US20050205261A1 - System and method for remediating pipeline blockage - Google Patents
System and method for remediating pipeline blockage Download PDFInfo
- Publication number
- US20050205261A1 US20050205261A1 US10/804,545 US80454504A US2005205261A1 US 20050205261 A1 US20050205261 A1 US 20050205261A1 US 80454504 A US80454504 A US 80454504A US 2005205261 A1 US2005205261 A1 US 2005205261A1
- Authority
- US
- United States
- Prior art keywords
- fluid
- pipe
- tubing
- space
- remote location
- 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.)
- Abandoned
Links
- 238000000034 method Methods 0.000 title claims abstract description 47
- 239000012530 fluid Substances 0.000 claims abstract description 190
- 150000004677 hydrates Chemical class 0.000 claims abstract description 30
- 238000004519 manufacturing process Methods 0.000 claims description 104
- 239000007788 liquid Substances 0.000 claims description 7
- 238000006073 displacement reaction Methods 0.000 claims 5
- 238000005086 pumping Methods 0.000 claims 3
- 238000013022 venting Methods 0.000 claims 3
- 230000003213 activating effect Effects 0.000 claims 1
- 230000015572 biosynthetic process Effects 0.000 abstract description 3
- 239000007789 gas Substances 0.000 description 27
- 230000003068 static effect Effects 0.000 description 12
- 230000008030 elimination Effects 0.000 description 5
- 238000003379 elimination reaction Methods 0.000 description 5
- 230000008018 melting Effects 0.000 description 5
- 238000002844 melting Methods 0.000 description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 239000003208 petroleum Substances 0.000 description 4
- 238000003780 insertion Methods 0.000 description 3
- 230000037431 insertion Effects 0.000 description 3
- 230000008016 vaporization Effects 0.000 description 3
- 238000009834 vaporization Methods 0.000 description 3
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- 238000004391 petroleum recovery Methods 0.000 description 2
- 150000001875 compounds Chemical class 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 239000011800 void material Substances 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
Images
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
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/12—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor using drilling pipes with plural fluid passages, e.g. closed circulation systems
-
- 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
Definitions
- pipeline systems are used to transport unprocessed and untreated petroleum production fluids from a petroleum reservoir in the sea bed to a production facility, or the like, floating on the surface of the sea.
- hydrates hydrates, wax and/or other types of compounds (hereinafter collectively referred to as “hydrates”) will form which can cause blockage of the pipeline.
- the fluids come from the reservoir at a relatively high temperature, they will cool down when flowing through the subsea pipeline and especially when they sit in the pipeline when the flow terminates. In either case, the fluids can cool down below the above threshold temperature causing the hydrates to form.
- FIG. 1 is an elevational view of a subsea petroleum operation including an embodiment of the invention.
- FIG. 2 is an enlarged sectional view of a portion of the pipe of FIG. 1 .
- FIGS. 3-6 are views, similar to that of FIG. 2 , but depicting alternative embodiments.
- the reference numeral 10 refers to a pipe that forms a riser and a flow line in a subsea petroleum recovery operation.
- the pipe 10 extends between a production facility 12 that floats on the surface of the sea S, and a tree system 14 extending just above a subsea well 16 .
- a production facility 12 that floats on the surface of the sea S
- a tree system 14 extending just above a subsea well 16 .
- the pipe 10 is shown curved in a manner to form an arc, it is understood that this is for the purpose of example only and that it can take other forms.
- the tree system 14 is supported at the upper surface of the sea bed B and the well 16 extends into the sea bed for recovering petroleum based production fluid from a formation formed in the sea bed.
- the tree system 14 is conventional and, as such, includes a series of valves and associated components (not shown) for controlling the flow of the production fluid in the pipe 10 .
- the production fluid flows from the well 16 , through the tree system 14 and the pipe 10 and to the production facility 12 for further processing, under control of the tree system 14 .
- the production fluid from the well 16 is at a relatively high temperature, it will cool down when flowing through the pipe 10 and/or when it is confined in the pipe when the flow terminates. It will be assumed that the relatively high static head and fluid pressure in the pipe 10 causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.
