US20160130918A1 - Jumper line configurations for hydrate inhibition - Google Patents
Jumper line configurations for hydrate inhibition Download PDFInfo
- Publication number
- US20160130918A1 US20160130918A1 US14/895,575 US201414895575A US2016130918A1 US 20160130918 A1 US20160130918 A1 US 20160130918A1 US 201414895575 A US201414895575 A US 201414895575A US 2016130918 A1 US2016130918 A1 US 2016130918A1
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- Prior art keywords
- jumper line
- subsea
- jumper
- subsea device
- elbows
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
- E21B43/013—Connecting a production flow line to an underwater well head
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
Definitions
- the present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- the extraction of hydrocarbons from deepwater oil and gas reservoirs requires the transportation of a production stream from the reservoirs to facilities for processing. Water, along with oil and gas, may be included in these production streams. During transportation, if the temperature of the production stream is low and the pressure is high, the system can enter the hydrate region where gas hydrates form. Gas hydrates are solids and behave like ice and, if formed in large quantities, may plug the pipeline. Hydrates may also plug or cause malfunction of other units, such as valves, chokes, separators, and heat exchangers.
- Jumper lines are flowlines that are commonly used to connected subsea units together. Conventional jumper line configurations often incorporate a valley and a bend in order to provide flexibility to the jumper line. During shut ins, liquids may settle and segregate in the lower middle section of these jumper lines. During shut in restart cycles, these jumper lines are often at risk of forming gas hydrates.
- the present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- the present disclosure provides a jumper line system comprising: a first subsea device; a second subsea device; and a jumper line providing fluid communication between the first subsea device and the second subsea device, wherein the jumper line does not comprise a valley.
- the present disclosure provides a method of transporting hydrocarbons from a subsea well comprising: providing a subsea well; providing a manifold; connecting the subsea well to the manifold via a jumper line, wherein the jumper line does not comprise a valley; and flowing hydrocarbons from the subsea well to the manifold via the jumper line.
- the present disclosure provides a method of connecting two subsea devices comprising: providing a first subsea device; providing a second subsea device; providing a jumper line, wherein the jumper line comprises a first end section and a second end section and does not comprise a valley; connecting the first end section of the jumper line to the first subsea device; and connecting the second end section of the jumper line to the second subsea device.
- FIG. 1 is a side view illustration of a typical M-shaped jumper line geometry.
- FIG. 2 is a side view illustration of a jumper line geometry in accordance with an embodiment of the present disclosure.
- FIGS. 3A and 3B are top and side view illustrations of a jumper line geometry in accordance with an embodiment of the present disclosure.
- the present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- FIG. 1 illustrates a conventional jumper line configuration 100 .
- conventional jumper line configuration 100 may comprise a first subsea device 110 , a second subsea device 120 , and a jumper line 130 .
- Jumper line 130 may comprise one or more straight sections 131 , one or more elbows 132 , one or more peaks 133 , one or more valleys 134 , and one or more end sections 135 .
- the one or more peaks 133 are comprised of one or more elbows 132 .
- the one or more peaks 133 define the one or more valleys 133 .
- the valleys 134 and elbows 132 may provide flexibility to the jumper line.
- liquids may settle and segregate in the valleys 134 , as well as end sections 135 , of the jumper lines 130 thus increasing the risk of hydrates forming in the valleys 134 during shut in-restart cycles.
- the present disclosure provides jumper line configurations that aid in the prevention of hydrate blockages. Examples of such jumper line configurations are illustrated in FIG. 2 and FIGS. 3A and 3B .
- FIG. 2 illustrates jumper line configuration 200 .
- jumper line configuration 200 may comprise a first subsea device 210 , a second subsea device, and a jumper line 230 .
- first subsea device 210 and second subsea device 220 can comprise any type subsea equipment.
- suitable subsea devices include subsea Christmas trees, well heads, and manifolds.
- first subsea device 210 may comprise a well head.
- second subsea device 210 may comprise a manifold.
- Jumper line 230 may be constructed out of any material suitable for use as a jumper line. Examples of suitable materials include carbon steel, allows of titanium and chrome, flexible pipes, or composite materials.
- Jumper line 230 may comprise one or more straight sections 231 , one or more elbows 232 , peak 233 , and one or more end sections 235 .
- the one or more straight sections 231 may be horizontal or vertical along a primary axis.
