WO2014197557A1 - Jumper line configurations for hydrate inhibition - Google Patents

Jumper line configurations for hydrate inhibition Download PDF

Info

Publication number
WO2014197557A1
WO2014197557A1 PCT/US2014/040845 US2014040845W WO2014197557A1 WO 2014197557 A1 WO2014197557 A1 WO 2014197557A1 US 2014040845 W US2014040845 W US 2014040845W WO 2014197557 A1 WO2014197557 A1 WO 2014197557A1
Authority
WO
WIPO (PCT)
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.)
Ceased
Application number
PCT/US2014/040845
Other languages
French (fr)
Inventor
Gaurav Bhatnagar
Gregory John Hatton
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Shell USA Inc
Original Assignee
Shell Internationale Research Maatschappij BV
Shell Oil Co
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij BV, Shell Oil Co filed Critical Shell Internationale Research Maatschappij BV
Priority to BR112015030340A priority Critical patent/BR112015030340A8/en
Priority to CN201480031987.1A priority patent/CN105283625B/en
Priority to US14/895,575 priority patent/US20160130918A1/en
Priority to AU2014275020A priority patent/AU2014275020B2/en
Priority to EP14807984.1A priority patent/EP3004520A4/en
Publication of WO2014197557A1 publication Critical patent/WO2014197557A1/en
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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.
  • 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.
  • Figure 1 is a side view illustration of a typical M-shaped jumper line geometry.
  • Figure 2 is a side view illustration of a jumper line geometry in accordance with an embodiment of the present disclosure.
  • Figures 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. [0016]
  • 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.
  • 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 Figure 2 and Figures 3 A and 3B.
  • 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.
  • Figure 3A illustrates a side view of jumper line configuration 300
  • Figure 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.

Landscapes

  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Laying Of Electric Cables Or Lines Outside (AREA)
  • Optical Communication System (AREA)
  • Earth Drilling (AREA)
  • Pipeline Systems (AREA)
  • Other Liquid Machine Or Engine Such As Wave Power Use (AREA)

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

JUMPER LINE CONFIGURATIONS FOR HYDRATE INHIBITION
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional Application No. 61/831,911, filed June 6, 2013, which is incorporated herein by reference.
BACKGROUND
[0002] 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.
[0003] 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.
[0004] 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.
[0005] It is desirable to develop a jumper line configuration that aids in preventing the formation of gas hydrates.
SUMMARY
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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
[0011] 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.
[0012] Figure 1 is a side view illustration of a typical M-shaped jumper line geometry.
[0013] Figure 2 is a side view illustration of a jumper line geometry in accordance with an embodiment of the present disclosure.
[0014] Figures 3A and 3B are top and side view illustrations of a jumper line geometry in accordance with an embodiment of the present disclosure.
DETAILED DESCRIPTION
[0015] 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. [0016] 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.
[0017] Referring now to Figure 1, Figure 1 illustrates a conventional jumper line configuration 100. As can be seen in Figure 1, 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. In certain embodiments, the one or more peaks 133 are comprised of one or more elbows 132. In certain embodiments, the one or more peaks 133 define the one or more valleys 133.
[0018] In this conventional configuration, the valleys 134 and elbows 132 may provide flexibility to the jumper line. However, during shut ins, 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.
[0019] 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 Figure 2 and Figures 3 A and 3B.
[0020] Referring now to Figure 2, Figure 2 illustrates jumper line configuration 200. As can be seen in Figure 2, jumper line configuration 200 may comprise a first subsea device 210, a second subsea device, and a jumper line 230.
[0021] In certain embodiments, first subsea device 210 and second 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.
[0022] 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.
[0023] 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. In certain embodiments, the one or more straight 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 from first subsea device 210 to second subsea device 220. In certain embodiments, the one or more straight sections 231 may be inclined from 0 degrees to 90 degrees from the primary axis. In certain embodiments, 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. In certain embodiments, peak 233 is comprised of the one or more elbows 232. In certain embodiments, the one or more elbows 232 may comprise one or more connectors. Unlike jumper line configuration 100 of Figure 1, 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.
[0024] In certain embodiments, jumper line 230 may further comprise one or more injection ports 236 wherein a hydrate inhibitor may be injected into the jumper line 230. In certain embodiments, the one or more injection ports 236 may be disposed on the one or more end sections 235.
[0025] In certain embodiments, 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. In certain embodiments, 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. In other embodiments, 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. In certain embodiments, the one or more valves 237 may be tree valves.
[0026] In certain embodiments, during shut ins, 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.
[0027] Referring now to Figure 3, Figure 3A illustrates a side view of jumper line configuration 300 and Figure 3B illustrates a top view of jumper line configuration 300. As can be seen in Figure 3A, 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.
[0028] In certain embodiments, straight section 331 may be inclined with respect to the primary axis. In Figure 3, 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. However, as shown in Figure 3B, 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. For example, in certain embodiments, 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. In certain embodiments, the one or more secondary elbows 338 may provide flexibility to the jumper line configuration 300.
[0029] 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.
[0030] 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.
[0031] 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

