U.S. patent application number 15/125903 was filed with the patent office on 2017-01-19 for long offset gas condensate production systems.
The applicant listed for this patent is SHELL OIL COMPANY. Invention is credited to Gaurav BHATNAGAR, James George BROZE, Karthik RAMANATHAN.
Application Number | 20170016309 15/125903 |
Document ID | / |
Family ID | 52780046 |
Filed Date | 2017-01-19 |
United States Patent
Application |
20170016309 |
Kind Code |
A1 |
BROZE; James George ; et
al. |
January 19, 2017 |
LONG OFFSET GAS CONDENSATE PRODUCTION SYSTEMS
Abstract
A long offset gas condensate production system comprising: a
subsea production well; a subsea separator; and a subsea
cooler.
Inventors: |
BROZE; James George;
(Houston, TX) ; BHATNAGAR; Gaurav; (Houston,
TX) ; RAMANATHAN; Karthik; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SHELL OIL COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
52780046 |
Appl. No.: |
15/125903 |
Filed: |
March 13, 2015 |
PCT Filed: |
March 13, 2015 |
PCT NO: |
PCT/US2015/020323 |
371 Date: |
September 13, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61954254 |
Mar 17, 2014 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/36 20130101;
E21B 43/0107 20130101; E21B 43/40 20130101; E21B 36/00 20130101;
E21B 43/017 20130101 |
International
Class: |
E21B 43/01 20060101
E21B043/01; E21B 43/36 20060101 E21B043/36; E21B 43/40 20060101
E21B043/40; E21B 43/017 20060101 E21B043/017 |
Claims
1. A long offset gas condensate production system comprising: one
or more subsea production wells; a subsea separator; and a subsea
cooler.
2. The long offset gas condensate production system of claim 1,
wherein each of the one or more subsea production wells are
connected to a subsea manifold by one or more flowlines.
3. The long offset gas condensate production system of claim 1,
wherein the subsea cooler is connected directly to the one or more
subsea production wells through one or more flowlines.
4. The long offset gas condensate production system of claim 2,
wherein the subsea cooler is connected directly to the subsea
manifold through a flowline.
5. The long offset gas condensate production system of claim 1,
wherein the subsea separator is directly connected to the subsea
cooler through a flowline.
6. The long offset gas condensate production system of claim 1,
wherein the subsea separator is directly connected to the one or
more subsea production wells by one or more flowlines.
7. The long offset gas condensate production system of claim 2,
wherein the subsea separator is directly connected to the subsea
manifold through a flowline.
8. The long offset gas condensate production system of claim 1,
wherein the subsea separator comprises a three-phase separator.
9. The long offset gas condensate production system of claim 1,
further comprising a water injection well.
10. The long offset gas condensate production system of claim 1,
further comprising a subsea pig launcher.
11. The long offset gas condensate production system of claim 1,
further comprising a paraffin injection point.
12. A long offset gas condensate production system comprising: one
or more subsea production wells; a subsea separator; a subsea
compressor; and a subsea cooler.
13. The long offset gas condensate production system of claim 12,
wherein each of the one or more subsea production wells are
connected to a subsea manifold by one or more flowlines.
14. The long offset gas condensate production system of claim 12,
wherein the subsea cooler is connected directly to the one or more
subsea production wells through one or more flowlines.
15. The long offset gas condensate production system of claim 13,
wherein the subsea cooler is connected directly to the subsea
manifold through a flowline.
16. The long offset gas condensate production system of any one of
claims 12-15, wherein the subsea separator is directly connected to
the subsea cooler through a flowline.
17. A method of transporting gas and condensate across a subsea
floor comprising: providing a long offset gas condensate production
system; providing a subsea production stream; cooling the subsea
production stream to form a cooled subsea production stream;
separating the cooled subsea production stream into a produced
water stream and a combined gas and condensate stream; and
transporting the combined gas and condensate stream across the
subsea floor.
18. The method of claim 17, wherein the long offset gas production
system comprises the long offset gas condensate production
system.
19. The method of claim 18, wherein the subsea production stream
comprises a subsea production stream from the one or more subsea
production wells.
20. The method of claim 18, wherein the subsea production stream is
cooled in the subsea cooler.