- the primary axis is defined as the horizontal line that is in line with the overall flow of hydrocarbons from first subsea device 210 to second subsea device 220 .
- the one or more straight sections 231 may be inclined from 0 degrees to 90 degrees from the primary axis.
- the one or more straight sections 231 may be straight along the primary axis while incorporating a number of straight sections and elbows along a perpendicular axis.
- peak 233 is comprised of the one or more elbows 232 .
- the one or more elbows 232 may comprise one or more connectors.
- jumper line configuration 200 does not comprise a valley defined by one or more peaks 233 . Rather, in certain embodiments, the maximum elevation of jumper line configuration 200 occurs at peak 233 , and no local maximum elevation occurs on either side of peak 233 .
- jumper line 230 may further comprise one or more injection ports 236 wherein a hydrate inhibitor may be injected into the jumper line 230 .
- the one or more injection ports 236 may be disposed on the one or more end sections 235 .
- jumper line 230 may further comprises one or more valves 237 that allow the end sections of jumper line 230 to be drained or provide means to move gas from the first subsea device 210 to the second subsea device 220 .
- the one or more valves 237 may be disposed on the one or more end sections 235 above the one or more injection ports 236 .
- the one or more valves 237 may be disposed on the one or more ends sections 235 below the one or more injection ports 236 .
- the one or more valves 237 may be tree valves.
- gas may segregate into the one or more peaks 233 of the jumper lines 230 and water may segregate into the one or more end sections 235 of jumper lines 230 .
- the one or more valves 237 may be manipulated to drain the water from the one or more end sections 235 , thus lowering the risk of forming hydrates when the lines are restarted.
- FIG. 3A illustrates a side view of jumper line configuration 300
- FIG. 3B illustrates a top view of jumper line configuration 300
- jumper line configuration 300 may comprise a first subsea device 310 , a second subsea device 320 , and a jumper line 330 .
- Jumper line 330 may comprise straight section 331 , one or more elbows 332 , peak 333 , and one or more end section 335 .
- Jumper line 330 may further comprise one or more injection ports 336 and one or more valves 337 .
- straight section 331 may be inclined with respect to the primary axis.
- peak 333 is comprised of a single elbow 332 . Similar to jumper line configuration 200 , jumper line configuration 300 does not comprise a valley defined by one or more peaks 333 . Rather, in certain embodiments, the maximum elevation of jumper line configuration 300 occurs at peak 333 , and no local maximum elevation occurs on either side of peak 333 .
- jumper line 330 may comprise one or more secondary elbows 338 . The one or more secondary elbows 338 may be arranged in a configuration that does not result in the formation of a valley in jumper line 330 along the primary axis.
- the one or more secondary elbows 338 may be in an axis perpendicular to the primary axis and produce one or more bends 339 in jumper line 330 in the same plane as the flow within the jumper line 330 .
- the one or more secondary elbows 338 may provide flexibility to the jumper line configuration 300 .
- the jumper line configuration discussed herein may have several advantages.
- One advantage is that the jumper line configurations discussed herein are able to provide bends without having valleys, thus increasing the flexibly while limiting the formation of hydrates.
- Another advantage is that using the jumper line geometry discussed herein, gas may segregate into the higher part so of the jumper line and water may segregate in the low sections, thus allowing water to be drained during shut ins.
Abstract
A jumper line system comprising: a first subsea device; a second subsea device; and a jumper line providing fluid communication between the first subsea device and the second subsea device, wherein the jumper line does not comprise a valley.
Description
- This application claims the benefit of U.S. Provisional Application No. 61/831,911, filed Jun. 6, 2013, which is incorporated herein by reference.
- The present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- The extraction of hydrocarbons from deepwater oil and gas reservoirs requires the transportation of a production stream from the reservoirs to facilities for processing. Water, along with oil and gas, may be included in these production streams. During transportation, if the temperature of the production stream is low and the pressure is high, the system can enter the hydrate region where gas hydrates form. Gas hydrates are solids and behave like ice and, if formed in large quantities, may plug the pipeline. Hydrates may also plug or cause malfunction of other units, such as valves, chokes, separators, and heat exchangers.
- Jumper lines are flowlines that are commonly used to connected subsea units together. Conventional jumper line configurations often incorporate a valley and a bend in order to provide flexibility to the jumper line. During shut ins, liquids may settle and segregate in the lower middle section of these jumper lines. During shut in restart cycles, these jumper lines are often at risk of forming gas hydrates.