C LA I M S
1. A j umper 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.
PCT/US2014/040845 2013-06-06 2014-06-04 Jumper line configurations for hydrate inhibition Ceased WO2014197557A1 (en)

Priority Applications (5)

Application Number Priority Date Filing Date Title
BR112015030340A BR112015030340A8 (en) 2013-06-06 2014-06-04 runoff system
CN201480031987.1A CN105283625B (en) 2013-06-06 2014-06-04 Jumper for suppressing aquation constructs
US14/895,575 US20160130918A1 (en) 2013-06-06 2014-06-04 Jumper line configurations for hydrate inhibition
AU2014275020A AU2014275020B2 (en) 2013-06-06 2014-06-04 Jumper line configurations for hydrate inhibition
EP14807984.1A EP3004520A4 (en) 2013-06-06 2014-06-04 Jumper line configurations for hydrate inhibition

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201361831911P 2013-06-06 2013-06-06
US61/831,911 2013-06-06

Publications (1)

Publication Number Publication Date
WO2014197557A1 true WO2014197557A1 (en) 2014-12-11

Family

ID=52008553

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2014/040845 Ceased WO2014197557A1 (en) 2013-06-06 2014-06-04 Jumper line configurations for hydrate inhibition

Country Status (6)

Country Link
US (1) US20160130918A1 (en)
EP (1) EP3004520A4 (en)
CN (1) CN105283625B (en)
AU (1) AU2014275020B2 (en)
BR (1) BR112015030340A8 (en)
WO (1) WO2014197557A1 (en)

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB201414733D0 (en) * 2014-08-19 2014-10-01 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

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030145997A1 (en) * 2002-02-06 2003-08-07 Gawain Langford Flowline jumper for subsea well
US6760275B2 (en) * 1997-04-07 2004-07-06 Kenneth J. Carstensen High impact communication and control system
US7296629B2 (en) * 2003-10-20 2007-11-20 Fmc Technologies, Inc. Subsea completion system, and methods of using same
WO2009079364A2 (en) * 2007-12-14 2009-06-25 Baker Hughes Incorporated Electrical submersible pump and gas compressor
US8235121B2 (en) * 2009-12-16 2012-08-07 Dril-Quip, Inc. Subsea control jumper module

Family Cites Families (20)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3825045A (en) * 1972-08-22 1974-07-23 Fmc Corp Fluid delivery and vapor recovery apparatus
US6022421A (en) * 1998-03-03 2000-02-08 Sonsub International, Inc, Method for remotely launching subsea pigs in response to wellhead pressure change
BR0206197A (en) * 2001-01-08 2004-02-03 Stolt Offshore Sa Maritime Ascending Tower
WO2005042905A2 (en) * 2003-10-20 2005-05-12 Exxonmobil Upstream Research Company A piggable flowline-riser system
WO2006057996A2 (en) * 2004-11-22 2006-06-01 Energy Equipment Corporation Dual bore well jumper
EA013376B1 (en) * 2006-02-03 2010-04-30 Эксонмобил Апстрим Рисерч Компани Wellbore method of hydrocarbons production
GB2481932B (en) * 2006-04-06 2012-02-22 Baker Hughes Inc Subsea flowline jumper containing esp
CA2664617C (en) * 2006-10-04 2012-08-28 Fluor Technologies Corporation Dual subsea production chokes for high pressure well production
WO2009042307A1 (en) * 2007-09-25 2009-04-02 Exxonmobile Upstream Research Company Method and apparatus for flow assurance management in subsea single production flowline
US8382457B2 (en) * 2008-11-10 2013-02-26 Schlumberger Technology Corporation Subsea pumping system
US8555978B2 (en) * 2009-12-02 2013-10-15 Technology Commercialization Corp. Dual pathway riser and its use for production of petroleum products in multi-phase fluid pipelines
US8863784B2 (en) * 2010-04-22 2014-10-21 Cameron International Corporation Viscoelastic damped jumpers
US9500247B2 (en) * 2010-11-01 2016-11-22 University Of Houston Pounding tune mass damper with viscoelastic material
BR112014004116B1 (en) * 2011-08-23 2020-08-04 Total Sa SUBMARINE INSTALLATION
US20130153038A1 (en) * 2011-09-16 2013-06-20 Andrew J. Barden Apparatus and methods for providing fluid into a subsea pipeline
SG11201406894VA (en) * 2012-04-26 2014-11-27 Ian Donald Oilfield apparatus and methods of use
US20160010434A1 (en) * 2014-07-10 2016-01-14 Baker Hughes Incorporated Submersible Pump Assembly Inside Subsea Flow Line Jumper and Method of Operation
US9739108B2 (en) * 2014-09-02 2017-08-22 Onesubsea Ip Uk Limited Seal delivery system
US9181786B1 (en) * 2014-09-19 2015-11-10 Baker Hughes Incorporated Sea floor boost pump and gas lift system and method for producing a subsea well
WO2016123340A1 (en) * 2015-01-30 2016-08-04 Bp Corporation North America, Inc. Subsea heat exchangers for offshore hydrocarbon production operations

