WO2011066050A1 - Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer - Google Patents
Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer Download PDFInfo
- Publication number
- WO2011066050A1 WO2011066050A1 PCT/US2010/053774 US2010053774W WO2011066050A1 WO 2011066050 A1 WO2011066050 A1 WO 2011066050A1 US 2010053774 W US2010053774 W US 2010053774W WO 2011066050 A1 WO2011066050 A1 WO 2011066050A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- conduit
- multiphase fluid
- atomizing device
- compressor
- expander
- Prior art date
Links
Classifications
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D29/00—Details, component parts, or accessories
- F04D29/58—Cooling; Heating; Diminishing heat transfer
- F04D29/582—Cooling; Heating; Diminishing heat transfer specially adapted for elastic fluid pumps
- F04D29/5846—Cooling; Heating; Diminishing heat transfer specially adapted for elastic fluid pumps cooling by injection
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D31/00—Pumping liquids and elastic fluids at the same time
Definitions
- centrifugal compressors or gas expanders do not handle liquid slugs and thus it is assumed that they can only handle a fraction of one percent liquid by volume.
- expensive liquid separators, dehydration processes and/or unit scrubbers are utilized to try and remove or separate the liquids prior to using centrifugal compressors or expanders.
- These devices are often designed for specific operating conditions and are then limited in the range of Gas Volume Fraction (GVF) that can be handled with a given process flow rate.
- GVF Gas Volume Fraction
- multiphase pumps can be used if it is known that the fluid will generally be below 90% GVF.
- Centrifugal compressors are often restricted to applications with GVFs of 99.7 or higher and even this can cause problems within the machine for stability and affecting the reliability of the seals and bearings. Therefore, for processes outside this small range, the current practice is to separate the fluids prior to utilizing a centrifugal compressor even with the design limitation with the associated process and equipment.
- gas expanders which are functionally a centrifugal compressor running in reverse to extract energy in one form or another through a process pressure drop across the expander.
- the separators, scrubbers and dehydration units are not only expensive and limited in liquid capacity and volume flow range but they also tend to be very bulky, taking up expensive real estate in locations such as offshore platforms, subsea processing or onshore facilities.
- This coupled with complex control systems and additional auxiliary equipment like pumps, regulators, level controllers, transmitters and filters adds to the complexity and likelihood of failure of these systems.
- FIG. 1 depicts a typical oil or gas well stream service where a separator 4 is used to separate liquids from the gas so that a centrifugal compressor 21 and pump 12 can then be used to boost the gas and liquid separately.
- the two are then combined again at 14 in order to transport both through a pipeline to a processing facility. If one machine could be used to transport the combined flow it has the potential to greatly reduce the overall cost and complexity of the total system.
- the above noted problems in handling multiphase fluid flow have been addressed by utilizing a liquid slug suppressor and/or an atomizing device to enhance the upstream mixing of the liquid with the gas, thus enabling the centrifugal compressor or expander to better handle higher levels of liquid.
- the atomizing device may be any one of known fluid atomizers including one or more atomizing nozzles or a flow mixer device. This can be used in existing designs to help protect the compressor or expander from process upsets with additional liquid volume or as a stand alone design to help eliminate some of the required equipment such as the separator or liquid pump.
- the slug suppressor slows down a slug of liquid and mixes it with gas already in the device to reduce the sudden change in density. This allows time for the compressor driver to slow down as the torque or load increases with the increase in liquid volume or reduction of GVF.
- the atomizing device further helps turn liquid slugs into droplets or mist mixed in with the gas to better help the compressor in dealing with the change in density and load while reducing the impact, resulting in less erosion. Either product or both in series can be used in a compressor or expander application where there is a potential for some liquids or liquid upsets.
- atomizing device means any device or mechanism for breaking a liquid into a fog, mist, or spray of liquid.
- atomized as used herein is to be understood to mean small, discrete particles of liquid.
- slug suppressor means any device that helps slow down the sudden change in fluid density of a high level of liquid within a gas stream by mixing the predominately liquid flow with gas that was flowing ahead of, with or behind the liquid.
- FIG. 1 is a schematic diagram of a known multiphase fluid handling system.