- It is desirable to develop a jumper line configuration that aids in preventing the formation of gas hydrates.
- The present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- In one embodiment, the present disclosure provides a jumper line system comprising: a first subsea device; a second subsea device; and a jumper line providing fluid communication between the first subsea device and the second subsea device, wherein the jumper line does not comprise a valley.
- In another embodiment, the present disclosure provides a method of transporting hydrocarbons from a subsea well comprising: providing a subsea well; providing a manifold; connecting the subsea well to the manifold via a jumper line, wherein the jumper line does not comprise a valley; and flowing hydrocarbons from the subsea well to the manifold via the jumper line.
- In another embodiment, the present disclosure provides a method of connecting two subsea devices comprising: providing a first subsea device; providing a second subsea device; providing a jumper line, wherein the jumper line comprises a first end section and a second end section and does not comprise a valley; connecting the first end section of the jumper line to the first subsea device; and connecting the second end section of the jumper line to the second subsea device.
- 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
- 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.
-
FIG. 1 is a side view illustration of a typical M-shaped jumper line geometry. -
FIG. 2 is a side view illustration of a jumper line geometry in accordance with an embodiment of the present disclosure. -
FIGS. 3A and 3B are top and side view illustrations of a jumper line geometry in accordance with an embodiment of the present disclosure. - The present disclosure relates generally to jumper line configurations. More specifically, in certain embodiments the present disclosure relates jumper line configurations for hydrate inhibition and associated methods.
- The description that follows includes exemplary apparatuses, methods, techniques, and 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.
- Referring now to
FIG. 1 ,FIG. 1 illustrates a conventionaljumper line configuration 100. As can be seen inFIG. 1 , conventionaljumper line configuration 100 may comprise afirst subsea device 110, asecond subsea device 120, and ajumper line 130.Jumper line 130 may comprise one or morestraight sections 131, one ormore elbows 132, one ormore peaks 133, one ormore valleys 134, and one ormore end sections 135. In certain embodiments, the one ormore peaks 133 are comprised of one ormore elbows 132. In certain embodiments, the one ormore peaks 133 define the one ormore valleys 133. - In this conventional configuration, the
valleys 134 andelbows 132 may provide flexibility to the jumper line. However, during shut ins, liquids may settle and segregate in thevalleys 134, as well asend sections 135, of thejumper lines 130 thus increasing the risk of hydrates forming in thevalleys 134 during shut in-restart cycles. - In certain embodiments, the present disclosure provides jumper line configurations that aid in the prevention of hydrate blockages. Examples of such jumper line configurations are illustrated in
FIG. 2 andFIGS. 3A and 3B . - Referring now to
FIG. 2 ,FIG. 2 illustratesjumper line configuration 200. As can be seen inFIG. 2 ,jumper line configuration 200 may comprise afirst subsea device 210, a second subsea device, and ajumper line 230. - In certain embodiments,
first subsea device 210 andsecond subsea device 220 can comprise any type subsea equipment. Examples of suitable subsea devices include subsea Christmas trees, well heads, and manifolds. In certain embodiments,first subsea device 210 may comprise a well head. In certain embodiments,second subsea device 210 may comprise a manifold. - Jumper
line 230 may be constructed out of any material suitable for use as a jumper line. Examples of suitable materials include carbon steel, allows of titanium and chrome, flexible pipes, or composite materials. -
Jumper line 230 may comprise one or morestraight sections 231, one ormore elbows 232,peak 233, and one ormore end sections 235. In certain embodiments, the one or morestraight sections 231 may be horizontal or vertical along a primary axis. In certain embodiments, the primary axis is defined as the horizontal line that is in line with the overall flow of hydrocarbons fromfirst subsea device 210 tosecond subsea device 220. In certain embodiments, the one or morestraight sections 231 may be inclined from 0 degrees to 90 degrees from the primary axis. In certain embodiments, the one or morestraight sections 231 may be straight along the primary axis while incorporating a number of straight sections and elbows along a perpendicular axis. In certain embodiments,peak 233 is comprised of the one ormore elbows 232. In certain embodiments, the one ormore elbows 232 may comprise one or more connectors. Unlikejumper line configuration 100 ofFIG. 1 ,jumper line configuration 200 does not comprise a valley defined by one ormore peaks 233. Rather, in certain embodiments, the maximum elevation ofjumper line configuration 200 occurs atpeak 233, and no local maximum elevation occurs on either side ofpeak 233. - In certain embodiments,
