WO2012158522A2 - Separation system to separate phases of downhole fluids for individual analysis - Google Patents
Separation system to separate phases of downhole fluids for individual analysis Download PDFInfo
- Publication number
- WO2012158522A2 WO2012158522A2 PCT/US2012/037531 US2012037531W WO2012158522A2 WO 2012158522 A2 WO2012158522 A2 WO 2012158522A2 US 2012037531 W US2012037531 W US 2012037531W WO 2012158522 A2 WO2012158522 A2 WO 2012158522A2
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- fluid
- phase
- phases
- separated
- vessel
- Prior art date
Links
- 239000012530 fluid Substances 0.000 title claims abstract description 86
- 238000000926 separation method Methods 0.000 title description 34
- 238000004458 analytical method Methods 0.000 title description 5
- 238000004891 communication Methods 0.000 claims abstract description 5
- 230000006854 communication Effects 0.000 claims abstract description 5
- 238000005070 sampling Methods 0.000 claims abstract description 5
- 239000012071 phase Substances 0.000 claims description 86
- 238000000034 method Methods 0.000 claims description 13
- 239000000463 material Substances 0.000 claims description 10
- 229930195733 hydrocarbon Natural products 0.000 claims description 9
- 150000002430 hydrocarbons Chemical class 0.000 claims description 9
- 239000004215 Carbon black (E152) Substances 0.000 claims description 8
- 239000007788 liquid Substances 0.000 claims description 8
- 239000000126 substance Substances 0.000 claims description 7
- 230000007613 environmental effect Effects 0.000 claims description 6
- 230000003993 interaction Effects 0.000 claims description 5
- 239000008346 aqueous phase Substances 0.000 claims description 2
- 239000007787 solid Substances 0.000 claims description 2
- 238000007599 discharging Methods 0.000 claims 1
- 230000004001 molecular interaction Effects 0.000 claims 1
- 230000010399 physical interaction Effects 0.000 claims 1
- 239000002244 precipitate Substances 0.000 claims 1
- 230000015572 biosynthetic process Effects 0.000 description 15
- 238000005755 formation reaction Methods 0.000 description 15
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 13
- 239000012528 membrane Substances 0.000 description 7
- 238000013500 data storage Methods 0.000 description 5
- 238000004128 high performance liquid chromatography Methods 0.000 description 5
- 239000000203 mixture Substances 0.000 description 4
- 239000000523 sample Substances 0.000 description 4
- 239000011324 bead Substances 0.000 description 3
- 238000004821 distillation Methods 0.000 description 3
- 238000005553 drilling Methods 0.000 description 3
- 230000002209 hydrophobic effect Effects 0.000 description 3
- 230000015654 memory Effects 0.000 description 3
- 239000011148 porous material Substances 0.000 description 3
- 238000012360 testing method Methods 0.000 description 3
- 238000010521 absorption reaction Methods 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 238000004587 chromatography analysis Methods 0.000 description 2
- 238000001816 cooling Methods 0.000 description 2
- 238000011161 development Methods 0.000 description 2
- 238000011156 evaluation Methods 0.000 description 2
- 238000004191 hydrophobic interaction chromatography Methods 0.000 description 2
- 238000004255 ion exchange chromatography Methods 0.000 description 2
- 238000005259 measurement Methods 0.000 description 2
- 230000005526 G1 to G0 transition Effects 0.000 description 1
- 230000005679 Peltier effect Effects 0.000 description 1
- 229910052797 bismuth Inorganic materials 0.000 description 1
- JCXGWMGPZLAOME-UHFFFAOYSA-N bismuth atom Chemical compound [Bi] JCXGWMGPZLAOME-UHFFFAOYSA-N 0.000 description 1
- 238000004090 dissolution Methods 0.000 description 1
- 238000001641 gel filtration chromatography Methods 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 238000011835 investigation Methods 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 230000005055 memory storage Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 230000003287 optical effect Effects 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 238000005191 phase separation Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000009257 reactivity Effects 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000000717 retained effect Effects 0.000 description 1
- 238000001542 size-exclusion chromatography Methods 0.000 description 1
- 230000003075 superhydrophobic effect Effects 0.000 description 1
- XSOKHXFFCGXDJZ-UHFFFAOYSA-N telluride(2-) Chemical compound [Te-2] XSOKHXFFCGXDJZ-UHFFFAOYSA-N 0.000 description 1
- 230000035899 viability Effects 0.000 description 1
Classifications
-
- 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
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/35—Arrangements for separating materials produced by the well specially adapted for separating solids
-
- 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
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/38—Arrangements for separating materials produced by the well in the well
-
- 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
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
Definitions
- This disclosure pertains generally to investigations of underground formations and more particularly to systems and methods for evaluating downhole fluids.