- FIG. 2 is a schematic diagram of one embodiment of a multiphase fluid handling system according to the disclosure for compressing a multiphase fluid.
- FIG. 3 is a schematic diagram of another embodiment of a multiphase fluid handling system according to the disclosure for expanding a multiphase fluid.
- FIG. 4 is a schematic depiction of a slug suppressor and atomizing device combined.
- FIG. 5 is a modified version of the multiphase fluid handling system shown in
- FIG. 1 illustrates a known system for handling a multiphase fluid in a well head environment.
- Fluid which may include water, oil, and gas for example, is directed into a cooler 1 and then into a separator tank 4 via a check valve 2 and conduit 3.
- Water is separated out and a pump 6 pumps the water to a remote location via conduit 7.
- Oil and condensate are collected and pump 12 delivers the oil and condensate to conduit 15 via conduits 11 and 13.
- a recycle line 30 is provided which includes valve 31, cooler 32 and check valve 33.
- Multiphase fluid for example fluid from a well head, is directed to the apparatus by a conduit 50, check valve 51, and conduit 52.
- the mixture of liquid and gas enters a fluid treatment device 55.
- the fluid treatment device may be a slug suppressor or a known atomizing device, such as one or more atomizing nozzles or a flow mixer. It may also be a combination of these elements.
- An example of a combined slug suppressor and atomizing device is shown in FIG. 4. Liquid accumulates in inner chamber 107 and gas flows in outer chamber 108.
- Baffles 104 are provided in the walls of inner chamber 107 to allow for sudden increases in liquid to spill over into the gas stream and mix with the gas. Thus a sudden increase in liquid flow is slowed down by using some of the gas still in the slug suppressor to reduce the liquid volume.
- Atomizing nozzles 105 at the lower end of the liquid chamber atomize the liquid and spray it into the gas flow downstream of a tapered portion 109 of the gas flow path. The atomized liquid and gas streams continue to flow through conduit portion 106.
- a typical slug suppressor and atomizing device is available from Framo Engineering AS.
- a flow mixer may include counter swirling vanes or counter rotating vortices.
- the mixture leaving the fluid treatment device 55 flows through conduit 56 to compressor 58.
- Compressed fluid leaves compressor 58 through conduit 60 and 61 to check valve 62 and to a distribution conduit 63 which delivers the compressed fluid to a desired location.
- a recycle line for the mixture from compressor 58 is provided at 66 that includes a valve 67, and check valve 69.
- FIG. 3 illustrates the application of the principles of the invention in an expander system.
- a multiphase fluid passes through a multiphase flow meter 82, a control valve 84, and a conduit 85 into the fluid treatment device 55. From there the mixture flows through conduit 91, expander 93, conduit 94, check valve 95 and distribution conduit 96.
- the expander 93 may be connected to a generator or compressor 92 or any device that requires a source of power.
- a bypass line 99, 97 along with a valve 98 are provided for bypassing expander 93.
- a hydraulic torque converter 90 may be positioned between the expander 93 and generator or compressor 90.
- a variable speed drive 57 such as a motor or other mechanical or electrical drive, including but not limited to gas motor, steam or gas turbine, expander, hydraulic turbine, is connected to the compressor 58.
- the drive mechanism controlling the torque or speed between the driver and compressor may be electronic, hydraulic, or mechanical. Suitable means for controlling the variable speed drive may include sensors for sensing torque, load, fluid density, GVF or input power.
- Speed or torque control helps make centrifugal compressors and expanders more robust, thus increasing reliability and reducing maintenance cost in wet services by designing the system to better manage a liquid slug and multiphase flow. This could be applied in all types of centrifugal compressor and expander applications where liquids are present or potentially present in the process, including well head services, subsea compressors or expanders, LNG expansion, wet gas compressors and other upstream and downstream processes.
- the flow control could use a two-or three-phase flow meter 82 to operate an inlet flow valve 84 or inlet guide vanes in order to reduce the flow as the GVF drops with increased liquid level, as shown in FIG 3.
- Other options are to use a hydraulic torque converter 90 between the gas expander 93 and what it is driving or any other method to measure the fluid density, multiphase flow mixture, mass flow, output power, or torque.