jumper line 230 may further comprise one ormore injection ports 236 wherein a hydrate inhibitor may be injected into thejumper line 230. In certain embodiments, the one ormore injection ports 236 may be disposed on the one ormore end sections 235. - In certain embodiments,
jumper line 230 may further comprises one ormore valves 237 that allow the end sections ofjumper line 230 to be drained or provide means to move gas from the firstsubsea device 210 to the secondsubsea device 220. In certain embodiments, the one ormore valves 237 may be disposed on the one ormore end sections 235 above the one ormore injection ports 236. In other embodiments, the one ormore valves 237 may be disposed on the one or more endssections 235 below the one ormore injection ports 236. In certain embodiments, the one ormore valves 237 may be tree valves. - In certain embodiments, during shut ins, gas may segregate into the one or
more peaks 233 of thejumper lines 230 and water may segregate into the one ormore end sections 235 of jumper lines 230. The one ormore valves 237 may be manipulated to drain the water from the one ormore end sections 235, thus lowering the risk of forming hydrates when the lines are restarted. - Referring now to
FIG. 3 ,FIG. 3A illustrates a side view ofjumper line configuration 300 andFIG. 3B illustrates a top view ofjumper line configuration 300. As can be seen inFIG. 3A ,jumper line configuration 300 may comprise a firstsubsea device 310, a secondsubsea device 320, and ajumper line 330.Jumper line 330 may comprisestraight section 331, one ormore elbows 332,peak 333, and one ormore end section 335.Jumper line 330 may further comprise one ormore injection ports 336 and one ormore valves 337. - In certain embodiments,
straight section 331 may be inclined with respect to the primary axis. InFIG. 3 , peak 333 is comprised of asingle elbow 332. Similar tojumper line configuration 200,jumper line configuration 300 does not comprise a valley defined by one ormore peaks 333. Rather, in certain embodiments, the maximum elevation ofjumper line configuration 300 occurs atpeak 333, and no local maximum elevation occurs on either side ofpeak 333. However, as shown inFIG. 3B ,jumper line 330 may comprise one or moresecondary elbows 338. The one or moresecondary elbows 338 may be arranged in a configuration that does not result in the formation of a valley injumper line 330 along the primary axis. For example, in certain embodiments, the one or moresecondary elbows 338 may be in an axis perpendicular to the primary axis and produce one ormore bends 339 injumper line 330 in the same plane as the flow within thejumper line 330. In certain embodiments, the one or moresecondary elbows 338 may provide flexibility to thejumper line configuration 300. - The jumper line configuration discussed herein may have several advantages. One advantage is that the jumper line configurations discussed herein are able to provide bends without having valleys, thus increasing the flexibly while limiting the formation of hydrates. Another advantage is that using the jumper line geometry discussed herein, gas may segregate into the higher part so of the jumper line and water may segregate in the low sections, thus allowing water to be drained during shut ins.
- 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.
- 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.
Claims (20)
1. A jumper line system comprising:
a first subsea device;
a second subsea device; and
a jumper line providing fluid communication between the first subsea device and the second subsea device, wherein the jumper line does not comprise a valley.
2. The system of claim 1 , wherein the first subsea device comprises a well head.
3. The system of claim 1 , wherein the second subsea device comprises a manifold.
4. The system of claim 1 , wherein the jumper line comprises a single peak.
5. The system of claim 4 , wherein the peak comprises one or more elbows.
6. The system of claim 5 , wherein the jumper line comprises one or more secondary elbows.
7. The system of claim 1 , wherein the jumper line comprises one or more injection ports.
8. The system of claim 1 , wherein the jumper line comprises one or more valves.
9. A method of transporting hydrocarbons from a subsea well comprising:
providing a subsea well;
providing a manifold;
connecting the subsea well to the manifold via a jumper line, wherein the jumper line does not comprise a valley; and
flowing hydrocarbons from the subsea well to the manifold via the jumper line.
10. The method of claim 9 , wherein the jumper line comprises a single peak.
11. The method of claim 10 , wherein the peak comprises one or more elbows.
12. The method of claim 9 , wherein the jumper line comprises one or more secondary elbows.
13. The method of claim 12 , wherein the one or more secondary elbows produce one or more bends in the jumper line in the same plane as the flow of hydrocarbons within the jumper line.