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6760275B2 (en) * 1997-04-07 2004-07-06 Kenneth J. Carstensen High impact communication and control system
US20030145997A1 (en) * 2002-02-06 2003-08-07 Gawain Langford Flowline jumper for subsea well
US7296629B2 (en) * 2003-10-20 2007-11-20 Fmc Technologies, Inc. Subsea completion system, and methods of using same
WO2009079364A2 (en) * 2007-12-14 2009-06-25 Baker Hughes Incorporated Electrical submersible pump and gas compressor
US8235121B2 (en) * 2009-12-16 2012-08-07 Dril-Quip, Inc. Subsea control jumper module

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See also references of EP3004520A4 *

Also Published As

Publication number Publication date
EP3004520A1 (en) 2016-04-13
AU2014275020A1 (en) 2016-01-28
BR112015030340A2 (en) 2017-07-25
AU2014275020B2 (en) 2017-04-27
US20160130918A1 (en) 2016-05-12
CN105283625B (en) 2017-12-26
EP3004520A4 (en) 2017-01-25
CN105283625A (en) 2016-01-27
BR112015030340A8 (en) 2019-12-24

Similar Documents

Publication Publication Date Title
EP3276123B1 (en) Subsea pipeline station
US8950498B2 (en) Methods, apparatus and systems for conveying fluids
AU2012291947A1 (en) Flexible pipe with injection tube and method for transporting a petroleum effluent
US9835283B2 (en) Polymeric device to protect pipe coupling
AU2014275020B2 (en) Jumper line configurations for hydrate inhibition
EP3719249B1 (en) Equipment for connecting undersea lines
BR112018074937B1 (en) SET, METHOD FOR USE OF A FLOW CONTROL MODULE AND SYSTEM
US20170016309A1 (en) Long offset gas condensate production systems
US11149530B2 (en) Subsea system and method for pressurization of a subsea oil reserve by injecting at least one of water and gas
KR20150111496A (en) Offshore plant
CN204534129U (en) A device for preventing freezing
CN105051319B (en) Fluid injection system and method
KR102113399B1 (en) Helical Trace Heating Flowline
US11634970B2 (en) Systems and methods for thermal management of subsea conduits using a jumper having adjustable insulating elements
CN208381762U (en) A kind of Multi-functional oil field Crude Oil Transportation individual well pipe-line system
CN116123453A (en) A high pour point oil subsea production manifold
US20210231249A1 (en) Systems and methods for thermal management of subsea conduits using an interconnecting conduit and valving arrangement
US10544630B1 (en) Systems and methods for slug mitigation
CN104595720A (en) A device for preventing freezing
KR20140055484A (en) Subsea pipeline system of the subsea production plant
KR20150133894A (en) Offshore plant
KR200480223Y1 (en) Horizontal pipelines for crude oil transfer
KR20170035377A (en) Offshore plant
US11767727B2 (en) Mandrel multiplying device for subsea oil production apparatus
US20210231250A1 (en) Systems and methods for thermal management of subsea conduits using a self-draining jumper

Legal Events

Date Code Title Description
WWE Wipo information: entry into national phase

Ref document number: 201480031987.1

Country of ref document: CN

121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 14807984

Country of ref document: EP

Kind code of ref document: A1

REEP Request for entry into the european phase

Ref document number: 2014807984

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: 2014807984

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: 14895575

Country of ref document: US

NENP Non-entry into the national phase

Ref country code: DE

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112015030340

Country of ref document: BR

ENP Entry into the national phase

Ref document number: 2014275020

Country of ref document: AU

Date of ref document: 20140604

Kind code of ref document: A

ENP Entry into the national phase

Ref document number: 112015030340

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20151203