opening
6510 to the flow channel
651a, thereby substantially sealing the bore 65 lb against any flow of
material passing through the
flow channel 651a.
In some embodiments of the present disclosure, the interface coupling 601 may
include an
interface flow body 601g attached to the front of the housing 600h, and each
flange ring section 601f
may be attached to the front of the interface flow body 601g. The latching
mechanism 601L that is
positioned in the bottom space 601z between the flange rings sections 601f
(see, Fig. 6A) may be
pivotably mounted to the interface flow body 601g by a suitably designed pivot
mechanism (not
shown), such as a pin and the like, in which the latching mechanism 601L may
include a pin hole
601h as shown in Fig. 6D. Furthermore, the interface coupling 601 may also
include a latch locking
mechanism 601k positioned in an opening 601i in the interface flow body 601g.
In some
embodiments, the latch locking mechanism may be a spring- and/or pressure-
assisted mechanism that
may be adapted to pivot the latching mechanism 601L about the pivot mechanism
so as to securely
lock the latching mechanism 601L into place at the bottom of the interface
flange 651f, as will be
further discussed with respect to Fig. 6E below.
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The flow control system 680 may include a front bore 601b in the interface
flow body 601g
that is substantially aligned with and separated from a rear bore 601c by a
plunger stop 601y.
Additionally, the flow control system may also include a housing bore 600b
positioned in the front of
the housing 600h of the interface tool 600, which may be substantially aligned
with the rear bore
601c. In certain embodiments, the flow control system may include a plunger
601p that is adapted to
move in a substantially axial fashion within the bores 601b, 601c, and 600b,
as will be described with
respect to Figs. 6E-6H below. The plunger 601p may have a first end 601m that
is positioned on the
front side of the plunger stop 601y, i.e., on the side where the front bore
601b is located. The plunger
601p may also have a second end 601n that is positioned on the back side of
the plunger stop 601y,
i.e., on the side where the rear bore 601c and housing bore 600b are located.
Furthermore, the first
end 601m of the plunger 601p is separated from the second end 601 by a plunger
shaft 601w that is
adapted to pass through an opening in the plunger stop 601y.
In certain illustrative embodiments, the first end 601m of the plunger 601p
may include a seal
ring 601s, such as an o-ring seal and the like, that is adapted to affect a
substantially leak-proof seal
between the first end 601m and the front bore 601b. Similarly, the second end
601n may also include
a seal ring 601s that is adapted to affect a substantially leak-proof seal
between the second end 601n
and the rear bore 601c, as well as the housing bore 600b. In certain
embodiments, the plunger stop
601y may be adapted to prevent the first end 601m of the plunger 601p from
moving into the rear
bore 601c of the interface flow body 601g, and to prevent the second end 601n
from moving into the
front bore 601b. Additionally, the plunger stop 601y may also include a seal
ring 601s, e.g., an o-ring
seal, that is adapted to affect a substantially leak-proof seal between the
plunger stop 601y and the
plunger shaft 601w. Accordingly, the seal ring 601s of the plunger stop 601y
may substantially
prevent any fluid that may be present within the rear bore 601c and/or the
housing bore 600b, such as,
for example, hydraulic fluid and the like, from passing into the front bore
601b. Likewise, the seal
ring 601s of the plunger stop 601y may also substantially prevent any fluid
that may be present in the
front bore 601b, such as production fluid from the subsea production equipment
650 and/or
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Me0H/purge fluid from the interface tool 611, from passing into the rear bore
601c and/or the
housing bore 600b.
The flow control system 680 may also include flow channels 601d and 601e that
may be in
fluid communication with the rear bore 601c of the interface flow body 601g,
as well as a fluid flow
channel 600d that may be in fluid communication with the housing bore 600b of
the housing 600h. In
some embodiments, the flow channels 601d/e and 600b may also be in fluid
communication with a
hydraulic and/or pneumatic control system (not shown) that may be used to
control the operation of
the various elements that make up the interface tool 600, e.g., 2-position/3-
way valves and/or
metering valves and the like as are described above with respect to Figs. 4A-
4B and Figs. 5D-5G. In
certain embodiments, fluid flow through the flow channels 601d/e and 600d may
be used to control
the position of the plunger 601p inside of the bores 601b, 601c and 600b, as
will be described below
in additional detail. Furthermore, a spring 600s may be positioned inside of
the housing bore 600b,
between the second side 601n of the plunger 601p and a back end 600x of the
bore 600b as shown in
Fig. 6D. In at least some embodiments, the spring 600s may be attached at one
end to the second end
601n of the plunger 601p and at another end to the back end 600x of the bore
600b, and may be
adapted to extend the plunger 601p under certain operational conditions, as
will also be described
below.
