US20010007283A1 - Method for boosting hydrocarbon production - Google Patents

Method for boosting hydrocarbon production Download PDF

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Publication number
US20010007283A1
US20010007283A1 US09/756,350 US75635001A US2001007283A1 US 20010007283 A1 US20010007283 A1 US 20010007283A1 US 75635001 A US75635001 A US 75635001A US 2001007283 A1 US2001007283 A1 US 2001007283A1
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United States
Prior art keywords
raw water
production
downhole
pump
hydraulic power
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
Application number
US09/756,350
Inventor
Kashmir Johal
Timothy Lower
Simon Dawson
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.)
Mentor Subsea Technology Services Inc
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Individual
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
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Assigned to MENTOR SUBSEA TECHNOLOGY SERVICES, INC. reassignment MENTOR SUBSEA TECHNOLOGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: JOHAL, KASHMIR SINGH, LOWER, TIMOTHY MILES, DAWSON, SIMON GERALD BAILEY
Publication of US20010007283A1 publication Critical patent/US20010007283A1/en
Abandoned legal-status Critical Current

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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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water
    • 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
    • E21B43/121—Lifting well fluids
    • E21B43/129—Adaptations of down-hole pump systems powered by fluid supplied from outside the borehole
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
    • F04F—PUMPING OF FLUID BY DIRECT CONTACT OF ANOTHER FLUID OR BY USING INERTIA OF FLUID TO BE PUMPED; SIPHONS
    • F04F1/00—Pumps using positively or negatively pressurised fluid medium acting directly on the liquid to be pumped
    • F04F1/18—Pumps using positively or negatively pressurised fluid medium acting directly on the liquid to be pumped the fluid medium being mixed with, or generated from the liquid to be pumped
    • F04F1/20—Pumps using positively or negatively pressurised fluid medium acting directly on the liquid to be pumped the fluid medium being mixed with, or generated from the liquid to be pumped specially adapted for raising liquids from great depths, e.g. in wells

