WO2012009184A2 - Water sensitive porous medium to control downhole water production and method therefor - Google Patents
Water sensitive porous medium to control downhole water production and method therefor Download PDFInfo
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- WO2012009184A2 WO2012009184A2 PCT/US2011/042993 US2011042993W WO2012009184A2 WO 2012009184 A2 WO2012009184 A2 WO 2012009184A2 US 2011042993 W US2011042993 W US 2011042993W WO 2012009184 A2 WO2012009184 A2 WO 2012009184A2
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- copolymers
- water
- acrylamide
- solid particles
- crosslinked
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 101
- 238000000034 method Methods 0.000 title claims description 39
- 238000004519 manufacturing process Methods 0.000 title abstract description 23
- 229920000642 polymer Polymers 0.000 claims abstract description 82
- 239000002245 particle Substances 0.000 claims abstract description 62
- 239000007787 solid Substances 0.000 claims abstract description 38
- 239000012530 fluid Substances 0.000 claims abstract description 30
- 230000007423 decrease Effects 0.000 claims abstract description 6
- 229920001577 copolymer Polymers 0.000 claims description 35
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 claims description 28
- 239000000178 monomer Substances 0.000 claims description 28
- 239000011324 bead Substances 0.000 claims description 16
- 229920001519 homopolymer Polymers 0.000 claims description 16
- -1 polysiloxanes Polymers 0.000 claims description 13
- 239000000919 ceramic Substances 0.000 claims description 12
- 239000000203 mixture Substances 0.000 claims description 12
- 239000008188 pellet Substances 0.000 claims description 10
- NIXOWILDQLNWCW-UHFFFAOYSA-N 2-Propenoic acid Natural products OC(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-N 0.000 claims description 8
- QGZKDVFQNNGYKY-UHFFFAOYSA-O Ammonium Chemical compound [NH4+] QGZKDVFQNNGYKY-UHFFFAOYSA-O 0.000 claims description 8
- 239000012267 brine Substances 0.000 claims description 8
- 239000000945 filler Substances 0.000 claims description 8
- 229920001206 natural gum Polymers 0.000 claims description 8
- 229920001296 polysiloxane Polymers 0.000 claims description 8
- 229920002451 polyvinyl alcohol Polymers 0.000 claims description 8
- 235000019422 polyvinyl alcohol Nutrition 0.000 claims description 8
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 claims description 8
- 239000004576 sand Substances 0.000 claims description 7
- 229910052782 aluminium Inorganic materials 0.000 claims description 6
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 claims description 6
- 239000011521 glass Substances 0.000 claims description 6
- XHZPRMZZQOIPDS-UHFFFAOYSA-N 2-Methyl-2-[(1-oxo-2-propenyl)amino]-1-propanesulfonic acid Chemical compound OS(=O)(=O)CC(C)(C)NC(=O)C=C XHZPRMZZQOIPDS-UHFFFAOYSA-N 0.000 claims description 5
- 241000758789 Juglans Species 0.000 claims description 5
- 235000009496 Juglans regia Nutrition 0.000 claims description 5
- 239000004677 Nylon Substances 0.000 claims description 5
- 229910001570 bauxite Inorganic materials 0.000 claims description 5
- 238000004132 cross linking Methods 0.000 claims description 5
- 239000003431 cross linking reagent Substances 0.000 claims description 5
- 239000012634 fragment Substances 0.000 claims description 5
- 229910052751 metal Inorganic materials 0.000 claims description 5
- 239000002184 metal Substances 0.000 claims description 5
- 229920001778 nylon Polymers 0.000 claims description 5
- 238000012856 packing Methods 0.000 claims description 5
- 235000020234 walnut Nutrition 0.000 claims description 5
- 229910052783 alkali metal Inorganic materials 0.000 claims description 4
- 238000004873 anchoring Methods 0.000 claims description 4
- QRHCILLLMDEFSD-UHFFFAOYSA-N bis(ethenyl)-dimethylsilane Chemical compound C=C[Si](C)(C)C=C QRHCILLLMDEFSD-UHFFFAOYSA-N 0.000 claims description 4
- KUQWZSZYIQGTHT-UHFFFAOYSA-N hexa-1,5-diene-3,4-diol Chemical compound C=CC(O)C(O)C=C KUQWZSZYIQGTHT-UHFFFAOYSA-N 0.000 claims description 4
- FQPSGWSUVKBHSU-UHFFFAOYSA-N methacrylamide Chemical compound CC(=C)C(N)=O FQPSGWSUVKBHSU-UHFFFAOYSA-N 0.000 claims description 4
- 238000002156 mixing Methods 0.000 claims description 4
- ZIUHHBKFKCYYJD-UHFFFAOYSA-N n,n'-methylenebisacrylamide Chemical compound C=CC(=O)NCNC(=O)C=C ZIUHHBKFKCYYJD-UHFFFAOYSA-N 0.000 claims description 4
- ZQXSMRAEXCEDJD-UHFFFAOYSA-N n-ethenylformamide Chemical compound C=CNC=O ZQXSMRAEXCEDJD-UHFFFAOYSA-N 0.000 claims description 4
- 125000001453 quaternary ammonium group Chemical group 0.000 claims description 4
- 150000003839 salts Chemical class 0.000 claims description 4
- NLVXSWCKKBEXTG-UHFFFAOYSA-N vinylsulfonic acid Chemical compound OS(=O)(=O)C=C NLVXSWCKKBEXTG-UHFFFAOYSA-N 0.000 claims description 4