In the illustrative configuration shown in Fig. 6D, the plunger 601p is in a
fully retracted
position, such that the first end 601m of the plunger 601p is substantially in
contact with the front side
of the plunger stop 601y. The flow control system 680 may also include a
replacement transfer tube
656r, which may be positioned in the front bore 601b of the interface flow
body 601g, such that a first
end 656m of the replacement transfer tube 656r is proximate a face of the
interface flow body 601g,
and a second end of the replacement transfer tube 656r is substantially in
contact with the first end
601m of the plunger 601p. In some embodiments, the flow control system may
include a flow
channel 601a that intersects the front bore 601b of the interface flow body
601g at an opening 601o.
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In at least some embodiments, the flow channel 601a is adapted to provide
fluid communication
between the front bore 60 lb and any illustrative fluid communication system
of the present disclosure
(see, e.g., the fluid communication systems 303 and 403 of Figs. 3A-3E and 4A,
respectively).
As noted previously with respect to Figs. 6B and 6C above, the replacement
transfer tube
656r is substantially the same size and configuration as the transfer tube
656. During an interface
operation between the interface coupling 601 and the interface coupling 651,
the flow control system
680 is actuated so that the replacement transfer tube 656r may be positioned
to establish fluid
communication between the bore 651b of the interface coupling 651 and the
front bore 601b of the
interface flow body 601g. See, Figs. 6E-6G, described below. In this way,
fluid communication may
also be established between the subsea production equipment 650 and any
illustrative interface system
disclosed herein (see, e.g., the sampling systems 310, 410 and 510 described
above), thereby
facilitating the various interfacing operations previously described, such as,
for example, cleaning
and/or purging, production fluid sample extraction, chemical injection,
hydrate remediation, and the
like. Furthermore, after the flow control system 680 has performed the
interfacing operations
described above, the replacement transfer tube 656r may be positioned so as to
replace the transfer
tube 656 in the bore 651b of the interface coupling 651 (see, Fig. 6H),
thereby re-sealing the interface
coupling 651 with a new and reliable sealing cartridge.
In certain illustrative embodiments, an ROV-mounted manipulator arm, such as
any
manipulator arm disclosed herein (see, e.g., manipulator arms 331 and 531 of
Figs. 3A-3E and
Figs. 5A-5B, respectively) may be used to move the interface tool 600 adjacent
to and slightly above
the interface coupling 651, so that the interface coupling 601 approaches the
interface coupling 651
with the axis 601x tilted at an angle 660 relative to the axis 651x. In some
embodiments, the angle
660 may range from 10 to 45 , depending on the specific design of the
interface flange 651f, the
flange ring sections 601f, the catch tabs 601q, and/or the latch mechanism
601L. Thereafter, the
manipulator arm (not shown) may be used to hook the catch tab 601q at the top
of each flange ring
section 601f on the back side of the interface flange 651f near the top of the
interface coupling 651.
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In at least some embodiments, the manipulator arm may then substantially relax
the weight of the
interface tool 600, thereby allowing the face of the interface flow body 601g
to contact and come to
rest against the face of the interface flange 651f, as shown in Fig. 6E.
In certain embodiments, the spring-assisted latch locking mechanism 601k may
pivot the
pivotably mounted latch mechanism 601L so the latch mechanism 601L is locked
into place at the
bottom of the interface flange 651f, thereby securely coupling the interface
coupling 601 to the
interface coupling 651. Furthermore, as noted above, spring-assisted or
hydraulic pressure may be
applied in the opening 601i so as to augment the operation of the latch
locking mechanism 601k, and
which may be continued throughout subsequent interfacing operations. In at
least some illustrative
embodiments, once the interface couplings 601 and 651 have been securely
coupled and locked in
place, the manipulator arm (not shown) may thereafter release the handle 607,
and the manipulator
arm and/or the ROV (not shown) may be moved away from the interface point, as
described with
respect to Fig. 3D above.