- variable speed drive 57 of FIG. 2 may be replaced by a fixed speed driver 102.
- a hydraulic torque converter 101 may be positioned between the fixed speed driver and the compressor 58 to allow for varying the speed of compressor 58.
- Embodiment A Apparatus for compressing a multiphase fluid comprising: a first conduit for conveying the multiphase fluid;
- centrifugal compressor connected to an output of the slug suppressor; and a distribution conduit connected to the compressor for conveying the compressed multiphase fluid to a desired location.
- Embodiment B The apparatus of embodiment A, further comprising an atomizing device positioned in the first conduit.
- Embodiment C The apparatus of embodiment B, wherein the atomizing device is a flow mixer that includes at least two counter swirling vanes or counter rotating vortices.
- Embodiment D The apparatus of any of embodiments A-C, wherein the driver for the compressor is an electric or gas motor, gas or steam turbine, expander, hydraulic turbine.
- the driver for the compressor is an electric or gas motor, gas or steam turbine, expander, hydraulic turbine.
- Embodiment E The apparatus of any of embodiments A-D, further comprising a means for controlling the compressor speed based on produced torque, load, fluid density, multiphase flow measurement or output power.
- Embodiment F The apparatus of embodiment B or C, wherein the slug suppressor and atomizing device are combined in a housing having an inlet and outlet, wherein the housing comprises:
- Embodiment G Apparatus according to embodiment F, wherein the housing tapers from the inlet to the outlet.
- Embodiment H Apparatus according to any of embodiments A-G, further comprising a recycle conduit connected at one end to the output of the compressor and at its other end to the first conduit.
- Embodiment I Apparatus according to embodiment H, further comprising a recycle valve in the recycle conduit.
- Embodiment J Apparatus for expanding a multiphase fluid comprising:
- an expander connected to an outlet of the slug suppressor; and a conduit connected to the expander for conveying the multiphase fluid to a desired location.
- Embodiment K The apparatus of embodiment J, further comprising an atomizing device connected to the first conduit.
- Embodiment L The apparatus of embodiment K, wherein the atomizing device is a flow mixer that includes at least two counter swirling vanes or counter rotating vortices.
- Embodiment M The apparatus of any of embodiments J-L, further comprising a generator or compressor connected to a power output shaft of the expander.
- Embodiment N The apparatus of embodiment K or L, wherein the slug suppressor and atomizing device are combined in a housing having an inlet and outlet, and the housing comprises
- Embodiment O Apparatus according to embodiment N, wherein the housing tapers from the inlet to the outlet.
- Embodiment P Apparatus according to any of embodiments J-O, further comprising a bypass conduit connected at one end to the output of the expander and at its other end to the first conduit.
- Embodiment Q Apparatus according to embodiment P, further comprising a bypass valve in the bypass conduit.
- Embodiment R Apparatus according to any of embodiments J-Q, further comprising means for controlling the expander or the driven equipment speed based on produced torque, load, fluid density, multiphase flow measurement or output power.
- Embodiment S A method of compressing a multiphase fluid comprising the steps of: providing a slug suppressor or an atomizing device;
- Embodiment T A method of compressing a multiphase fluid including liquid and gas components comprising the steps of:
- Embodiment U A method of expanding a pressurized multiphase fluid comprising the steps of:
- Embodiment V A method of expanding a pressurized multiphase fluid including liquid and gas components comprising the steps of:
- Embodiment W The method of embodiment S, further comprising the step of directing the multiphase fluid through a flow mixer prior to its being compressed.
- Embodiment X The method of embodiment S, wherein the compressor is a centrifugal compressor.
- Embodiment Y The method of embodiment S, further comprising the step of using an electric or gas motor, gas or steam turbine, expander, hydraulic turbine or other driving device to provide power to the compressor.
- Embodiment Z The apparatus of embodiment T, further comprising a means for controlling the compressor speed based on produced torque, load, fluid density, multiphase flow measurement or output power.
- Embodiment AA Apparatus for compressing a multiphase fluid comprising:
- an atomizing device connected to the first conduit; a compressor connected to an output of the atomizing device; and a distribution conduit connected to the compressor for conveying the compressed multiphase fluid to a desire location.