Description
BACKGROUND
[0001] The present disclosure relates generally to long offset gas
condensate production systems. More specifically, in certain
embodiments the present disclosure relates to long offset gas
condensate production systems capable of transporting gas and
condensate across subsea floors and associated methods.
[0002] During the production, it is often desirable to transport
oil long distances across a seafloor. Using subsea flowlines to
tieback subsea wells to a remote processing facility is an
established method for developing oil and gas fields. The design
and specifications of the subsea flowlines may be driven by the
needs of flow assurance management. Flow assurance management may
include ensuring that the unprocessed well fluid are able to reach
the process facility, arrive at the process facility above critical
temperatures (such as the wax appearance temperature or cloud point
and the hydrate equilibrium temperature), can be made to flow again
after planned or unplanned shutdown (particularly with respect to
clearing hydrate blockages), avoid hydrates, wax, asphaltene,
scale, sand, and other undesirable contents from building up in the
flowline, and can be made to flow at a range of driving pressures,
flowrates, and compositions.
[0003] Typical methods used to achieve the many different demands
of flow assurance may include using highly insulated flowlines,
pipe-in-pipe flowlines, active heating of flowlines, and dual
flowlines. These approaches, however, may have high costs. The oil
industry is continually attempting to increase tieback distances
and at the same time reduce the costs of those tieback systems. The
challenge of having longer tieback distances while at the same time
achieving acceptable costs is proving difficult for the industry,
especially because subsea tiebacks tend to be the approach used for
the smaller reservoirs (which demand lower costs.) Deeper water may
also exacerbate the difficulties of subsea tie backs with the added
disadvantage that it is much easier for hydrates that can block the
flowlines to form in deep water. Flow assurance management may be
especially problematic with fluids with high concentrations of
water.
[0004] It is desirable to develop a method and system of
transporting waxy fluids with significant formation water
production through long offset distances within a single bare
flowline. It is also desirable to develop a method and system of
transporting fluids that mitigate or manage flow assurance risks
and minimize costs.
SUMMARY
[0005] The present disclosure relates generally to long offset gas
condensate production systems. More specifically, in certain
embodiments the present disclosure relates to long offset gas
condensate production systems capable of transporting gas and
condensate across subsea floors and associated methods.
[0006] In one embodiment, the present disclosure provides a long
offset gas condensate production system comprising: one or more
subsea production wells; a subsea cooler, and a subsea
separator.
[0007] In another embodiment, the present disclosure provides a
long offset gas condensate production system comprising: one or
more subsea production wells; a subsea separator; a subsea cooler;
and a subsea compressor.
[0008] In another embodiment, the present disclosure provides a
method of transporting gas and condensate across a subsea floor
comprising: providing a long offset gas condensate production
system; providing a subsea production stream, cooling the subsea
production stream to form a cooled subsea production stream,
separating the cooled subsea production stream into a produced
water stream and a combined gas and condensate stream, and
transporting the combined gas and condensate stream across the
subsea floor.
[0009] The features and advantages of the present disclosure will
be readily apparent to those skilled in the art. While numerous
changes may be made by those skilled in the art, such changes are
within the spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] So that the above recited features and advantages of the
disclosure may be understood in detail, a more particular
description of the disclosure, briefly summarized above, may be had
by reference to the embodiments thereof that are illustrated in the
appended drawings. It is to be noted, however, that the appended
drawings illustrate only typical embodiments of this disclosure and
are, therefore, not to be considered limiting of its scope. The
figures are not necessarily to scale, and certain features and
certain views of the figures may be shown exaggerated in scale or
in schematic in the interest of clarity and conciseness.
[0011] FIG. 1 is an illustration of a long offset condensate
production system in accordance with an embodiment of the present
disclosure.
[0012] FIG. 2 is an illustration of a long offset gas condensate
production system in accordance with an embodiment of the present
disclosure.
DETAILED DESCRIPTION
[0013] The present disclosure relates generally to long offset gas
condensate production systems. More specifically, in certain
embodiments the present disclosure relates to long offset gas
condensate production systems capable of transporting gas and
condensate across subsea floors and associated methods.
[0014] The description that follows includes exemplary apparatuses,
methods, techniques, and/or instruction sequences that embody
techniques of the inventive subject matter. However, it is
understood that the described embodiments may be practiced without
these specific details.