- the above threshold temperature e.g., the temperature below which hydrates are formed
- the normal flow of production fluid from the well 16 and into the pipe 10 is terminated by closing the proper valves in the tree system 14 ( FIG. 1 ), and a section of coiled tubing 18 is installed in the pipe 10 .
- the lower end of the tubing 18 is inserted into the pipe and lowered from a supply reel, or the like, at the production facility 12 until the latter end reaches a predetermined depth in the pipe, which corresponds to the depth sufficient to remove the head of liquid in the pipe, as will be explained.
- the sections of the pipe 10 and the coiled tubing 18 are shown extending vertically in FIG.
- An annular space 20 is formed between the outer diameter of the tubing 18 and the inner diameter of the corresponding section of the pipe, and continues to the production facility 12 .
- production fluid from the well 16 accumulates in the tubing 18 and in the space 20 and creates a static head and a relatively high fluid pressure.
- gas compressible, relatively low-density fluid, such as nitrogen or hydrocarbon gas
- the gas passes through the space 20 in a direction as shown by the arrows A which is in a direction towards the well 16 , and is introduced at a pressure sufficient to displace the production fluid in the space.
- the displaced production fluid is forced into the end of the tubing 18 as shown by the arrows B, before passing through the tubing in a direction towards the production facility 12 shown by the arrows C. During this movement, the original production fluid in the tubing 18 is also displaced.
- the gas flowing down the space 20 reaches the end of the tubing 18 , most of the production fluid is evacuated from the space 20 and the tubing 18 and passed to the production facility 12 . The gas will then start flowing up the space 20 and the tubing 18 and carry any remaining production fluid with it.
- the supply of the gas to the space 20 is stopped, the system is depressurized either via the space and/or via the tubing 18 .
- the remaining production fluids will be allowed to expand and flow naturally to the production facility by a variety of physical phenomena including the expansion of the relatively low vapor pressure production fluid and/or the vaporization of the high vapor pressure gas.
- this evacuation of the production fluid from the space 20 and the tubing 18 significantly reduces the static head and fluid pressure in the space and the tubing. This lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe 10 .
- the tubing 18 can be removed from the pipe 10 , and the normal flow of production fluid from the well 16 , through the pipe 10 and to the production facility 12 , can be restarted under control of the valves in the tree system 14 .
- FIG. 3 contains several components of the embodiment of FIG. 2 , which are given the same reference numerals. It will be assumed that the relatively high static head and fluid pressure in the pipe 10 causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.
- the above threshold temperature e.g., the temperature below which hydrates are formed
- the tubing 18 is kept void of production fluid during the above insertion of the packer 26 by maintaining a gas pressure on the tubing or by the use of a special check valve (not shown) that can be controlled by pressure variations in the tubing.
- the gas in the tubing 18 is then vented to the production facility 12 ( FIG. 1 ) or the above check valve is opened, causing the production fluid below the packer 26 to expand and flow upwardly in the tubing and to the production facility.
- the static head and fluid pressure in the pipe 10 is determined according to this height of the gas/liquid interface and the pressure of the gas above the interface. With the tubing 18 and the packer 26 in place and the tubing 18 depressurized in accordance with the above, the interface is likely to be lower than the original head in the pipe 10 before the tubing 18 and the packer are introduced, and thus the final equilibrium pressure in the pipe 10 will be lower.
- the depth to which the tubing 18 and the packer 26 are inserted can be selected to ensure that the final equilibrium pressure is low enough to lower the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus cause melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe 10 .
- the tubing 18 and the packer 26 can be removed from the pipe 10 , and the normal flow of production fluid from the well 16 , through the pipe 10 and to the production facility 12 , can be restarted.
- FIG. 4 contains several components of the embodiment of FIG. 3 , which are given the same reference numerals.
- a submersible electric motor 30 is connected to the lower end of the tubing 18 and is operatively connected to a submersible pump 32 .
- the relatively high static head and fluid pressure in the pipe 10 causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.
- the above threshold temperature e.g., the temperature below which hydrates are formed
- the normal flow of production fluid from the well 16 and into the pipe 10 is terminated by closing the proper valves in the tree system 14 , and the coiled tubing 18 is installed in the pipe 10 in the manner discussed above.