Definitions

  • the invention is generally related to the production of oil and more particularly to the injection of water into an oil bearing formation.
  • the raw water provides the hydraulic power to the downhole equipment via the production well annulus in an open loop arrangement.
  • the raw water is co-mingled with the production fluids.
  • the raw water provides the hydraulic power to the downhole equipment via the production well annulus in a closed loop arrangement.
  • the raw water is not co-mingled with the production fluids.
  • the raw water provides hydraulic power to the downhole equipment via the production well annulus in an open loop downhole arrangement.
  • the raw water discharged from the turbine is conveyed to a suitable formation for injection via a dual completion well.
  • FIG. 1 is a schematic illustration of the preferred embodiment of the invention.
  • FIG. 2 is a longitudinal cross section at the mid-plane of the hydraulic submersible pump used in the preferred embodiment of FIG. 1.
  • FIG. 3 is a schematic illustration of an alternate embodiment of the invention.
  • FIG. 4 is a longitudinal cross section at the mid-plane of the hydraulic submersible pump used in the alternate embodiment of FIG. 3.
  • FIG. 5 is a schematic illustration of a second alternate embodiment of the invention.
  • FIG. 1 schematically illustrates the preferred embodiment of the invention.
  • the existing raw water processing and injection system 12 is used to process sea water and provide the processed water for injection into the oil bearing formation below the sea floor via piping 14 in fluid communication with the wellheads 15 and the water injection wells 16 .
  • the wellheads 15 are located at the sea floor 17 .
  • the processed sea water is also used to provide the motive hydraulic power to the downhole equipment 18 via piping 20 in fluid communication with the wellheads 21 and the production well annulus 22 .
  • the production wells are indicated by numeral 19 .
  • the raw water power fluid is co-mingled with the production fluids and transported to a receiving/processing facility not shown via piping 24 .
  • the piping 24 may be above or below the water surface.
  • the wellhead 15 includes a power fluid isolation valve 28 , and a production master valve 30 .
  • Tubing hanger 32 supports production tubing 34 .
  • Casing hanger 36 supports casing 38 .
  • the production tubing 34 is preferably equipped with ported landing nipples 40 that enable the hydraulic submersible pump assembly 42 to be installed by wireline, landed, and locked in position.
  • a sealing packer 44 positioned between the lower end of the tubing assembly 34 and the casing 38 directs the flow of production fluids into the pump assembly and isolates the power fluid.
  • a safety valve 46 is provided at the lower end of the pump assembly 42 . The safety valve 46 is controlled from the surface for shutting off the flow of production fluids if necessary.
  • power fluid locally generated and processed sea water, from the processing system 12 is directed through the power fluid valve 28 into the annulus between the tubing 34 and casing 38 .
  • the power fluid enters the pump assembly at the flow crossover 48 .
  • Downhole pump assemblies are generally known but the operation will be briefly described for the sake of clarity.
  • the power fluid flows through the pump assembly 42 to the turbine and causes the turbine and pump to spin.
  • the pump provides power to help pull the production fluids from the formation.
  • the production fluids exit the pump assembly at the pump discharge outlets 52 where they are co-mingled with the power fluid.
  • the power fluid exits the pump assembly at the turbine exhaust ports 50 into the annulus between the pump assembly and production tubing.
  • the co-mingled production fluid and power fluid flows back into the pump assembly below the flow crossover 48 .
  • the co-mingled fluids exit the pump assembly into the production tubing 34 and flow up the tubing to the production master valve 30 and into the piping 24 seen in FIG. 1.
  • the piping 24 delivers the co-mingled production and power fluids to a receiving/processing facility not shown.
  • FIG. 3 schematically illustrates an alternate embodiment of the invention.
  • the raw water power fluid is not co-mingled with the production fluid but instead is exhausted via piping 54 to the raw water processing and injection system 12 for reprocessing and injection into the reservoir.
  • a second, smaller diameter casing 56 is provided in the annulus between the first casing 38 and the production tubing 34 . This defines an annulus between the production tubing 34 and the second casing 56 and an annulus between the first casing 38 and the second casing 56 .
  • the power fluid isolation valve 28 is in fluid communication with the annulus between the production tubing 34 and the second casing 56 .
  • the wellhead includes a turbine exhaust valve 58 which is in fluid communication with the annulus between the first casing 38 and the second casing 56 .
  • the second casing 56 is provided with seals 60 that seal against the production tubing 34 and direct the crossover of power fluid to the production tubing annulus and into the pump assembly 42 .
  • the turbine exhaust 50 directs the power fluid into the annulus between the casing 38 and the second inner casing 56 .
  • power fluid processed sea water
  • the power fluid enters the pump assembly at the flow crossover 48 .
  • Downhole pump assemblies are generally known but the operation will be briefly described for the sake of clarity.
  • the power fluid flows through the pump assembly 42 to the turbine and causes the turbine and pump to spin.
  • the pump provides power to help pull the production fluids from the formation.
  • the production fluids exit the pump assembly at the pump discharge outlets 52 into the annulus between the production tubing 34 and the second casing 56 .
  • the production fluids then reenter the pump assembly before the crossover 48 and then exit the pump assembly into the production tubing 34 .
  • the production fluids flow up through the production tubing 34 and through the master production valve to the piping 24 seen in FIG. 3.
  • the piping 24 delivers the production fluids to a receiving/processing facility not shown.
  • the power fluid exits the turbine exhaust 50 into the annulus between the first and second casings 38 and 56 and flows to the turbine exhaust valve 58 .
  • the power fluid is then directed via piping 54 to the raw water processing and injection system where it is reprocessed and injected into the reservoir.
  • FIG. 5 schematically illustrates an alternate embodiment of the invention.
  • the raw water power fluid is not co-mingled with the production but instead is directed to a suitable formation for injection via a dual completion well 62 .
  • the main operation is the same as that described for FIG. 3 and 4 .
  • the difference is that the power fluid from turbine exhaust valve 58 is directed to water injection line 64 for injection into the oil bearing formation.

Abstract

An apparatus and method that uses the local raw water injection equipment to use the minimally processed seawater as the hydraulic power fluid for the downhole turbine/pump arrangement. In one embodiment, the raw water provides the hydraulic power to the downhole equipment via the production well annulus in an open loop arrangement. The raw water is co-mingled with the production fluids. In another embodiment, the raw water provides the hydraulic power to the downhole equipment via the production well annulus in a closed loop arrangement. The raw water is not co-mingled with the production fluids. In another embodiment, the raw water provides hydraulic power to the downhole equipment via the production well annulus in an open loop downhole arrangement. The raw water discharged from the turbine is conveyed to a suitable formation for injection via a dual completion well.