- 238000001035 drying Methods 0.000 claims description 3
- DYUWTXWIYMHBQS-UHFFFAOYSA-N n-prop-2-enylprop-2-en-1-amine Chemical compound C=CCNCC=C DYUWTXWIYMHBQS-UHFFFAOYSA-N 0.000 claims description 3
- 239000011363 dried mixture Substances 0.000 claims description 2
- 230000015572 biosynthetic process Effects 0.000 abstract description 13
- 238000000576 coating method Methods 0.000 abstract description 9
- 239000011248 coating agent Substances 0.000 abstract description 7
- 239000003921 oil Substances 0.000 description 23
- 238000005755 formation reaction Methods 0.000 description 12
- 239000007789 gas Substances 0.000 description 12
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 9
- 229910001220 stainless steel Inorganic materials 0.000 description 6
- 239000010935 stainless steel Substances 0.000 description 6
- 229930195733 hydrocarbon Natural products 0.000 description 5
- 150000002430 hydrocarbons Chemical class 0.000 description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 239000008398 formation water Substances 0.000 description 4
- 230000000670 limiting effect Effects 0.000 description 4
- 238000001000 micrograph Methods 0.000 description 4
- 230000004044 response Effects 0.000 description 4
- 230000002401 inhibitory effect Effects 0.000 description 3
- 239000007788 liquid Substances 0.000 description 3
- 238000011068 loading method Methods 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 238000012360 testing method Methods 0.000 description 3
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- 230000004913 activation Effects 0.000 description 2
- 239000003570 air Substances 0.000 description 2
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 229920006158 high molecular weight polymer Polymers 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 239000000377 silicon dioxide Substances 0.000 description 2
- 239000000243 solution Substances 0.000 description 2
- ZOXJGFHDIHLPTG-UHFFFAOYSA-N Boron Chemical compound [B] ZOXJGFHDIHLPTG-UHFFFAOYSA-N 0.000 description 1
- VYZAMTAEIAYCRO-UHFFFAOYSA-N Chromium Chemical compound [Cr] VYZAMTAEIAYCRO-UHFFFAOYSA-N 0.000 description 1
- 208000002565 Open Fractures Diseases 0.000 description 1
- RTAQQCXQSZGOHL-UHFFFAOYSA-N Titanium Chemical compound [Ti] RTAQQCXQSZGOHL-UHFFFAOYSA-N 0.000 description 1
- QCWXUUIWCKQGHC-UHFFFAOYSA-N Zirconium Chemical compound [Zr] QCWXUUIWCKQGHC-UHFFFAOYSA-N 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 239000012080 ambient air Substances 0.000 description 1
- 238000007664 blowing Methods 0.000 description 1
- 229910052796 boron Inorganic materials 0.000 description 1
- 229910052804 chromium Inorganic materials 0.000 description 1
- 239000011651 chromium Substances 0.000 description 1
- 229910052681 coesite Inorganic materials 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 229910052906 cristobalite Inorganic materials 0.000 description 1
- 125000000524 functional group Chemical group 0.000 description 1
- 230000003301 hydrolyzing effect Effects 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 230000004941 influx Effects 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 230000003715 interstitial flow Effects 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 239000003607 modifier Substances 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 239000011236 particulate material Substances 0.000 description 1
- 239000013618 particulate matter Substances 0.000 description 1
- 239000011148 porous material Substances 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000002441 reversible effect Effects 0.000 description 1
- 235000012239 silicon dioxide Nutrition 0.000 description 1
- 125000006850 spacer group Chemical group 0.000 description 1
- 238000003756 stirring Methods 0.000 description 1
- 229910052682 stishovite Inorganic materials 0.000 description 1
- 239000000758 substrate Substances 0.000 description 1
- 229910052719 titanium Inorganic materials 0.000 description 1
- 239000010936 titanium Substances 0.000 description 1
- 229910052905 tridymite Inorganic materials 0.000 description 1
- 229910052726 zirconium Inorganic materials 0.000 description 1
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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
Definitions
- the present invention relates to apparatus and methods for controlling the production of fluid through a device in a wellbore and methods for constructing said apparatus, and more particularly relates, in one non- limiting embodiment, to apparatus for and methods of inhibiting and controlling the flow of water through a wellbore from subterranean formations during hydrocarbon recovery operations and methods for constructing said apparatus.