- the motor 30 is activated to drive the pump 32 to lift the production fluid from that portion of the pipe 10 extending below the tubing 18 , and pass the fluid through the tubing 18 and the pipe 10 to the production facility 12 ( FIG. 1 ), as shown by the arrows A. Also, the pump 32 pumps the fluid from that portion of the space 20 extending below the packer 26 , through the tubing 18 , and to the production facility 12 ( FIG. 1 ), as shown by the arrows B. As production fluid is pumped from the pipe 10 and the space 20 in the above manner, the packer 26 prevents the production fluid in the space 20 above the packer from flowing downwardly.
- the static head and the fluid pressure in the pipe 10 will be quickly reduced and the temperature of the fluid is lowered to a value below the above-mentioned threshold temperature, thus causing melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe 10 .
- the tubing 18 , the packer 26 , the pump 30 and the motor 32 can be removed from the pipe 10 , and the normal flow of production fluid from the well 16 , through the pipe 10 and to the production facility 12 , can be restarted.
- the pump 30 and the motor 32 can be replaced by a hydraulic power turbine in which case separate conduits could be provided to convey the hydraulic production fluid supply, the hydraulic production fluid return and the fluid being removed from the pipe.
- a length of flexible tubing could be installed on the suction end of the pump 30 to extend the reach of the production fluid removal capability of the system to some point significantly beyond the location of the pump.
- the packer 26 can be eliminated and the fluid in the entire space 20 removed by the pump 32 .
- the embodiment of FIG. 5 includes components of the previous embodiments, which are given the same reference numerals.
- the normal flow of production fluid from the well 16 and into the pipe 10 is terminated by closing the proper valves in the tree system 14 ( FIG. 1 ), and two radially spaced, concentric coiled tubes 18 a and 18 b are installed in the pipe 10 .
- the lower ends of the tubes 18 a and 18 b are inserted into the pipe 10 and lowered from a supply reel, or the like, at the production facility 12 ( FIG. 1 ) until the latter ends reach a predetermined depth in the pipe, which corresponds to the depth sufficient to remove the head of liquid in the pipe.
- a space 20 extends between the outer surface of the tube 18 b and the inner surface of the pipe 10 .
- a space 36 is formed between the outer surface of the tube 18 a and the inner surface of the tube 18 b and extends to the production facility 12 .
- production fluid from the well 16 accumulates in the tubes 18 a and 18 b and in the space 36 and creates a static head and a relatively high fluid pressure.
- a packer 26 is lowered into the space 20 to a desired depth and then set in place to seal against production fluid flow across it in a conventional manner and therefore isolate that portion of the space 20 extending above the packer from that portion extending below, as viewed in FIG. 3 .
- gas compressible, relatively low-density fluid, such as nitrogen or hydrocarbon gas
- the gas passes through the space 36 in a direction as shown by the arrows A which is in a direction towards the well 16 , and is introduced at a pressure sufficient to displace the production fluid in the space.
- the displaced production fluid is forced into the end of the tube 18 a as shown by the arrows B, before passing through the latter tube in a direction towards the production facility 12 shown by the arrows C. During this movement, the original production fluid in the tube 18 a is also displaced.
- the gas flowing down the space 36 reaches the end of the tubes 18 a, most of the production fluid is evacuated from the space 36 and the tube 18 a and passed to the production facility 12 . The gas will then start flowing up the space 36 and the tubes 18 a and 18 b and carry the production fluid with it.
- the cross section of the flow path through the space 36 , as well as the flow path defined in the interior of the tube 18 a , is significantly smaller than the diameter of the pipe 10 . This promotes the lifting of the production fluid up the tube 18 a and the space 36 in accordance with the above.
- the supply of the gas to the space 36 is stopped, the system is depressurized either via the space or the tubing and the remaining production fluid allowed to expand and flow naturally to the production facility 12 via the tubes 18 a and 18 b by a variety of physical phenomena including the expansion of the relatively low vapor pressure production fluid and/or the vaporization of the high vapor pressure gas.