Description

    BACKGROUND OF THE INVENTION
  • 1. Field of the Invention [0001]
  • The invention is generally related to the production of oil and more particularly to the injection of water into an oil bearing formation. [0002]
  • 2. General Background [0003]
  • In the production of oil, it is often necessary to boost the pressure of the produced fluids in order to achieve the required production rates. Current downhole pressure boosting methods include the injection of water into the formation, well bore gas lift, electrical submersible pumps, and hydraulically driven, downhole turbine/pump arrangements. [0004]
    • SUMMARY OF THE INVENTION
  • What is provided is an apparatus and method which uses locally generated, minimally treated sea water (raw water) injection equipment to provide the hydraulic power fluid for a downhole turbine/pump arrangement. In one embodiment, the raw water provides the hydraulic power to the downhole equipment via the production well annulus in an open loop arrangement. The raw water is co-mingled with the production fluids. In another embodiment, the raw water provides the hydraulic power to the downhole equipment via the production well annulus in a closed loop arrangement. The raw water is not co-mingled with the production fluids. In another embodiment, the raw water provides hydraulic power to the downhole equipment via the production well annulus in an open loop downhole arrangement. The raw water discharged from the turbine is conveyed to a suitable formation for injection via a dual completion well. [0005]
    • BRIEF DESCRIPTION OF THE DRAWINGS
  • For a further understanding of the nature and objects of the present invention reference should be made to the following description, taken in conjunction with the accompanying drawings in which like parts are given like reference numerals, and wherein: [0006]
  • FIG. 1 is a schematic illustration of the preferred embodiment of the invention. [0007]
  • FIG. 2 is a longitudinal cross section at the mid-plane of the hydraulic submersible pump used in the preferred embodiment of FIG. 1. [0008]
  • FIG. 3 is a schematic illustration of an alternate embodiment of the invention. [0009]
  • FIG. 4 is a longitudinal cross section at the mid-plane of the hydraulic submersible pump used in the alternate embodiment of FIG. 3. [0010]
  • FIG. 5 is a schematic illustration of a second alternate embodiment of the invention. [0011]
    • DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
  • FIG. 1 schematically illustrates the preferred embodiment of the invention. The existing raw water processing and [0012] injection system 12 is used to process sea water and provide the processed water for injection into the oil bearing formation below the sea floor via piping 14 in fluid communication with the wellheads 15 and the water injection wells 16. The wellheads 15 are located at the sea floor 17. The processed sea water is also used to provide the motive hydraulic power to the downhole equipment 18 via piping 20 in fluid communication with the wellheads 21 and the production well annulus 22. The production wells are indicated by numeral 19. The raw water power fluid is co-mingled with the production fluids and transported to a receiving/processing facility not shown via piping 24. The piping 24 may be above or below the water surface.
  • As seen in FIG. 2, the [0013] wellhead 15 includes a power fluid isolation valve 28, and a production master valve 30. Tubing hanger 32 supports production tubing 34. Casing hanger 36 supports casing 38. The production tubing 34 is preferably equipped with ported landing nipples 40 that enable the hydraulic submersible pump assembly 42 to be installed by wireline, landed, and locked in position. A sealing packer 44 positioned between the lower end of the tubing assembly 34 and the casing 38 directs the flow of production fluids into the pump assembly and isolates the power fluid. A safety valve 46 is provided at the lower end of the pump assembly 42. The safety valve 46 is controlled from the surface for shutting off the flow of production fluids if necessary.
  • In operation, power fluid, locally generated and processed sea water, from the [0014] processing system 12 is directed through the power fluid valve 28 into the annulus between the tubing 34 and casing 38. The power fluid enters the pump assembly at the flow crossover 48. Downhole pump assemblies are generally known but the operation will be briefly described for the sake of clarity. The power fluid flows through the pump assembly 42 to the turbine and causes the turbine and pump to spin. The pump provides power to help pull the production fluids from the formation. The production fluids exit the pump assembly at the pump discharge outlets 52 where they are co-mingled with the power fluid. The power fluid exits the pump assembly at the turbine exhaust ports 50 into the annulus between the pump assembly and production tubing. The co-mingled production fluid and power fluid flows back into the pump assembly below the flow crossover 48. The co-mingled fluids exit the pump assembly into the production tubing 34 and flow up the tubing to the production master valve 30 and into the piping 24 seen in FIG. 1. As indicated above, the piping 24 delivers the co-mingled production and power fluids to a receiving/processing facility not shown.
  • FIG. 3 schematically illustrates an alternate embodiment of the invention. In this embodiment, the raw water power fluid is not co-mingled with the production fluid but instead is exhausted via [0015] piping 54 to the raw water processing and injection system 12 for reprocessing and injection into the reservoir.
  • As seen in FIG. 4, there are several differences from the embodiment of FIG. 2. A second, [0016] smaller diameter casing 56 is provided in the annulus between the first casing 38 and the production tubing 34. This defines an annulus between the production tubing 34 and the second casing 56 and an annulus between the first casing 38 and the second casing 56. The power fluid isolation valve 28 is in fluid communication with the annulus between the production tubing 34 and the second casing 56. The wellhead includes a turbine exhaust valve 58 which is in fluid communication with the annulus between the first casing 38 and the second casing 56. The second casing 56 is provided with seals 60 that seal against the production tubing 34 and direct the crossover of power fluid to the production tubing annulus and into the pump assembly 42. The turbine exhaust 50 directs the power fluid into the annulus between the casing 38 and the second inner casing 56.
  • In operation, power fluid (processed sea water) from the [0017] processing system 12 is directed through the power fluid valve 28 into the annulus between the tubing 34 and second casing 56. The power fluid enters the pump assembly at the flow crossover 48. Downhole pump assemblies are generally known but the operation will be briefly described for the sake of clarity. The power fluid flows through the pump assembly 42 to the turbine and causes the turbine and pump to spin. The pump provides power to help pull the production fluids from the formation. The production fluids exit the pump assembly at the pump discharge outlets 52 into the annulus between the production tubing 34 and the second casing 56. The production fluids then reenter the pump assembly before the crossover 48 and then exit the pump assembly into the production tubing 34. The production fluids flow up through the production tubing 34 and through the master production valve to the piping 24 seen in FIG. 3. As indicated above, the piping 24 delivers the production fluids to a receiving/processing facility not shown. The power fluid exits the turbine exhaust 50 into the annulus between the first and second casings 38 and 56 and flows to the turbine exhaust valve 58. The power fluid is then directed via piping 54 to the raw water processing and injection system where it is reprocessed and injected into the reservoir.
  • FIG. 5 schematically illustrates an alternate embodiment of the invention. In this embodiment, the raw water power fluid is not co-mingled with the production but instead is directed to a suitable formation for injection via a [0018] dual completion well 62.
  • The main operation is the same as that described for FIG. 3 and [0019] 4. The difference is that the power fluid from turbine exhaust valve 58 is directed to water injection line 64 for injection into the oil bearing formation.
  • Because many varying and differing embodiments may be made within the scope of the inventive concept herein taught and because many modifications may be made in the embodiment herein detailed in accordance with the descriptive requirement of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense. [0020]