- the present disclosure addresses the need to separate one or more phases of a downhole fluid.
- the present disclosure provides an apparatus for sampling a fluid in a borehole.
- the apparatus may include a vessel configured to be disposed in a borehole, the vessel being further configured to separate the fluid into a plurality of phases without substantially affecting a structure of at least one of the separated phases; and at least one sensor in communication with one phase of the plurality of phases in the vessel.
- the present disclosure provides a method for sampling a fluid in a borehole. The method may include separating the fluid into a plurality of phases in a vessel positioned in the borehole without substantially affecting a structure of at least one of the separated phases; and estimating a parameter of interest relating to at least one phase separated from the fluid while the at least one phase is in the vessel.
- FIG. 1 shows a schematic of a centrifugal-type of separator according to one embodiment of the present disclosure
- FIG. 2 shows a schematic of a thermal separator according to one embodiment of the present disclosure
- FIG. 3 shows a schematic of a separator that uses reactive surfaces according to one embodiment of the present disclosure
- FIG. 4 shows a schematic of a membrane-based separator according to one embodiment of the present disclosure
- FIG. 5 illustrates a schematic of a formation evaluation system that includes a separator according to one embodiment of the present disclosure.
- the present disclosure relates to devices and methods to evaluate downhole fluids.
- the term downhole fluid is generally any fluid found in a drilled wellbore and /or any fluid that resides in the formation.
- Downhole fluids include but are not limited to, naturally occurring fluids such as oil, gas, and water, as well as engineered fluids such as drilling fluids and surface injected fluids.
- the teachings may be advantageously applied to a variety of systems in the oil and gas industry, water wells, geothermal wells, surface applications and elsewhere. Merely for clarity, certain non-limiting embodiments will be discussed in the context of hydrocarbon producing wells.
- a test tool 100 that may be used to actively separate a fluid into two or more homogeneous materials or phases (e.g. , a polar phase, a nonpolar phase, an aqueous phase, a liquid hydrocarbon, a gas hydrocarbon, water, etc.).
- the separation may be performed without substantially affecting a structure of one or more of the substances making up the several phases. That is, after the separation, one or more than one of the separated phases still retains the same molecular structure as prior to the separation (e.g., minimal molecular dissolution or association).
- the pre- separation and post-separation phases are structurally similar.
- the tool 100 may be used to evaluate one or more characteristics of the separated phase(s) and also estimate one or more parameters relating to the separation process (e.g. , pressure, temperature, etc.).
- the tool 100 may include an inlet 102 through which a fluid 103 enters an active separation chamber 104 and outlets 106a,b through which the separated phases 107a,b exit the separation chamber 104.
- the tool 100 may include a variety of sensors configured to estimate one or more desired parameters. For example, a sensor 108a may be used to estimate a characteristic of a first phase component (e.g. , oil) , and a sensor 108b may be used to estimate a characteristic of a second phase component (e.g. , water). Other phase components (e.g.
- the test tool 100 may include a separator 110 that uses rotation to separate the fluid into two or more phase components.
- the separator 110 may include an enclosure 112, which may be drum-shaped, that is rotated by a suitable motor 114.
- the fluid 103 flows via the inlet 102 into the enclosure 112, which is rotated by the motor 114.