- this evacuation of the production fluid from the space 36 and the tubes 18 a and 18 b in the foregoing manner significantly reduces the static head and fluid pressure in the space and the tubing.
- the reduction of the static head and fluid pressure in the pipe 10 lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe 10 .
- the tubes 18 a and 18 b and the packer 26 can be removed from the pipe 10 , and the normal flow of production fluid from the well 16 , through the pipe 10 and to the production facility 12 , can be restarted.
- FIG. 6 contains several components of the embodiment of FIG. 2 , which are given the same reference numerals, and, as in the previous embodiments, it will be assumed that production fluid is present in the tubing 18 and in the space 20 between the tubing 18 and the pipe 10 . It will be assumed that the relatively high static head and fluid pressure in the pipe 10 causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.
- the above threshold temperature e.g., the temperature below which hydrates are formed
- the normal flow of production fluid from the well 16 and into the pipe 10 is terminated by closing the proper valves in the tree system 14 , and the tubing 18 is installed in the pipe 10 in the manner discussed above.
- One or more conventional pigging devices 40 are then inserted downwardly into the space 20 through the column of production fluid in the space. This insertion can be done in any conventional manner including installing the pigging devices 40 on the lower end portion of the tubing 18 before it is inserted in the pipe 10 .
- the pigging devices 40 are configured to normally allow fluids to flow past them in the space 20 , but can be expanded to bridge across the space 20 in a conventional manner, thus creating a dynamic seal. It will be assumed that the pigging device 40 nearest to the production facility 12 ( FIG. 1 ), which is the uppermost device as viewed in FIG. 6 , is expanded and the remaining devices are configured to allow fluid to flow past them.
- Gas from the production facility 12 is then introduced into the upper end of the tubing 18 and flows in the tubing in a direction shown by the arrows A, which is towards the well 16 .
- the gas displaces the production fluid in the tubing 18 which exits the lower end of the tubing, and flows in the space 20 in a direction shown by the arrows C, which is towards the production facility 12 .
- the displaced fluid and the gas flowing through the space 20 in the above manner will pass through all of the pigging devices 40 with the exception of the above device nearest to the production facility which will be pushed upwardly in the space by the gas and fluid.
- As the latter pigging device 40 moves upwardly, it will sweep out the fluids above the space 20 .
- the remaining pigging devices 40 can be expanded as necessary and forced towards the production facility 12 in the above manner to remove the desired quantity of production fluid from the pipe.
- the reduction of the static head and fluid pressure in the pipe 10 lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe 10 .
- the tube 18 and the pigging devices 40 are removed from the pipe 10 , and the normal flow of production fluid from the well 16 , through the pipe 10 and to the production facility 12 , is restarted.
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- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Pipeline Systems (AREA)
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US10/804,545 US20050205261A1 (en) | 2004-03-19 | 2004-03-19 | System and method for remediating pipeline blockage |
PCT/GB2005/001003 WO2006010874A1 (fr) | 2004-03-19 | 2005-03-16 | Systeme et procede permettant de remedier aux obstructions dans un pipe-line |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US10/804,545 US20050205261A1 (en) | 2004-03-19 | 2004-03-19 | System and method for remediating pipeline blockage |
Publications (1)
Publication Number | Publication Date |
---|---|
US20050205261A1 true US20050205261A1 (en) | 2005-09-22 |
Family
ID=34962987
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US10/804,545 Abandoned US20050205261A1 (en) | 2004-03-19 | 2004-03-19 | System and method for remediating pipeline blockage |
Country Status (2)
Country | Link |
---|---|
US (1) | US20050205261A1 (fr) |
WO (1) | WO2006010874A1 (fr) |
Cited By (14)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20100314122A1 (en) * | 2009-03-11 | 2010-12-16 | Andrea Sbordone | Method and system for subsea intervention using a dynamic seal |