Claims (3)

What is claimed as invention is:
1. A method for boosting production of hydrocarbons from a well in an oil bearing formation, comprising the steps of:
a. placing a hydraulic submersible pump in the well;
b. driving the hydraulic pump with locally generated and processed sea water; and
c. directing the water exhaust from the hydraulic pump into a common line with the produced hydrocarbons.
2. A method for boosting production of hydrocarbons from a well in an oil bearing formation, comprising the steps of:
a. placing a hydraulic submersible pump in the well;
b. driving the hydraulic pump with locally generated and processed sea water; and
c. directing the water exhaust from the hydraulic pump into a separate line from the hydrocarbons for reuse.
3. A method for boosting production of hydrocarbons from a well in an oil bearing formation, comprising the steps of:
a. placing a hydraulic submersible pump in the well;
b. driving the hydraulic pump with locally generated and processed water;
c. directing the water exhaust from the hydraulic pump into a separate line from the produced hydrocarbons; and
d. injecting the water exhaust from the hydraulic pump into the oil bearing formation.
US09/756,350 2000-01-12 2001-01-08 Method for boosting hydrocarbon production Abandoned US20010007283A1 (en)

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GB0000653A GB2358202A (en) 2000-01-12 2000-01-12 Methods for boosting hydrocarbon production
GB0000653.6 2000-01-12