- Oil and gas wells are typically completed by placing a casing along the wellbore length and perforating the casing adjacent each such production zone to extract the formation fluids (such as hydrocarbons) into the wellbore. These production zones are sometimes separated or isolated from each other by installing a packer between the production zones. Fluid from each production zone entering the wellbore is drawn into a tubing that runs to the surface. It is desirable to have substantially even drainage along the production zone. Uneven drainage may result in undesirable conditions such as an invasive gas cone or water cone. In the instance of an oil-producing well, for example, a gas cone may cause an in-flow of gas into the wellbore that could significantly reduce oil production. Similarly, a water cone may cause an in-flow of water into the oil production flow that reduces the amount and quality of the produced oil.
- a wellbore device for controlling a flow of a fluid through a flow path therein.
- the wellbore device includes a container comprising a flow path and a consolidated water sensitive porous medium (WSPM) packed within the flow path of the wellbore device container.
- WSPM consolidated water sensitive porous medium
- the WSPM includes solid particles and at least one water hydrolyzable polymer at least partially coated on the solid particles.
- a method of constructing a wellbore device for controlling a flow of a fluid through a flow path in the wellbore device involves mixing solid particles with at least one water hydrolyzable polymer in the presence of a fluid that may be water or brine to give a mixture.
- the method further includes at least partially drying the mixture.
- the method involves packing the at least partially dried mixture into the flow path of the container of the wellbore device to form a consolidated water sensitive porous medium (WSPM).
- WSPM water sensitive porous medium
- a method for controlling a flow of a fluid through a flow path in a wellbore device in a wellbore involves flowing the fluid through the flowpath in the wellbore device and controlling a resistance to flow of the fluid through the flow path whereby: resistance to flow increases as water content of the fluid increases, and resistance to flow decreases as water content of the fluid decreases.
- the wellbore device used includes a container (which may be coextensive therewith) comprising the flow path and a consolidated water sensitive porous medium (WSPM) packed within the flow path of the wellbore device container.
- the WSPM includes solid particles and at least one water hydrolyzable polymer at least partially coated on the solid particles.
- FIG. 1 is a schematic illustration of water sensitive porous media (WSPM) installed inside a wellbore to control the production of water;
- WSPM water sensitive porous media
- FIGS. 2A and 2B are schematic illustrations of different water cuts generating different flow resistance when flowing through a WSPM as a result of different degrees of polymer chain activation (expansion);
- FIG. 3 is a graph of the pressure differential of WSPM (cross- linked VF-1 copolymer coated on 20-60 mesh (850-250 micron) HSP ® proppant) at 200 °F (93 °C) with diesel and simulated formation brine (SFB);
- FIG. 4 is a graph of a pressure drop response for different water cut fluids flowing through WSPM at 200 °F (93 O);
- FIG. 5 is a microphotograph of 20/40 mesh (850/425 micron) HSP ceramic proppant before polymer coating.
- FIG. 6 is a microphotograph of 20/40 mesh (850/425 micron) HSP ceramic proppant after polymer coating.
- the WSPM may be constructed of water-soluble or water-hydrolyzable, high molecular weight polymers which are coated on solid particles, such as sand, glass beads, and ceramic proppants.
- the coated particles are packed under high pressure to form a consolidated homogenous and high porosity porous medium within a container of a wellbore device.
- the container and the wellbore device may be separate structures, where the container is part of the wellbore device, or the container and the wellbore device may be the same and coextensive.
- the polymers may be optionally crosslinked with crosslinking agents.