- the centrifugal forces generated by the rotating enclosure 112 separates phases based on relative density. In other embodiments, the separation may be performed independent of orientation.
- the relatively lighter phase 107a e.g. , oil
- the relatively denser phase 107b e.g. , water
- the enclosure 112 may be oriented to allow gravity to also separate the phases based on relative density.
- the tool 100 may include an orientation sensor (not shown) that provides an indication of verticality and an orientation device (not shown) that orients the device such that more dense phases collect at a particular location in the chamber 104.
- the sensors 108a-c may generate information relating to one or more parameters of the fluid 103, the separated phase components 107a,b and / or the environmental conditions associated with the tool 100.
- 'Information' may be data in any form and may be "raw” and / or "processed,” e.g. , direct measurements, indirect measurements, analog signal, digital signals, etc.
- the information provided by the sensors 108a,b is indicative of a state, condition, or property of the separated phase immediately after separation, but before the separated phase has exited the tool 100.
- the sensors 108c may provide information relating to the conditions under which the separation occurred.
- the tool 100 may provide information that includes at least a property of one or more separated components and the conditions that caused the separation.
- the sensors 108a,b may be configured to generate information regarding the chemical composition(s) or material properties(s) of the separated phases 107a,b.
- This information may relate to properties that include, but are not limited to, one or more of: (i) pH, (ii) H2S, (iii) density, (iv) viscosity, (v) thermal conductivity, (vi) electrical resistivity, (vii) chemical composition, (viii) reactivity, (ix) radiofrequency properties, (x) surface tension, (xi) infra-red absorption, (xii) ultraviolet absorption, (xiii) refractive index, and (xiv) rheological properties.
- the separation of the phase components may be performed by a number of different devices and techniques in addition to the centrifugal separator shown in Fig. 1.
- the tool 100 may include a cyclonic separator wherein the fluid 103 is spun in a spiral or helix-like manner in the chamber 104. Still other non-limiting embodiments of separators are discussed below.
- thermoelectric elements 124a,b may be used to remove heat from the fluid 123 in the column 122.
- a thermoelectric elements 124a,b may be formed of a suitable material (e.g., bismuth telluride) that when energized by an electrical circuit 126 transfers heat across a space against a temperature gradient (or Peltier effect).
- a suitable power source 128 may provide electrical power.
- heat may be applied by suitable heating elements to separate phases in the distillation column 122.
- electrostatic forces may be used to separate phase components based on the electric charge of the components.
- sensors 108a-c may be used to obtain desired information relating to the fluid and / or environment in the distillation column 122.
- a column 140 that includes one or more reactive column surfaces 142 that define a flow conduit 144 where the separator 140 is used for chromatographic purposes, e.g. , high performance liquid chromatography, ion exchange chromatography, hydrophobic interaction chromatography, gel filtration chromatography, and combinations thereof. Chromatography is used to separate phases of a liquid.
- the liquid i.e. , the mobile phase
- a column surface 142 i.e., the stationary phase.
- the column surfaces 142 may interact with a targeted phase of the fluid 146.
- the targeted phase of the fluid 146 interacts with the column surface 142 and is retained by the column surface 142, which allows the remainder of the fluid 146 to continue flowing through the column 140.
- the targeted phase of the fluid 146 is separated from the remainder of the fluid 146.
- Chromatography may be used by designing the column surfaces 142 to interact with the fluid 146 based on dipole-dipole interactions, ionic interactions or molecule sizes.
- sensors 108a-c may be used to obtain desired information relating to the fluid and / or environment in the flow conduit 144.
- the column surfaces 142 may attract oil or water (e.g. , lipophilic, hydrophobic, hydrophilic), cause a phase component to coalesce, and / or cause a desired flow regime.
- the surfaces may be a combination of hydrophilic and superhydrophobic surfaces that allow water to coalesce and then flow along a predefined channel. Similar combination of surface may be designed using oleophilic and oleophobic surfaces.