As shown in the illustrative embodiment of Fig. 6E, the interface couplings
651 and 601 may
be adapted so that the bore 651b, i.e., the axis 651x, of the interface
coupling 651 is substantially
aligned with the bores 601b/c, i.e., the axis 601x, of the interface coupling
601. In this configuration,
the replacement transfer tube 656r may be readily pushed from the bore 601b
into the bore 651b so as
to establish fluid communication between the two interface couplings 651 and
601, as described
below. Furthermore, as noted with respect to Figs. 6B and 6C above, both ends
656m and 656n of the
replacement transfer tube 656r may have a chamfer 656x, which may facilitate
easier movement of
the replacement transfer tube 656r across an interface between the interface
couplings 651 and 601 in
the event the bores 65 lb and 60 lb may not be perfectly aligned.
Additionally, in some illustrative
embodiments, one or both of the bores 651b and 601b may also be chamfered at
the faces of the
interface flange 651f and/or the interface flow body 601g, respectively, so as
to further facilitate the
movement of the replacement transfer tube 656r into the bore 651b.
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Figure 6F illustrates the interface tool 600 and flow control system 680 shown
in Figs. 6D and
6E, wherein the plunger 601p has been actuated so as to be moved to a first
position along the co-
axial bores 601b, 601c and 600b. As shown in Fig. 6F, the flow control system
has been actuated to
move the replacement transfer tube 656r past the face of the interface flange
651f and partially into a
front portion of the bore 651b of the interface coupling 651, while the
transfer tube 656 has been
partially moved out of the bore 651b at an opposite end of the interface
coupling 651. In some
illustrative embodiments, the plunger 601p may be moved through the respective
bores 601b/c and
600b by operation of a suitably designed hydraulic or pneumatic system (not
shown), which may be in
fluid communication with the bores 601c and 600b via the flow passages 601d/e
and 600d. The
hydraulic/pneumatic system may be adapted to control a flow of fluid through
the flow passages
601d/e and 600d, and thereby control a flow of fluid into and/or out of the
rear bore 601c and the
housing bore 600b.
In the relative positions of the plunger 601p, the replacement transfer tube
656r, and the
transfer tube 656 shown in Fig. 6F, the plunger 601p has been moved until the
seal ring 601s on the
second end 601n of the plunger 601p is substantially aligned with a point
where the flow passage
601d intersects the rear bore 601c of the interface flow body 601g. While the
plunger 601p is being
moved, the first end 601m may contact and push against the second end 656n of
the replacement
transfer tube 656r so as to move the first end 656m of the replacement
transfer tube 656r partially into
the bore 65 lb of the interface coupling 651. At the same time, the first end
656m of the replacement
transfer tube 656r may simultaneously contact and push against the second end
656n of the transfer
tube 656 so as to move the first end 656m of the transfer tube 656 partially
out of the bore 651b, and
so that the flow blocking portion 656z of the transfer tube 656 no longer
blocks the opening 6510 of
the flow channel 651a, as shown in Fig. 6F.
In some embodiments of the flow control system 680 described herein, the
length of the
plunger 601p may be adapted so that when the plunger 601p is in a first
position as shown in Fig. 6F,
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the flow groove 656g and intersecting flow passages 656c and 656d proximate
the second end 656n of
the replacement transfer tube 656r are substantially aligned with the opening
6010 to the flow channel
601a of the interface flow body 601g. Similarly, the length of the replacement
transfer tube 656r may
also be adapted so that when the flow groove 656g and intersecting flow
passages 656c/d proximate
the second end 656n of the replacement transfer tube 656r are substantially
aligned with the opening
6010 to the flow channel 601a, the flow groove 656g and intersecting flow
passages 656a and 656b
proximate the first end 656m of the replacement transfer tube 656r are
substantially aligned with the
opening 6510 to the flow channel 651a of the interface coupling 651.
As shown in Fig. 6G, fluid communication may thereby be established between
the subsea
production equipment 650 and the interface tool 600 by way of a substantially
continuous flow path
through: 1) the flow channel 651a; 2) the intersecting flow passages 656a/b;
3) the axial flow passage
656e; 4) the intersecting flow passages 656c/d; 5) and the flow channel 601a.