- the solid particles may be mixed with the polymer solution, e.g. in a blender or mixer, at a particular ratio.
- the production of unwanted subterranean formation water may be prevented, controlled or inhibited by a method involving treating particles with high molecular weight, water-hydrolyzable polymers, and incorporating the particles into a water sensitive porous medium (WSPM) in a wellbore device placed within the wellbore.
- the polymer-coated particles are introduced into a container of a wellbore device under high pressure to form a consolidated WSPM in the device before its introduction downhole.
- the relatively high molecular weight polymers that have components or functional groups that anchor, affiliate or attach onto the surface of the solid particles.
- the polymers are hydrophilic and/or hydrolyzable meaning they swell or expand in physical size upon contact with water.
- the average particle size of the particles may range from about 1 0 mesh to about 100 mesh (from about 2000 microns to about 150 microns). Alternatively, the average particle size of the particles may range from about 20 mesh independently to about 60 mesh (from about 840 microns to about 250 microns); where the term "independently" means that any lower threshold may be combined with any upper threshold.
- the solid particles which serve as a substrate to the water hydrolyzable polymer are relatively small, particulate matter, but should not be confused with atomic particles or subatomic particles.
- the particles may be any of a wide variety of solid particulate material; suitable materials include, but are not necessarily limited to, sand, glass beads, ceramic beads, metal beads, bauxite grains, walnut shell fragments, aluminum pellets, nylon pellets and combinations thereof, including conventional proppants and gravel, and, including proppants and gravel of to- be-developed materials.
- suitable materials include, but are not necessarily limited to, sand, glass beads, ceramic beads, metal beads, bauxite grains, walnut shell fragments, aluminum pellets, nylon pellets and combinations thereof, including conventional proppants and gravel, and, including proppants and gravel of to- be-developed materials.
- Proppants are known in the oilfield as sized particles typically mixed with fracturing fluids to hold open fractures after a hydraulic fracturing treatment. Proppants are sorted for size and sphericity to provide an effective conduit for the production of oil and/or gas from the reservoir to the wellbore.
- Granular has a particular meaning in the oilfield relating to particles of a specific size or specific size range which are placed between a screen that is positioned in the wellbore and the surrounding annulus.
- the size of the gravel is selected to prevent the passage of sand from the formation through the gravel pack.
- the solid particles e.g. proppants or gravel
- the solid particles may suitably be a variety of materials including, but not necessarily limited to, sand (the most common component of which is silica, i.e. silicon dioxide, Si0 2 ), glass beads, ceramic beads, metal beads, bauxite grains, walnut shell fragments, aluminum pellets, nylon pellets and combinations thereof.
- the particles may be coated by a method that involves at least partially hydrolyzing the polymer in a liquid including, but not necessarily limited to, water, brine, glycol, ethanol and mixtures thereof.
- the particles are then intimately mixed or contacted with the liquid containing the polymer to contact the surfaces of the particles with the polymer.
- the liquid is then at least partially vaporized or evaporated through vacuum, or the use of heat and/or contact with a dry gas such as air, nitrogen, or the like.
- the coating method may be conducted at a temperature between ambient up to about 200 °F (about 93°C), to facilitate quick drying of the coating. It may not be necessary in some embodiments to completely dry the coating.
- the loading of the polymers may be a ratio of weight of solid particles to weight of dry water hydrolyzable polymer ranging from about 1 0,000:1 to about 1 0:1 ; alternatively ranging from about 500:1 independently to about 25:1 .
- the solid particles should be at least partially coated by the polymer; that is, while it is desirable to completely coat the solid particles with the polymer, the method and apparatus may still be considered successful if the particles are at least partially coated to the extent the WSPM functions effectively for the purposes noted herein.
- the high pressure used to pack the water hydrolyzable polymer coated particles into the container of the wellbore device through which the flow path exists may range from about 50 to about 2000 psi (about 0.3 to about 1 3.8 MPa), alternatively from about 1 00 independently to about 1000 psi (about 0.7 to about 6.9 MPa).
- the WSPM placed in the wellbore will control unwanted formation water flowing through the wellbore while not adversely affecting the flow of oil and gas.
- the polymers anchored on the solid particles expand to reduce the water flow channel and increase the resistance to water flow.
- the polymers may be understood to interact chemically, ionically or mechanically with a component of the produced or in-flowing formation fluids, e.g. water molecules. This desired response may be variously described as resistance, permeability, impedance, etc. , where the flow of hydrocarbons (e.g. oil and gas) is desirable, but the flow of water is not. This interaction varies the resistance to flow across the flow path of the wellbore device.