14. The method of claim 9 , wherein the jumper line comprises one or more injection ports.
15. The method of claim 9 , wherein the jumper line comprises one or more valves.
16. A method of connecting two subsea devices comprising:
providing a first subsea device;
providing a second subsea device;
providing a jumper line, wherein the jumper line comprises a first end section and a second end section does not comprise a valley;
connecting the first end section of the jumper line to the first subsea device; and
connecting the second end section of the jumper line to the second subsea device.
17. The method of claim 16 , wherein the jumper line comprises a single peak.
18. The method of claim 17 , wherein the peak comprises one or more elbows.
19. The method of claim 16 , wherein the jumper line comprises one or more secondary elbows.
20. The method of claim 16 , wherein the jumper line comprises one or more injection ports.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US14/895,575 US20160130918A1 (en) | 2013-06-06 | 2014-06-04 | Jumper line configurations for hydrate inhibition |
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US201361831911P | 2013-06-06 | 2013-06-06 | |
PCT/US2014/040845 WO2014197557A1 (en) | 2013-06-06 | 2014-06-04 | Jumper line configurations for hydrate inhibition |
US14/895,575 US20160130918A1 (en) | 2013-06-06 | 2014-06-04 | Jumper line configurations for hydrate inhibition |
Publications (1)
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US20160130918A1 true US20160130918A1 (en) | 2016-05-12 |
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US14/895,575 Abandoned US20160130918A1 (en) | 2013-06-06 | 2014-06-04 | Jumper line configurations for hydrate inhibition |
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US (1) | US20160130918A1 (en) |
EP (1) | EP3004520A4 (en) |
CN (1) | CN105283625B (en) |
AU (1) | AU2014275020B2 (en) |
BR (1) | BR112015030340A8 (en) |
WO (1) | WO2014197557A1 (en) |
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US20170234098A1 (en) * | 2014-08-19 | 2017-08-17 | Statoil Petroleum As | Wellhead assembly |
US20210231249A1 (en) * | 2020-01-28 | 2021-07-29 | Chevron U.S.A. Inc. | Systems and methods for thermal management of subsea conduits using an interconnecting conduit and valving arrangement |
US11634970B2 (en) | 2020-01-28 | 2023-04-25 | Chevron U.S.A. Inc. | Systems and methods for thermal management of subsea conduits using a jumper having adjustable insulating elements |
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- 2014-06-04 BR BR112015030340A patent/BR112015030340A8/en not_active Application Discontinuation
- 2014-06-04 WO PCT/US2014/040845 patent/WO2014197557A1/en active Application Filing
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US20170234098A1 (en) * | 2014-08-19 | 2017-08-17 | Statoil Petroleum As | Wellhead assembly |
AU2015304087B2 (en) * | 2014-08-19 | 2019-10-03 | Equinor Energy As | Wellhead assembly |
US10697265B2 (en) * | 2014-08-19 | 2020-06-30 | Equinor Energy As | Wellhead assembly |
US10982502B2 (en) * | 2014-08-19 | 2021-04-20 | Equinor Energy As | Wellhead assembly |
NO345975B1 (en) * | 2014-08-19 | 2021-11-29 | Statoil Petroleum As | Wellhead assembly |
US20210231249A1 (en) * | 2020-01-28 | 2021-07-29 | Chevron U.S.A. Inc. | Systems and methods for thermal management of subsea conduits using an interconnecting conduit and valving arrangement |
US11634970B2 (en) | 2020-01-28 | 2023-04-25 | Chevron U.S.A. Inc. | Systems and methods for thermal management of subsea conduits using a jumper having adjustable insulating elements |
Also Published As
Publication number | Publication date |
---|---|
CN105283625B (en) | 2017-12-26 |
AU2014275020B2 (en) | 2017-04-27 |
EP3004520A4 (en) | 2017-01-25 |
CN105283625A (en) | 2016-01-27 |
BR112015030340A8 (en) | 2019-12-24 |
WO2014197557A1 (en) | 2014-12-11 |
EP3004520A1 (en) | 2016-04-13 |
AU2014275020A1 (en) | 2016-01-28 |
BR112015030340A2 (en) | 2017-07-25 |
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