[0015] There may be several potential advantages of the systems and
methods discussed herein. One potential advantage is that the
methods and systems discussed herein may permit the transport of
waxy fluids with significant amounts of formation water through
long offset distances within single bare flowlines. Another
potential advantage is that the methods and system discussed herein
may manage or mitigate the flow assurance risks of transporting
fluids through long offset distances.
[0016] Referring now to FIG. 1, FIG. 1 illustrates a long offset
gas condensate production system 100 comprising a subsea production
well 110; a subsea cooler 120; and a subsea separator 130.
[0017] In certain embodiments, subsea production well 110 may
comprise a single subsea production well 110 or multiple subsea
production wells 110. For example, in certain embodiments long
offset gas condensate production system 100 may comprise one, two,
three, four, five, or more subsea production wells 110. In certain
embodiments, each of the multiple subsea production wells 110 may
be connected to a subsea manifold 111 by one or more flowlines 112.
In certain embodiments, subsea production well 110 may comprise a
gas condensate well. In certain embodiments, subsea manifold 111
may comprise any conventional subsea manifold.
[0018] In certain embodiments, flowlines 112 may comprise any
conventional subsea flowline. In certain embodiments, flowlines 112
may comprise non-CRA materials
[0019] In certain embodiments, subsea cooler 120 may comprise any
conventional subsea cooler. In certain embodiments, subsea cooler
120 may be used in several different configurations to achieve
different flow assurance benefits. For example, as shown in FIG. 1,
subsea cooler 120 may be directly connected to a flowline 113 from
subsea manifold 111. Alternatively, not illustrated in FIG. 1,
subsea cooler 120 may be connected to a well stream directly from a
subsea production well. In these configurations, the subsea cooler
may be used to cool a subsea production stream before it enters
subsea separator 130.
[0020] The use of these configurations may depend on the pressure,
temperature and water-gas ratio of the fluid in flowlines 112
and/or 113. One benefit of these configurations is that at least a
portion of the saturated water in the fluid in flowlines 112 and/or
113 may be removed by lowering the temperature of the fluid. This
in turn may lead to lower total water amounts in subsequent streams
resulting in much lower hydrate inhibitor dosages. In addition,
less water in the fluid may also mitigate corrosion issues in
fields with high CO.sub.2 content.
[0021] In other embodiments, not illustrated in FIG. 1, long offset
gas condensate system may not comprise a subsea cooler before
subsea separator. In certain embodiments, not illustrated in FIG.
1, long offset gas condensate system may comprise a subsea cooler
without subsea separator and/or a compressor.
[0022] In certain embodiments, as shown in FIG. 1, flowline 121
from subsea cooler 120 may be connected directly to subsea
separator 130. Alternatively, not illustrated in FIG. 1, a flowline
from manifold 111 or one or more individual wells 110 may be
connected directly to subsea separator 120.
[0023] In certain embodiments the subsea separator 130 may be a
three-phase separator. In certain embodiments subsea separator 130
may be a two-phase separator. In certain embodiments, subsea
separator 130 may be used capable of separating a production stream
into a gas stream, a condensate stream, and a water stream. In
certain embodiments, subsea separator 130 may comprise a gas
flowline 132, a condensate flowline 133, and a water flowline
134.
[0024] In certain embodiments, the water stream separated from the
production stream within subsea separator 130 may be disposed of or
injected into a reservoir. In certain embodiments, water flowline
134 may be connected to a subsea water injection well 140. In
certain embodiments, pump 135 may facilitate the flow of the water
stream within water flowline 134 water from subsea separation 130
to subsea water injection well 140.
[0025] In certain embodiments, gas flowline 132 and condensate
flowline 133 may combined to form a combined gas and condensate
flowline 136. In certain embodiments, combined gas and condensate
flowline 136 may comprise a DLC coated flowline. In certain
embodiments, combined gas and condensate flowline 136 may comprise
an electrically heated flowline. In certain embodiments, combined
gas and condensate flowline 136 may be capable of transporting gas
and condensate across the subsea floor to an onshore location.
[0026] In certain embodiments, long offset gas condensate
production system 100 may comprise subsea pig launcher 150. In
certain embodiments, subsea pig launcher 150 may be capable of
launching pigs within combined gas and condensate flowline 136.