- the pre-treated particles e.g. proppants
- the pre-treated particles are expected to form homogeneous porous media with the polymer uniformly distributed in the media to increase the efficiency of the polymer controlling unwanted water production.
- suitable water hydrolyzable polymers include those having a weight average molecular weight greater than 1 00,000.
- suitable, more specific examples of water hydrolyzable polymers include, but are not necessarily limited to, homopolymers and copolymers of acrylamide, sulfonated or quaternized homopolymers and copolymers of acrylamide, polyvinylalcohols, polysiloxanes, hydrophilic natural gum polymers and chemically modified derivatives thereof.
- Crosslinked versions of these polymers may also be suitable, including but not necessarily limited to, crosslinked homopolymers and copolymers of acrylamide, crosslinked sulfonated or quaternized homopolymers and copolymers of acrylamide, crosslinked polyvinylalcohols, crosslinked polysiloxanes, crosslinked hydrophilic natural gum polymers and chemically modified derivatives thereof.
- suitable water hydrolyzable polymers include, but are not necessarily limited to, copolymers having a hydrophilic monomeric unit, where the hydrophilic monomeric unit is selected from the group consisting of ammonium and alkali metal salt of acrylamido- methylpropanesulfonic acid (AMPS), a first anchoring monomeric unit based on N-vinylformamide and a filler monomeric unit, where the filler monomeric unit is selected from the group consisting of acrylamide and methylacrylamide.
- AMPS acrylamido- methylpropanesulfonic acid
- Additional suitable water hydrolyzable polymers include, but are not necessarily limited to, copolymers of vinylamide monomers and monomers containing ammonium or quaternary ammonium moieties, copolymers of vinylamide monomers and monomers comprising vinylcarboxylic acid monomers and/or vinylsulfonic acid monomers, and salts thereof, and these aforementioned copolymers further comprising a crosslinking monomer selected from the group consisting of bis-acrylamide, diallylamine, ⁇ , ⁇ -diallylacrylamide, divinyloxy- ethane, divinyldimethylsilane.
- Suitable crosslinking agents include, but are not necessarily limited to, aluminum, boron, chromium, zirconium, titanium, and other inorganic based and organic based crosslinking agents and other conventional crosslinking agents.
- RPMs relative permeability modifiers
- FIG. 1 Shown in FIG. 1 is a schematic illustration of an oil well 10 having a wellbore 12, which happens to be vertical in part and horizontal in part, in a subterranean formation 14 that contains both oil and water.
- Water sensitive porous media (WSPM) within wellbore devices 16 have been installed at four locations between packers 18 along the horizontal section of the wellbore 12 to control the production of water.
- the flow of oil from the formation 14 into the wellbore 12 is schematically indicated by black arrows 20, whereas the flow of water is schematically indicated by gray arrows 22.
- the flow of oil 20 is uninhibited by the WSPM due to the lack of resistance of the unhydrolyzed polymer, whereas the flow of water is inhibited by the increased resistance of the hydrolyzed polymer, as indicated by the lower water flow at small gray arrows 24.
- FIG. 2 Shown in FIG. 2 is a schematic illustration of different water cuts generating different flow resistance when flowing through a WSPM 16 as a result of different degrees of polymer chain activation (expansion).
- the WSPM 16 includes solid particles 30 having water hydrolyzable polymers 32 at least partially coated thereon or adhered thereto.
- the water droplets are schematically represented by gray circles 34 and the oil droplets are schematically represented by black circles 36.
- FIG. 2A schematically illustrates the WSPM 16 where a 25% water cut flows in the direction shown (left to right) where the relatively low amount of water droplets 34 cause a relatively small amount of the polymer 32 to swell, enlarge or hydrolyze increasing resistance to flow.
- FIG. 1 schematically illustrates the WSPM 16 where a 25% water cut flows in the direction shown (left to right) where the relatively low amount of water droplets 34 cause a relatively small amount of the polymer 32 to swell, enlarge or hydrolyze increasing resistance to flow.
- FIG. 2B schematically illustrates the WSPM 16 where a larger 50% water cut flows in the direction shown (left to right) where the relatively equal amount of water droplets 34 compared to the oil droplets 36 cause a relatively larger amount of the polymer 32 to swell, enlarge or hydrolyze further increasing resistance to flow, as compared with FIG. 2A.