- Embodiment BB The apparatus of embodiment AA, wherein the atomizing device comprises one or more atomizing nozzles or a flow mixer connected to the first conduit.
- Embodiment CC The apparatus of embodiment AA or BB, further comprising an electric or gas motor, gas or steam turbine, expander, hydraulic turbine or other driving device to provide power to the compressor.
- Embodiment DD The apparatus of any of embodiments AA-CC, further comprising means for controlling the speed of the compressor based on torque, load, fluid density, GVF or input power.
- Embodiment EE Apparatus for expanding a multiphase fluid comprising:
- an expander connected to an output of the atomizing device; and a distribution conduit connected to the expander for conveying the expanded multiphase fluid to a desired location.
- Embodiment FF The apparatus of embodiment EE, further comprising a slug suppressor connected to the first conduit.
- Embodiment GG The apparatus of embodiment EE or FF, further comprising means for controlling the speed of the expander or the driven equipment based on torque produced, load, fluid density, multiphase flow measurement, GVF or output power.
- Embodiment HH The apparatus of any of embodiments EE-GG, further comprising a generator or compressor connected to a power output shaft of the expander.
- Embodiment II The apparatus of embodiment HH, further comprising a bypass conduit connected at one end to the output of the expander and at its other end to the first conduit.
- Embodiment JJ The apparatus of embodiment II, further comprising a bypass valve in the bypass conduit.
- Embodiment KK The apparatus of any of embodiment EE-JJ, wherein the atomizing device is a flow mixer or one or more atomizing nozzles.
- Embodiment LL The apparatus of any of embodiments E, R, Y, or DD wherein the means for monitoring or controlling a stated parameter is comprised of a torque sensor, a load sensor, a fluid density sensor, a multiphase flow meter, an input power sensor, a torque converter, a computerized control system, an inlet or outlet control valve, recycle valve, a variable speed drive, a permanent magnet motor or other similar device.
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- Engineering & Computer Science (AREA)
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- Physics & Mathematics (AREA)
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- Structures Of Non-Positive Displacement Pumps (AREA)
Abstract
Description
Claims
Priority Applications (8)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CN201080053215.XA CN102667017B (en) | 2009-11-25 | 2010-10-22 | Use the centrifugal moisture compression of slug TVS and/or atomizer or expand |
JP2012541083A JP5763667B2 (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion using slag suppressor and / or atomizer |
AU2010325127A AU2010325127B2 (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer |
BR112012012489-7A BR112012012489B1 (en) | 2009-11-25 | 2010-10-22 | CENTRIFUGAL COMPRESSION OF MOIST GAS OR EXPANSION WITH A STRIP SUPPRESSOR AND/OR ATOMIZER |
CA2777868A CA2777868C (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer |
RU2012126170/13A RU2552083C2 (en) | 2009-11-25 | 2010-10-22 | Centrifugal compression of moist gas or expansion with device of protection against liquid piston and/or spray device |
US13/500,534 US20120224980A1 (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer |
EP10833743.7A EP2504497B1 (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US26441409P | 2009-11-25 | 2009-11-25 | |
US61/264,414 | 2009-11-25 |
Publications (1)
Publication Number | Publication Date |
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WO2011066050A1 true WO2011066050A1 (en) | 2011-06-03 |
Family
ID=44066848
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2010/053774 WO2011066050A1 (en) | 2009-11-25 | 2010-10-22 | Centrifugal wet gas compression or expansion with a slug suppressor and/or atomizer |
Country Status (10)
Country | Link |
---|---|
US (1) | US20120224980A1 (en) |
EP (1) | EP2504497B1 (en) |
JP (1) | JP5763667B2 (en) |
CN (1) | CN102667017B (en) |
AU (1) | AU2010325127B2 (en) |