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US20040129427A1 (en) * 2001-02-14 2004-07-08 Allan Sharp Downhole pump
US20040244987A1 (en) * 2003-06-04 2004-12-09 Crews Gregory A. Oil anchor
US20050167116A1 (en) * 2003-08-14 2005-08-04 Lima Goncalves Marcelo De Albuquerque Apparatus for production in oil wells
US20070187110A1 (en) * 2003-08-14 2007-08-16 Lima Goncalves Marcelo D A Method and apparatus for production in oil wells
US20080236839A1 (en) * 2007-03-27 2008-10-02 Schlumberger Technology Corporation Controlling flows in a well
US20090056939A1 (en) * 2007-08-30 2009-03-05 Schlumberger Technology Corporation Flow control device and method for a downhole oil-water separator
US20090217992A1 (en) * 2008-02-29 2009-09-03 Schlumberger Technology Corporation Subsea injection system
US20090242197A1 (en) * 2007-08-30 2009-10-01 Schlumberger Technology Corporation Flow control system and method for downhole oil-water processing
US20110067881A1 (en) * 2008-12-16 2011-03-24 Chevron U.S.A. Inc. System and method for delivering material to a subsea well
US8062400B2 (en) 2008-06-25 2011-11-22 Dresser-Rand Company Dual body drum for rotary separators
US8061972B2 (en) 2009-03-24 2011-11-22 Dresser-Rand Company High pressure casing access cover
US8061737B2 (en) 2006-09-25 2011-11-22 Dresser-Rand Company Coupling guard system
US8079805B2 (en) 2008-06-25 2011-12-20 Dresser-Rand Company Rotary separator and shaft coupler for compressors
US8079622B2 (en) 2006-09-25 2011-12-20 Dresser-Rand Company Axially moveable spool connector
US8087901B2 (en) 2009-03-20 2012-01-03 Dresser-Rand Company Fluid channeling device for back-to-back compressors
US8210804B2 (en) 2009-03-20 2012-07-03 Dresser-Rand Company Slidable cover for casing access port
US8231336B2 (en) 2006-09-25 2012-07-31 Dresser-Rand Company Fluid deflector for fluid separator devices
US8267437B2 (en) 2006-09-25 2012-09-18 Dresser-Rand Company Access cover for pressurized connector spool
US8302779B2 (en) 2006-09-21 2012-11-06 Dresser-Rand Company Separator drum and compressor impeller assembly
US8408879B2 (en) 2008-03-05 2013-04-02 Dresser-Rand Company Compressor assembly including separator and ejector pump
US8414692B2 (en) 2009-09-15 2013-04-09 Dresser-Rand Company Density-based compact separator
US8430433B2 (en) 2008-06-25 2013-04-30 Dresser-Rand Company Shear ring casing coupler device
US8434998B2 (en) 2006-09-19 2013-05-07 Dresser-Rand Company Rotary separator drum seal
US8596292B2 (en) 2010-09-09 2013-12-03 Dresser-Rand Company Flush-enabled controlled flow drain
US8657935B2 (en) 2010-07-20 2014-02-25 Dresser-Rand Company Combination of expansion and cooling to enhance separation
US8673159B2 (en) 2010-07-15 2014-03-18 Dresser-Rand Company Enhanced in-line rotary separator
US8733726B2 (en) 2006-09-25 2014-05-27 Dresser-Rand Company Compressor mounting system
US8746464B2 (en) 2006-09-26 2014-06-10 Dresser-Rand Company Static fluid separator device
US8821362B2 (en) 2010-07-21 2014-09-02 Dresser-Rand Company Multiple modular in-line rotary separator bundle
US9095856B2 (en) 2010-02-10 2015-08-04 Dresser-Rand Company Separator fluid collector and method