US20110052328A1 (en) * | 2009-08-26 | 2011-03-03 | Chevron U.S.A. Inc. | Apparatus and method for performing an intervention in a riser |
US20110171817A1 (en) * | 2010-01-12 | 2011-07-14 | Axcelis Technologies, Inc. | Aromatic Molecular Carbon Implantation Processes |
US8430169B2 (en) | 2007-09-25 | 2013-04-30 | Exxonmobil Upstream Research Company | Method for managing hydrates in subsea production line |
US8469101B2 (en) | 2007-09-25 | 2013-06-25 | Exxonmobil Upstream Research Company | Method and apparatus for flow assurance management in subsea single production flowline |
US20140262283A1 (en) * | 2013-03-13 | 2014-09-18 | Halliburton Energy Services, Inc. | Methods for treatment of a subterranean formation |
US20160168972A1 (en) * | 2014-12-11 | 2016-06-16 | Chevron U.S.A. Inc. | Mitigating hydrate formation during a shutdown of a deep water fpso |
WO2021162697A1 (fr) * | 2020-02-12 | 2021-08-19 | Halliburton Energy Services, Inc. | Canalisation descendante de tubes spiralés concentriques de remédiation d'hydrates |
US11131158B1 (en) | 2020-07-08 | 2021-09-28 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11256273B2 (en) | 2020-07-08 | 2022-02-22 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11274501B2 (en) | 2020-07-08 | 2022-03-15 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11294401B2 (en) | 2020-07-08 | 2022-04-05 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11314266B2 (en) | 2020-07-08 | 2022-04-26 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11802645B2 (en) | 2020-07-08 | 2023-10-31 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB0914572D0 (en) | 2009-08-20 | 2009-09-30 | Danisco | Process |
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2004
- 2004-03-19 US US10/804,545 patent/US20050205261A1/en not_active Abandoned
-
2005
- 2005-03-16 WO PCT/GB2005/001003 patent/WO2006010874A1/fr active Application Filing
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Cited By (22)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8919445B2 (en) | 2007-02-21 | 2014-12-30 | Exxonmobil Upstream Research Company | Method and system for flow assurance management in subsea single production flowline |
US8430169B2 (en) | 2007-09-25 | 2013-04-30 | Exxonmobil Upstream Research Company | Method for managing hydrates in subsea production line |
US8469101B2 (en) | 2007-09-25 | 2013-06-25 | Exxonmobil Upstream Research Company | Method and apparatus for flow assurance management in subsea single production flowline |
US20100314122A1 (en) * | 2009-03-11 | 2010-12-16 | Andrea Sbordone | Method and system for subsea intervention using a dynamic seal |
US20110052328A1 (en) * | 2009-08-26 | 2011-03-03 | Chevron U.S.A. Inc. | Apparatus and method for performing an intervention in a riser |
WO2011028364A2 (fr) * | 2009-08-26 | 2011-03-10 | Chevron U.S.A. Inc. | Appareil et procédé pour la réalisation d'une intervention dans une colonne montante |
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US20160168972A1 (en) * | 2014-12-11 | 2016-06-16 | Chevron U.S.A. Inc. | Mitigating hydrate formation during a shutdown of a deep water fpso |
GB2606913A (en) * | 2020-02-12 | 2022-11-23 | Halliburton Energy Services Inc | Concentric coiled tubing downline for hydrate remediation |
WO2021162697A1 (fr) * | 2020-02-12 | 2021-08-19 | Halliburton Energy Services, Inc. | Canalisation descendante de tubes spiralés concentriques de remédiation d'hydrates |
US11613933B2 (en) | 2020-02-12 | 2023-03-28 | Halliburton Energy Services, Inc. | Concentric coiled tubing downline for hydrate remediation |
GB2606913B (en) * | 2020-02-12 | 2023-12-06 | Halliburton Energy Services Inc | Concentric coiled tubing downline for hydrate remediation |
US11131158B1 (en) | 2020-07-08 | 2021-09-28 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11256273B2 (en) | 2020-07-08 | 2022-02-22 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11274501B2 (en) | 2020-07-08 | 2022-03-15 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11294401B2 (en) | 2020-07-08 | 2022-04-05 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11314266B2 (en) | 2020-07-08 | 2022-04-26 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
US11802645B2 (en) | 2020-07-08 | 2023-10-31 | Saudi Arabian Oil Company | Flow management systems and related methods for oil and gas applications |
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