- the column surfaces 142 may be configured to operate according to HPLC (high performance liquid chromatography). HPLC is generally an automated system having fluids applied in a precise manner with controlled flow rates at high pressures.
- the column surfaces 142 may be a matrix of specially fabricated glass or plastic beads coated with a uniform layer of chromatographic material. HPLC allows for high speed, high resolution, and reproducibility of the separation.
- the column 140 may also be configured for ion exchange chromatography where oppositely charged molecules are bound to the column surfaces 142 to allow a targeted phase to be separated from the fluid 146.
- a targeted phase is water to be separated from the fluid 146
- charged or ionic molecules would be bound to the column surfaces 142. Water would bind to the ionic molecules and the remainder of the fluid 146 would flow through the column 140.
- the column 140 may also be configured for hydrophobic interaction chromatography where the column surfaces 142 are impregnated with nonpolar groups.
- the nonpolar groups may interact with the hydrophobic phase of the fluid 146, which causes the hydrophobic phase to bind to the column surfaces 142 and allows the charged phase to flow through the column 140.
- An embodiment of this may include the oil phase being separated from the fluid 146, so that the remainder of the fluid 146 flows through the column 140.
- the column 140 may be configured for size exclusion chromatography where molecules are separated according to the size and/or shape of the molecules within the targeted phase of the fluid 146. In this instance, the column surface 142 may have gel beads with pores of a specified size range.
- the pores may retain molecules of a particular wettability, size and/or shape of the fluid 146.
- an oil molecule is size-wise larger than a water molecule.
- the pores of the column surfaces 146 may be configured to be penetrable by water but relatively impenetrable by oil. Such a column surface 142 then would retain water but allow the oil to flow through the column 140.
- a separator 160 that includes a permeable material 162 that separates a chamber 164 into a pre-separation section 166 and a post-separation section 168.
- the material may be a membrane 162 that has a permeability selected to allow passage of only a selected phase component (e.g. , a hydrocarbon).
- a piston 170 or other suitable movable member reduces the volume in the pre-separation section 166 to generate a pressure differential that forces the selected phase component through the membrane 162 and into the post-separation section 168.
- a vacuum pump (not shown) may be used to reduce pressure in the post-separation section 168.
- the material 162 may be beads, or a sponge-like material.
- sensors 108a-c may be used to obtain desired information relating to the fluid and / or environment in the membrane separator 160.
- Other embodiments of using membrane separation may use pistons or other pressurizing mechanisms to force the fluid through a membrane which selectively filters molecules.
- the membrane may be porous, micro-porous, or nano-porous.
- the above illustrative separation techniques separate the phases without substantially affecting a structure of one or more of the substances making up the several phases. Separation processes involving pressure reduction below bubble point or cooling can cause condensate to in a liquid. However, the liquid and / or the condensate in those processes may undergo a chemical structural change that may make it difficult or impossible to acquire information relating to the fluid prior to such a separation process.
- the separation techniques of the present disclosure retain the pre- separation structure of phase substance(s) even after separation.
- Fig. 5 schematically illustrates a wellbore system 10 deployed from a rig 12 into a borehole 14. While a land-based rig 12 is shown, it should be understood that the present disclosure may be applicable to offshore rigs and subsea formations.
- the wellbore system 10 may include a carrier 16 and a wellbore tool 20.
- the wellbore tool 20 is shown as a fluid analysis tool.
- the fluid analysis tool 20 may include a probe 22 that contacts a borehole wall 24 for extracting formation fluid from a formation 26. Extendable pads or ribs 28 may be used to laterally thrust the probe 22 against the borehole wall 24.
- the fluid analysis tool 20 may include a pump 30 that pumps formation fluid from formation 26 via the probe 22. Formation fluid travels along a flow line to one or more sample containers 32 or to line 34 from which the formation fluid exits to the borehole 14.
- the fluid may have one or more pre-existing phase components (i.e., that exist prior to separation).
- the tool 20 may include a separator 100 as described previously to separate one or more phase components from the fluid extracted from the formation 26.