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US7207381B2 (en) * 2001-02-14 2007-04-24 Allan Sharp Downhole pump driven by injection water
US20040129427A1 (en) * 2001-02-14 2004-07-08 Allan Sharp Downhole pump
US20040244987A1 (en) * 2003-06-04 2004-12-09 Crews Gregory A. Oil anchor
US7000694B2 (en) 2003-06-04 2006-02-21 Crews Gregory A Oil anchor
US20060076143A1 (en) * 2003-06-04 2006-04-13 Crews Gregory A Oil anchor
US7594543B2 (en) * 2003-08-14 2009-09-29 Goncalves Marcelo De Albuquerqus Lima Method and apparatus for production in oil wells
US20050167116A1 (en) * 2003-08-14 2005-08-04 Lima Goncalves Marcelo De Albuquerque Apparatus for production in oil wells
US7249634B2 (en) * 2003-08-14 2007-07-31 Petroleo Brasileiro S.A. - Petrobras Apparatus for production in oil wells
US20070187110A1 (en) * 2003-08-14 2007-08-16 Lima Goncalves Marcelo D A Method and apparatus for production in oil wells
US8434998B2 (en) 2006-09-19 2013-05-07 Dresser-Rand Company Rotary separator drum seal
US8302779B2 (en) 2006-09-21 2012-11-06 Dresser-Rand Company Separator drum and compressor impeller assembly
US8079622B2 (en) 2006-09-25 2011-12-20 Dresser-Rand Company Axially moveable spool connector
US8061737B2 (en) 2006-09-25 2011-11-22 Dresser-Rand Company Coupling guard system
US8267437B2 (en) 2006-09-25 2012-09-18 Dresser-Rand Company Access cover for pressurized connector spool
US8231336B2 (en) 2006-09-25 2012-07-31 Dresser-Rand Company Fluid deflector for fluid separator devices
US8733726B2 (en) 2006-09-25 2014-05-27 Dresser-Rand Company Compressor mounting system
US8746464B2 (en) 2006-09-26 2014-06-10 Dresser-Rand Company Static fluid separator device
US20080236839A1 (en) * 2007-03-27 2008-10-02 Schlumberger Technology Corporation Controlling flows in a well
US8291979B2 (en) 2007-03-27 2012-10-23 Schlumberger Technology Corporation Controlling flows in a well
US8006757B2 (en) * 2007-08-30 2011-08-30 Schlumberger Technology Corporation Flow control system and method for downhole oil-water processing
US8327941B2 (en) * 2007-08-30 2012-12-11 Schlumberger Technology Corporation Flow control device and method for a downhole oil-water separator
US20090056939A1 (en) * 2007-08-30 2009-03-05 Schlumberger Technology Corporation Flow control device and method for a downhole oil-water separator
US20090242197A1 (en) * 2007-08-30 2009-10-01 Schlumberger Technology Corporation Flow control system and method for downhole oil-water processing
US20110000675A1 (en) * 2007-08-30 2011-01-06 Schlumberger Technology Corporation Flow control device and method for a downhole oil-water separator
US7814976B2 (en) * 2007-08-30 2010-10-19 Schlumberger Technology Corporation Flow control device and method for a downhole oil-water separator
US20090217992A1 (en) * 2008-02-29 2009-09-03 Schlumberger Technology Corporation Subsea injection system
US8961153B2 (en) * 2008-02-29 2015-02-24 Schlumberger Technology Corporation Subsea injection system
US8408879B2 (en) 2008-03-05 2013-04-02 Dresser-Rand Company Compressor assembly including separator and ejector pump
US8079805B2 (en) 2008-06-25 2011-12-20 Dresser-Rand Company Rotary separator and shaft coupler for compressors
US8430433B2 (en) 2008-06-25 2013-04-30 Dresser-Rand Company Shear ring casing coupler device
US8062400B2 (en) 2008-06-25 2011-11-22 Dresser-Rand Company Dual body drum for rotary separators
US20110067881A1 (en) * 2008-12-16 2011-03-24 Chevron U.S.A. Inc. System and method for delivering material to a subsea well
US8210804B2 (en) 2009-03-20 2012-07-03 Dresser-Rand Company Slidable cover for casing access port
US8087901B2 (en) 2009-03-20 2012-01-03 Dresser-Rand Company Fluid channeling device for back-to-back compressors
US8061972B2 (en) 2009-03-24 2011-11-22 Dresser-Rand Company High pressure casing access cover
US8414692B2 (en) 2009-09-15 2013-04-09 Dresser-Rand Company Density-based compact separator
US9095856B2 (en) 2010-02-10 2015-08-04 Dresser-Rand Company Separator fluid collector and method
US8673159B2 (en) 2010-07-15 2014-03-18 Dresser-Rand Company Enhanced in-line rotary separator
US8657935B2 (en) 2010-07-20 2014-02-25 Dresser-Rand Company Combination of expansion and cooling to enhance separation
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GB0000653D0 (en) 2000-03-01
NO20010146D0 (en) 2001-01-09
NO20010146L (en) 2001-07-13
BR0100053A (en) 2001-08-21
GB2358202A (en) 2001-07-18

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