In this configuration,
interfacing operations, such as, cleaning and/or purging, production fluid
sampling, or chemical
injection and the like may be performed. It should be appreciated that, due to
the configuration of
each flow groove 656g relative to the respective intersecting flow passages
656a/b and 656c/d, flow
between the flow channels 651a/601a and the axial flow passage 656e may be
substantially
unrestricted. Accordingly, the replacement transfer tube 656r may be rotated
within the bores 65 lb
and 60 lb to virtually any orientation substantially without affecting fluid
communication between the
subsea production equipment 650 and the interface tool 600.
It should be appreciated that, due to presence of the plurality of seal rings
656s spaced down
the length 656L (see, Figs. 6B-6C) of the replacement transfer tube 656r, each
of which runs
continuously around the perimeter (e.g., circumference) of the transfer tube
656r, the replacement
transfer tube 656r may be moved along the bores 601b and 651b by the flow
control system 680 in
such a way as to substantially avoid any leakage into the surrounding subsea
environment.
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Figure 6H illustrates the interface tool 600 of Figs. 6D-6E after interfacing
operations have
been substantially completed, and wherein the flow control system 680 has been
actuated to move the
plunger 601p to a second position along the co-axial bores 601b, 601c and
600b. As shown in
Fig. 6H, the entire length of the replacement transfer tube 656r has been
moved past the face of the
interface flange 651f. In this configuration, it should be understood that the
replacement transfer tube
656r is adapted to take the place of transfer tube 656 within the bore 65 lb
of the interface coupling
651.
As noted above, the plunger 601p may be moved through the bores 601b and 601c
by
operation of a suitably designed hydraulic or pneumatic system (not shown).
Furthermore, regarding
the relative positions of the plunger 601p, the replacement transfer tube
656r, and the transfer tube
656 shown in Fig. 6H, the plunger 601p has been moved until the second end
601n of the plunger
601p contacts the back side of the plunger stop 601y. In this position, the
seal ring 601s on the
second end 601n of the plunger 601p is properly located relative to a point
where the flow passage
601e intersects the rear bore 601c of the interface flow body 601g so as to
allow for hydraulic
retraction of the plunger 601p. While the plunger 601p is being moved, the
first end 601m may
contact and push against the second end 656n of the replacement transfer tube
656r so as to move the
replacement transfer tube 656r completely into the bore 651b of the interface
coupling 651.
Furthermore, in certain embodiments, the distance between the back side of the
plunger stop 601y and
the face of the interface flow body 601g may be adapted and so that the second
end 656n of the
replacement transfer tube 656r is properly positioned proximate the face of
the interface flange 651f,
as was previously the case with the transfer tube 656 shown in Fig. 6D. At the
same time, the first
end 656m of the replacement transfer tube 656r may simultaneously contact and
push against the
second end 656n of the transfer tube 656 so that transfer tube 656 is
displaced along the bore 651b
and ejected out of the back side of the interface coupling 651, as shown in
Fig. 6H.
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In some illustrative embodiments of the present disclosure, the flow control
system 680 may
position the replacement transfer tube 656r within the bore 65 lb in
substantially the same position
that was previously occupied by the transfer tube 656 as shown in Fig. 6D,
i.e., prior to the flow
control system 680 having been actuated so as to establish fluid communication
between the subsea
production equipment 650 and the interface tool 600 as illustrated in Figs. 6F-
6G and performing the
interfacing operations described above. For example, the replacement transfer
tube 656r may be
positioned in the bore 651b so that neither of the flow grooves 656g on the
replacement transfer tube
656r are aligned with and/or positioned above the opening 6510 of the flow
channel 651a, and so that
a flow blocking portion 656z once again blocks flow from the opening 651o.
Furthermore, in at least
some embodiments, the replacement transfer tube 656r may also be positioned so
that a pair seal rings
656s straddles the opening 6510 to the flow channel 651a, thereby
substantially re-sealing the bore
651b against any flow of material passing through the flow channel 651a.
Moreover, and as
previously noted above, it should also be appreciated that, due the presence
of the plurality of seal
rings 656r disposed along the length 656L (see, Figs. 6B and 6C) of the
replacement transfer tube
656r, this operation may be performed in such a manner as to substantially
reduce the potential that
leakage to the surrounding environment may occur.