BR (1) | BR112012012489B1 (en) |
CA (1) | CA2777868C (en) |
RU (1) | RU2552083C2 (en) |
SG (1) | SG10201407025TA (en) |
WO (1) | WO2011066050A1 (en) |
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GB2493749A (en) * | 2011-08-17 | 2013-02-20 | Statoil Petroleum As | Subsea well stream processing |
WO2013070547A1 (en) * | 2011-11-08 | 2013-05-16 | Dresser-Rand Company | Compact turbomachine system with improved slug flow handling |
WO2016153626A1 (en) * | 2015-03-26 | 2016-09-29 | Exxonmobil Upstream Research Company | Method of controlling a compressor system and compressor system |
WO2016180763A1 (en) * | 2015-05-14 | 2016-11-17 | Vetco Gray Scandinavia As | A control system for controlling a subsea gas compression system |
US9915134B2 (en) | 2013-06-24 | 2018-03-13 | Saudi Arabian Oil Company | Integrated pump and compressor and method of producing multiphase well fluid downhole and at surface |
GB2584079A (en) * | 2019-05-13 | 2020-11-25 | Equinor Energy As | A method and system for preparing a fluid produced at an offshore production facility for transportation |
EP3274593B1 (en) * | 2015-03-26 | 2021-03-24 | ExxonMobil Upstream Research Company | Wet gas compression |
US11224900B2 (en) | 2017-01-17 | 2022-01-18 | Equinor Energy As | Gas compressor cleaning |
US11371326B2 (en) | 2020-06-01 | 2022-06-28 | Saudi Arabian Oil Company | Downhole pump with switched reluctance motor |
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US11644351B2 (en) | 2021-03-19 | 2023-05-09 | Saudi Arabian Oil Company | Multiphase flow and salinity meter with dual opposite handed helical resonators |
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US11994016B2 (en) | 2021-12-09 | 2024-05-28 | Saudi Arabian Oil Company | Downhole phase separation in deviated wells |
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US11022595B2 (en) | 2015-06-26 | 2021-06-01 | Statoil Petroleum As | Determining the phase composition of a fluid flow |
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US20230191311A1 (en) * | 2021-12-22 | 2023-06-22 | Uop Llc | Processes and apparatuses for operating a gas compressor |
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- 2010-10-22 SG SG10201407025TA patent/SG10201407025TA/en unknown
- 2010-10-22 WO PCT/US2010/053774 patent/WO2011066050A1/en active Application Filing
- 2010-10-22 BR BR112012012489-7A patent/BR112012012489B1/en active IP Right Grant
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US9303498B2 (en) | 2011-08-17 | 2016-04-05 | Statoil Petroleum As | Subsea compression |
GB2493749B (en) * | 2011-08-17 | 2016-04-13 | Statoil Petroleum As | Improvements relating to subsea compression |
GB2493749A (en) * | 2011-08-17 | 2013-02-20 | Statoil Petroleum As | Subsea well stream processing |
WO2013070547A1 (en) * | 2011-11-08 | 2013-05-16 | Dresser-Rand Company | Compact turbomachine system with improved slug flow handling |
EP2776720A4 (en) * | 2011-11-08 | 2015-05-20 | Dresser Rand Co | Compact turbomachine system with improved slug flow handling |
US10677031B2 (en) | 2013-06-24 | 2020-06-09 | Saudi Arabian Oil Company | Integrated pump and compressor and method of producing multiphase well fluid downhole and at surface |
US9915134B2 (en) | 2013-06-24 | 2018-03-13 | Saudi Arabian Oil Company | Integrated pump and compressor and method of producing multiphase well fluid downhole and at surface |
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Also Published As
Publication number | Publication date |
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CA2777868C (en) | 2018-07-31 |
SG10201407025TA (en) | 2014-12-30 |
BR112012012489A2 (en) | 2020-08-11 |
EP2504497A1 (en) | 2012-10-03 |
JP2013512089A (en) | 2013-04-11 |
BR112012012489B1 (en) | 2021-06-29 |
CN102667017A (en) | 2012-09-12 |
AU2010325127A1 (en) | 2012-06-07 |
CA2777868A1 (en) | 2011-06-03 |
US20120224980A1 (en) | 2012-09-06 |
CN102667017B (en) | 2015-08-19 |
EP2504497A4 (en) | 2018-04-18 |
EP2504497B1 (en) | 2019-05-22 |
RU2552083C2 (en) | 2015-06-10 |
RU2012126170A (en) | 2013-12-27 |
JP5763667B2 (en) | 2015-08-12 |
AU2010325127B2 (en) | 2016-04-28 |
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