[0027] In certain embodiments, long offset gas condensate
production system 100 may comprise paraffin inhibitor injection
point 161. In certain embodiments, paraffin inhibitor injection
point 161 may be located in combined gas and condensate flowline
136. In certain embodiments, a paraffin inhibitor may be injected
into the subsea system at paraffin injection point 161 to mitigate
wax deposition in flowlines.
[0028] Referring now to FIG. 2, long offset gas condensate
production system 200 may comprise any combination of features
discussed above with respect to long offset gas condensate
production system 100. In certain embodiments, long offset gas
condensate production system 200 may comprise a subsea production
well 210; a subsea cooler 220; a subsea separator 230, and a subsea
water injection well 240.
[0029] In certain embodiments, subsea production well 210 may
comprise any combination of features described above with respect
to subsea production well 210. As can be seen in FIG. 2, in certain
embodiments subsea production system 200 may comprise multiple
wells 210 connected to a manifold 211 by flowlines 213.
[0030] In certain embodiments, subsea cooler 220 may comprise any
combination of features discussed above with respect to subsea
cooler 120. As can be seeing in FIG. 2, in certain embodiments,
subsea cooler 220 may be fluidly connected to subsea manifold 111
by a flowline 212.
[0031] In certain embodiments, subsea separator 230 may comprise
any combination of features discussed above with respect to subsea
separator 130. As can be seen in FIG. 2, in certain embodiments,
subsea separator 230 may be connected to a subsea water injection
well 240 by a water flowline 234. In certain embodiments, subsea
separator 230 may also comprise a gas flowline 232 and a condensate
flowline 233. In certain embodiments, gas flowline 232 and
condensate flowline 233 may be combined to form a combined gas and
condensate flowline 236
[0032] In certain embodiments, a subsea compressor 250 may be
connected to combined gas and condensate flowline 236. In certain
embodiments, subsea compressor 250 may be either dry gas or wet gas
compressor. In certain embodiments, subsea compressor 250 may
comprise a recycle stream 251. In certain embodiments, subsea
compressor 250 may comprise a subsea cooler 252. In certain
embodiments, the subsea cooler may be used to cool the combined gas
and condensate flowline 236, recycle stream 251, or compressed gas
and condensate flowline 237.
[0033] In certain embodiments, compressed gas and condensate
flowline 237 may comprise a DLC coated flowline. In certain
embodiments, compressed gas and condensate flowline 237 may
comprise an electrically heated flowline. In certain embodiments,
compressed gas and condensate flowline 237 may be capable of
transporting gas and condensate across the subsea floor to an
onshore location.
[0034] In certain embodiments, long offset gas condensate
production system 200 may comprise subsea pig launcher 260. In
certain embodiments, subsea pig launcher 260 may be capable of
launching pigs within compressed gas and condensate flowline
237.
[0035] In certain embodiments, long offset gas condensate
production system 200 may comprise paraffin inhibitor injection
point 261. In certain embodiments, paraffin inhibitor injection
point 261 may be located in compressed gas and condensate flowline
237. In certain embodiments, a paraffin inhibitor may be injected
into the subsea system at paraffin injection point 261 to mitigate
wax deposition in flowlines.
[0036] In certain embodiments, the present disclosure provides a
method of transporting gas and condensate across a subsea floor. In
certain embodiments, the method may comprise: providing a long
offset gas condensate production system; providing a subsea
production stream, cooling the subsea product stream to form a
cooled subsea production stream, separating the cooled subsea
production stream into a produced water stream and a combined gas
and condensate stream and, and transporting the gas and condensate
stream across the subsea floor. In certain embodiments, the long
offset gas condensate production system may comprise any
combination of features discussed above with respect to long offset
gas condensate production systems 100 and 200.
[0037] While the embodiments are described with reference to
various implementations and exploitations, it will be understood
that these embodiments are illustrative and that the scope of the
inventive subject matter is not limited to them. Many variations,
modifications, additions and improvements are possible.
[0038] Plural instances may be provided for components, operations
or structures described herein as a single instance. In general,
structures and functionality presented as separate components in
the exemplary configurations may be implemented as a combined
structure or component. Similarly, structures and functionality
presented as a single component may be implemented as separate
components. These and other variations, modifications, additions,
and improvements may fall within the scope of the inventive subject
matter.
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