In certain illustrative embodiments, the spring 600s may be adapted so that,
in the event
power is lost to the hydraulic/pneumatic system, such that fluid pressure to
the flow channels 601d/e
and 600d is no longer available to actuate the plunger 601p, the spring 600s
may be allowed to fully
extend, thereby moving the plunger 601p to the position illustrated in Fig.
6H. In this way, the
plunger 601p can properly position the replacement transfer tube 656r in the
bore 651b of the
interface coupling 651, thereby sealing both the subsea production equipment
650 and the interface
tool 651, protecting the extracted fluid sample from contamination, and
preventing spillage/leakage to
the surrounding subsea environment. Similarly, the latch locking mechanism
601K may also be
adapted so that if fluid pressure from the hydraulic/pneumatic system to the
opening 601i may be lost,
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the spring-assisted mechanism (not shown) may enable the latch mechanism 601L
to be opened, and
the interface tool 600 to be safely uncoupled.
In the illustrative embodiment shown in Figs. 6E-6H, the interface coupling
651 and the
interface tool 601 are depicted as being oriented along a substantially
horizontal axis. However, as
may be appreciated by one of ordinary skill having the benefit of the
presently disclosed subject
matter, the interface couplings 651 and 601, including the latch mechanism
601L and latch locking
mechanism 601k, may be readily adapted so as to facilitate a coupling
operation wherein the interface
coupling on the subsea production equipment 650 is oriented along a
substantially non-horizontal
axis, including, for example, a substantially vertical axis. Therefore, it
should be appreciated that the
interface systems disclosed herein are not limited to configurations wherein
the interface coupling on
a respective piece of subsea production equipment, such as the interface
couplings 351, 451, 651
and/or 751 (see, Figs. 7A-7C) may be in a substantially horizontal
orientation, due at least in part to
the substantially compact configuration of the interface tools disclosed
herein (e.g., interface tools
300, 400, 500, 600 and/or 700), and the ability of an ROV-mounted manipulator
arm to position the
interface tools at substantially any position and orientation, as previously
described.
Figures 7A-7C are perspective views of a portion of an illustrative interface
system 710 that
depicts some aspects of yet another illustrative interface tool 700 according
to the present disclosure.
As shown in Fig. 7A, the interface system 710 includes an interface tool 700
that is adapted to be held
and supported by a manipulator arm 731, which in turn may be operatively
mounted on an ROV (not
shown), as previously described above. In certain illustrative embodiments, at
least some elements of
the interface tool 700 may be substantially similar to those illustrated and
described with respect to
Figs. 5A-5G above, and will not be addressed herein in any further detail.
The interface tool 700 may include an appropriately designed interface
coupling 701 that is
substantially based on a standard API 17H high-torque rotary interface
configuration, and which is
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adapted to be removably coupled to a corresponding interface coupling 751 on a
respective piece of
subsea production equipment 750 (see, Fig. 7B). The interface coupling 701 may
have an axis 701x
and include, among other things, an interface flow body 701g and a pair of
latching mechanisms 701L
disposed on opposite sides of the interface flow body 701g. As shown in Fig.
7A, a replacement
transfer tube 756r, which may be substantially similar to the replacement
transfer tube 656r illustrated
in Figs. 6B-6G and described above, may be positioned in a bore 701b of the
interface flow body
701g prior to removably coupling the interface coupling 701 on the interface
tool 700 to the interface
coupling 751.
Figure 7B is a close-up perspective view of the interface tool 700 shown in
Fig. 7A as the
interface coupling 701 is being positioned adjacent to and in front of the
interface coupling 751 by the
manipulator arm 731. In some embodiments, the interface coupling 751 may
include a coupling
housing 751h that may be attached to the subsea production equipment 750 by a
plurality of fasteners
751z, such as bolts and the like. Furthermore, the coupling housing 751h may
have a recess 751r with
an axis 751x that is adapted to receive the interface flow body 701g of the
interface coupling 701
during a docking and coupling operation, such that the interface coupling 751
may be considered to
act as the "female" fitting of the interface connection, whereas the interface
coupling 701 may be
considered to act as the "male" fitting.