- a programmable controller may be used to control one or more aspects of the operation of the tool 20.
- the wellbore system 10 may include a surface controller 40 and / or a downhole controller 42.
- the tool 20 is positioned downhole and operated to extract fluid from the formation 26.
- the fluid from the formation may be a multi-phase fluid.
- the separator tool 100 separates at least one phase from the extracted fluid.
- the sensors 108a,b estimate one or more phase properties of the separated phases before the separated fluids have exited the separator tool 100.
- the sensors 108a,b provide information about the post-separated phase(s) that may be used to characterize the properties of the phases prior to separation.
- the sensors 108c acquire information that can be used to evaluate the environmental conditions under which the phase separation occurred.
- the wellbore system 10 may be a drilling system that configured to form the borehole 14 using tools such as a drill bit (not shown).
- the carrier 16 may be a coiled tube, casing, liners, drill pipe, etc.
- the wellbore system 10 may use a non-rigid carrier.
- the carrier 16 may be wirelines, wireline sondes, slickline sondes, e-lines, etc.
- carrier as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support, or otherwise facilitate the use of another device, device component, combination of devices, media and/or member.
- the controller 40, 42 may include an information processor that is in data communication with a data storage medium and a processor memory.
- the data storage medium may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical disks, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage.
- the data storage medium may store one or more programs that when executed causes information processor to execute the disclosed method(s). Signals indicative of the parameter may be transmitted to a surface controller 40. These signals may also, or in the alternative, be stored downhole in a data storage device and may also be processed. In one example, wired pipe may be used for transmitting information.
- carrier means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member.
- fluid and “fluids” refers to one or gasses, one or more liquids, and mixtures thereof.
Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
BR112013024360A BR112013024360A2 (en) | 2011-05-13 | 2012-05-11 | separation system for separating wellbore fluid phases for individual analysis |
GB1313358.2A GB2501042A (en) | 2011-05-13 | 2012-05-11 | Separation system to separate phases of downhole fluids for individual analysis |
NO20131069A NO20131069A1 (en) | 2011-05-13 | 2013-08-06 | Separation system to separate phases of downhole fluids for individual analysis |
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201161485961P | 2011-05-13 | 2011-05-13 | |
US61/485,961 | 2011-05-13 | ||
US13/468,951 US20120285680A1 (en) | 2011-05-13 | 2012-05-10 | Separation system to separate phases of downhole fluids for individual analysis |
US13/468,951 | 2012-05-10 |
Publications (2)
Publication Number | Publication Date |
---|---|
WO2012158522A2 true WO2012158522A2 (en) | 2012-11-22 |
WO2012158522A3 WO2012158522A3 (en) | 2013-01-31 |
Family
ID=47141095
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2012/037531 WO2012158522A2 (en) | 2011-05-13 | 2012-05-11 | Separation system to separate phases of downhole fluids for individual analysis |
Country Status (5)
Country | Link |
---|---|
US (1) | US20120285680A1 (en) |
BR (1) | BR112013024360A2 (en) |
GB (1) | GB2501042A (en) |
NO (1) | NO20131069A1 (en) |
WO (1) | WO2012158522A2 (en) |
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10787872B1 (en) | 2019-10-11 | 2020-09-29 | Halliburton Energy Services, Inc. | Graphene oxide coated membranes to increase the density of water base fluids |
US10919781B1 (en) | 2019-10-11 | 2021-02-16 | Halliburton Energy Services, Inc. | Coated porous substrates for fracking water treatment |