In certain embodiments, the coupling housing 751h may include a pair of slots
751s disposed
on the inside of the recess 751r and on opposing sides thereof, and which may
be adapted to receive,
during a docking and coupling operation, the two latching mechanisms 701L that
are positioned on
opposite sides of the interface flow body 701g. Furthermore, each slot 751s
may include an
appropriate sized and positioned notch 751n that is adapted to receive a
spring and/or pressure
actuated locking clip 701c on each latching mechanism 701L so as to thereby
securely couple the
interface coupling 701 to the interface coupling 751 in a proper position.
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Figure 7C is a perspective view of the interface tool 700 and the interface
coupling 751 of
Fig. 7B, showing an inside view of the recess 751r of the coupling housing
751h. As shown in
Fig. 7C, a transfer tube 756, which may be substantially similar to the
transfer tube 656 illustrated in
Figs. 6B-6G and described above, may be positioned in a bore 751b of the
interface coupling 751
prior to removably coupling the interface coupling 701 thereto. Accordingly,
once the interface flow
body 701g of the interface coupling 701 has been inserted into the recess 751r
of the interface
coupling 751 and secured in place with locking clips 701c of the latching
mechanisms 701L,
interfacing operations substantially as described with respect to Figs. 6F-6H
may be performed ¨ e.g.,
establishing fluid communication between the subsea production equipment 750
and the interfacing
tool 700, extracting production fluid samples, performing chemical injection
operations, and the like.
Figure 8 schematically illustrates various illustrative interface points for
some illustrative
subsea production equipment where any one of the interface systems described
herein, such as the
interface systems 310, 410, 510, 610 and/or 710, may be utilized to perform
specified interfacing
operations. For example, Fig. 8 schematically illustrates an interface point
851a on a subsea structure
850a that may be positioned above an oil and gas well 870, such as any one of
the subsea structures
described above. Furthermore, the interface point 851a may be an interface
coupling of the present
disclosure that is substantially similar to one of the illustrative interface
couplings 351, 451, 651 or
751, where an illustrative interface system may be coupled so that interfacing
operations such as fluid
sampling and/or cleaning and the like may be performed as described above.
In some embodiments, the subsea wellhead 850a may include a flow module 850b
that may
also, or alternatively, include an interface point 85 lb, such as an
illustrative sample coupling and the
like. In other embodiments, the flow module 850b may be connected by a
flowline jumper 850c to a
pipeline end termination (PLET) 850d, through which a flow of production fluid
870f may flow to
other subsea production equipment, such as separator vessels and/or flow
manifolds and the like. In
certain embodiments, an interface point 851d, which may be any interface
coupling of the present
disclosure, may be located on the PLET 850d, where a respective interface
system as described herein
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may be coupled, and an interfacing operation performed, such as a chemical
injection and/or hydrate
remediation operation and the like.
Figure 9 schematically depicts various interface points for an illustrative
subsea separator
vessel 950. As shown in Fig. 9, the separator vessel 950 may receive a flow of
production fluid 970f,
which may then be separated inside the separator vessel 950 into various zones
made up of different
constituent components, such as, for example, a gas zone 970a and an oil zone
970b. Furthermore,
the production fluid 970f may also include an amount of solids particulate
matter, such as sand and
the like, that also separates out in the bottom of the separator vessel 950 in
a sand zone 970c.
Separated flows of gas 971a and oil 971b from the gas zone 970a and the oil
zone 970b, respectively,
may then be sent to other subsea equipment, or to a production platform at the
ocean surface.
Depending on the operational strategy of a subsea installation in general and
of the separator
vessel 950 in specific, various interface points may be included on the
separator vessel 950 so as to
obtain different type of fluid samples, and/or to perform other types of
interfacing operations as
previously described. For example, in some embodiments, an interface point
951a may be positioned
at an inlet to the separator vessel 950, where the flow of production fluid
970f is received from
another piece of subsea production equipment, e.g., a subsea structure, flow
module, PLET, and the
like. Accordingly, fluid samples may be obtained from the interface point 951a
so as to determine the
quality and characteristics of the fluid flowing into the separator vessel
950. In other embodiments,
an interface point 951b may be positioned at an outlet from the separator
vessel 950, e.g., where a
flow 971b of separated oil from the oil zone 970b is discharged from the
separator vessel, so that fluid
samples may be obtained that can be used for various testing and evaluation
purposes, such as
evaluating the performance of the separator vessel 950. It should be
appreciated that other interface
points may also be positioned on the separator vessel 950, which may be used
for any of the
interfacing operations described herein.
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As may be appreciated by those having ordinary skill in the art, maintenance,
i.e., clean-out,
operations must generally be periodically performed on the separator vessel
950 so as to remove the
sand in the sand zone 970c from the bottom of the separator vessel, as it may
eventually affect the
available volume within the separator vessel 950 as well as the separator's
overall efficiency and
performance. Typically, this clean-out operation requires that the separator
vessel 950 be shut down
and taken out of service so that the vessel can be opened and the sand removed
from the sand zone
970c.
In certain illustrative embodiments, an interface point 951c may be positioned
on the
separator vessel 950 in the sand zone 970c so than an interface system of the
present disclosure may
be used to perform clean-out operation to remove sand from the sand zone 970c
while the separator
vessel 950 is in operation, thereby avoiding the periodic maintenance shut-
down periods described
above. For example, in some embodiments, the interface point 951c may include
any of the interface
couplings disclosed herein, such as the interface coupling 651 illustrated in
Figs. 6A and 6D-6H and
described above. Furthermore, an interface tool of the present disclosure,
such as the interface tool
600 shown in Figs. 6A and 6D-6H, may be coupled to the interface point 951c
(e.g., to the interface
coupling 651), and fluid communication established between the interface tool
(e.g., the interface tool
600) and the separator vessel 950 by way of a suitably designed fluid transfer
element, such as the
transfer tube sealing cartridge 656 shown in Figs. 6B-6H above. Thereafter, a
purging operation may
be performed substantially as described above with respect to the schematic
diagrams illustrated in
Figs. 4A-4B.
For example, in at least some illustrative embodiments, 2-position/3-way
valves on the
interface tool, such as the 2-position/3-way valves 403a-c of the interface
system 410 shown in
Figs. 4A-4B, may be actuated as described above so that methanol from an Me0H
supply reservoir,
such as the Me0H reservoir 442 of Figs. 4A-4B, can be pumped into the sand
zone 970c in the
bottom of the separator vessel 950 via the interface point 951. During this
operation, movement of
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sand in the sand zone 970c may be stimulated by the flow of methanol into the
separator vessel 950.
Next, one of the 2-position/3-way valves, such as the 2-position/3-way valve
403c, may be actuated
so that a flow of fluid from the separator vessel 950 ¨ which may include some
combination of
Me0H, sand from the sand zone 970c, and/or oil from the oil zone 970b ¨ may be
directed to flow
into a purge reservoir, such as the purge reservoir 443 of the interface
system 410. In this way, at
least a portion of the sand may be removed from the sand zone 970c.
Depending on the overall capacity of given interface system such as the
interface system 410,
which may be a function of the size of the Me0H supply reservoir 442 and the
size of the purge
reservoir 443, the Me0H/purging/cleaning steps described above may be
performed until: 1) the
supply of Me0H is exhausted or the capacity of the purge reservoir is reached;
or 2) the sand zone
970c in the separator vessel 950 has been substantially cleared of sand. In
the event the sand zone
970c is not substantially cleared of sand, the performance of the separator
vessel 950 may be re-
evaluated to determine whether or not further immediate purging/cleaning of
the separator vessel 950
may be required, in which case another interface system 410 may be brought
into service so as to
complete the operation. However, it should be appreciated that, due to the on-
line purging/cleaning
capabilities of the various interface systems disclosed herein, i.e., while
the subsea production
equipment is still in operation, the overall efficiency and cost-effectiveness
of a subsea installation
utilizing the disclosed interface systems may be substantially enhanced.
As a result of the above-described subject matter, various systems and methods
for interfacing
with subsea production equipment while the equipment is in operation are
disclosed, which may
improve the cost and efficiency, as well as the environmental safety, of a
subsea production
installation.
The particular embodiments disclosed above are illustrative only, as the
invention may be
modified and practiced in different but equivalent manners apparent to those
skilled in the art having
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the benefit of the teachings herein. For example, the process steps set forth
above may be performed
in a different order. Furthermore, no limitations are intended to the details
of construction or design
herein shown, other than as described in the claims below. It is therefore
evident that the particular
embodiments disclosed above may be altered or modified and all such variations
are considered
within the scope and spirit of the invention. Accordingly, the protection
sought herein is as set forth
in the claims below.
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