Families Citing this family (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9181799B1 (en) * | 2012-06-21 | 2015-11-10 | The United States of America, as represented by the Secretary of the Department of the Interior | Fluid sampling system |
WO2015026394A1 (en) * | 2013-08-22 | 2015-02-26 | Halliburton Energy Services, Inc. | On-site mass spectrometry for liquid and extracted gas analysis of drilling fluids |
US11333017B2 (en) | 2019-04-03 | 2022-05-17 | Schlumberger Technology Corporation | System and method for fluid separation |
US11156085B2 (en) * | 2019-10-01 | 2021-10-26 | Saudi Arabian Oil Company | System and method for sampling formation fluid |
US11591890B2 (en) * | 2021-01-21 | 2023-02-28 | Baker Hughes Oilfield Operations Llc | Method and apparatus for producing hydrocarbon |
NO347746B1 (en) * | 2022-03-28 | 2024-03-11 | Affin As | Assembly for generating electricity in a production well of a hot fluid |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7644611B2 (en) * | 2006-09-15 | 2010-01-12 | Schlumberger Technology Corporation | Downhole fluid analysis for production logging |
WO2010020435A1 (en) * | 2008-08-22 | 2010-02-25 | Services Petroliers Schlumberger | Universal flash system and apparatus for petroleum reservoir fluids study |
US20100089569A1 (en) * | 2007-03-19 | 2010-04-15 | Van Zuilekom Anthony H | Separator for downhole measuring and method therefor |
US20100192684A1 (en) * | 2009-02-02 | 2010-08-05 | Xu Wu | Phase separation detection in downhole fluid sampling |
Family Cites Families (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB2363809B (en) * | 2000-06-21 | 2003-04-02 | Schlumberger Holdings | Chemical sensor for wellbore applications |
US7195063B2 (en) * | 2003-10-15 | 2007-03-27 | Schlumberger Technology Corporation | Downhole sampling apparatus and method for using same |
-
2012
- 2012-05-10 US US13/468,951 patent/US20120285680A1/en not_active Abandoned
- 2012-05-11 GB GB1313358.2A patent/GB2501042A/en not_active Withdrawn
- 2012-05-11 BR BR112013024360A patent/BR112013024360A2/en not_active IP Right Cessation
- 2012-05-11 WO PCT/US2012/037531 patent/WO2012158522A2/en active Application Filing
-
2013
- 2013-08-06 NO NO20131069A patent/NO20131069A1/en unknown
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7644611B2 (en) * | 2006-09-15 | 2010-01-12 | Schlumberger Technology Corporation | Downhole fluid analysis for production logging |
US20100089569A1 (en) * | 2007-03-19 | 2010-04-15 | Van Zuilekom Anthony H | Separator for downhole measuring and method therefor |
WO2010020435A1 (en) * | 2008-08-22 | 2010-02-25 | Services Petroliers Schlumberger | Universal flash system and apparatus for petroleum reservoir fluids study |
US20100192684A1 (en) * | 2009-02-02 | 2010-08-05 | Xu Wu | Phase separation detection in downhole fluid sampling |
Cited By (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10787872B1 (en) | 2019-10-11 | 2020-09-29 | Halliburton Energy Services, Inc. | Graphene oxide coated membranes to increase the density of water base fluids |
US10919781B1 (en) | 2019-10-11 | 2021-02-16 | Halliburton Energy Services, Inc. | Coated porous substrates for fracking water treatment |
WO2021071526A1 (en) * | 2019-10-11 | 2021-04-15 | Halliburton Energy Services, Inc. | Graphene oxide coated membranes to increase the density of water base fluids |
US11041348B2 (en) | 2019-10-11 | 2021-06-22 | Halliburton Energy Services, Inc. | Graphene oxide coated membranes to increase the density of water base fluids |
GB2603298A (en) * | 2019-10-11 | 2022-08-03 | Halliburton Energy Services Inc | Graphene oxide coated membranes to increase the density of water base fluids |
GB2603298B (en) * | 2019-10-11 | 2023-09-06 | Halliburton Energy Services Inc | Graphene oxide coated membranes to increase the density of water base fluids |
Also Published As
Publication number | Publication date |
---|---|
NO20131069A1 (en) | 2013-09-02 |
BR112013024360A2 (en) | 2016-12-20 |
GB201313358D0 (en) | 2013-09-11 |
WO2012158522A3 (en) | 2013-01-31 |
US20120285680A1 (en) | 2012-11-15 |
GB2501042A (en) | 2013-10-09 |
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