- FIG. 5 is a microphotograph of 20/40 mesh (850/425 micron) HSP ® ceramic proppant before polymer coating.
- HSP proppant is available from Carbo Ceramics.
- FIG. 6 is a microphotograph of the same 20/40 mesh (850/425 micron) HSP ceramic proppant after polymer coating. It may be seen that each proppant particle in FIG. 6 is fully coated and bonded by the polymer using the coating method described.
- the stainless steel tube (container, simulating a wellbore device) is affixed on one end with an end cap; a 1 00 mesh (150 micron) stainless screen is laid inside the end cap to hold the polymer coated proppants;
- Steps 3) and 4) are repeated until the length of the porous medium reaches desired porous medium length;
- FIG. 3 is a graph of the pressure differential of crosslinked VF-1 copolymer coated on 20-60 mesh (850-250 micron) HSP proppant at 200 °F (93°C) with diesel and simulated formation brine (SFB).
- VF-1 is a cross-linked vinylamide-vinylsulfonate copolymer.
- the HSP proppants were coated with the VF-1 polymer as described above.
- the polymer loading was 0.4 % bw (by weight) of the proppant weight.
- FIG. 3 is a response test graph showing that the pressure differential of the polymer-coated proppant WSPM placed inside of a 1 2-inch long, 1 -inch ID stainless steel tube (about 30 cm long by about 2.5 cm ID) changes when pumping with oil (diesel in this Example) relative to pumping with formation water (Simulated Formation Brine or SFB) flowing through the pack.
- This graph demonstrates that the pack exhibits high flow resistance for water and low flow resistance for oil.
- FIG. 4 is a graph of a pressure drop response for different water cut fluids flowing through a WSPM at 200°F (93 °C). The fluids were blends of brine and diesel. With increasing amounts of water (greater water cut percentage), the higher the pressure drop.
- the WSPM was made from VF-1 coated 50-60 mesh (297 to 250 micron) ceramic proppants with polymer loading 0.4%. Different water cuts are marked on FIG 4.
- the components and proportions of the solid particles and polymers and steps of constructing the wellbore devices may change somewhat from wellbore device to another and still accomplish the stated purposes and goals of the methods described herein.
- the assembly methods may use different pressures and additional or different steps than those exemplified herein.
- a wellbore device for controlling a flow of a fluid through a flow path may consist of or consist essentially of a container comprising a flow path and a consolidated water sensitive porous medium (WSPM) packed within the flow path of the wellbore device container, where the WSPM consists of or consists essentially of solid particles and at least one water hydrolyzable polymer at least partially coated on the solid particles.
- WSPM consolidated water sensitive porous medium
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- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Compositions Of Macromolecular Compounds (AREA)
- Silicates, Zeolites, And Molecular Sieves (AREA)
- Manufacture Of Porous Articles, And Recovery And Treatment Of Waste Products (AREA)
- Solid-Sorbent Or Filter-Aiding Compositions (AREA)
- Manufacturing Of Micro-Capsules (AREA)
- Addition Polymer Or Copolymer, Post-Treatments, Or Chemical Modifications (AREA)
Abstract
Description
Claims
Priority Applications (7)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB1300119.3A GB2494826A (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor |
AU2011279476A AU2011279476A1 (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor |
MX2013000464A MX2013000464A (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor. |
CA2804663A CA2804663C (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor |
CN2011800345143A CN103080472A (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor |
BR112013000803A BR112013000803A2 (en) | 2010-07-13 | 2011-07-06 | porous water-sensitive medium to control downhole water production and method for this purpose |
NO20130019A NO20130019A1 (en) | 2010-07-13 | 2013-01-04 | Water-sensitive porous medium for controlling water production in the wellbore and methods for this |
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US12/835,023 | 2010-07-13 | ||
US12/835,023 US20110005752A1 (en) | 2008-08-14 | 2010-07-13 | Water Sensitive Porous Medium to Control Downhole Water Production and Method Therefor |
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WO2012009184A2 true WO2012009184A2 (en) | 2012-01-19 |
WO2012009184A3 WO2012009184A3 (en) | 2012-04-05 |
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PCT/US2011/042993 WO2012009184A2 (en) | 2010-07-13 | 2011-07-06 | Water sensitive porous medium to control downhole water production and method therefor |
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US (1) | US20110005752A1 (en) |
CN (1) | CN103080472A (en) |
AU (1) | AU2011279476A1 (en) |
BR (1) | BR112013000803A2 (en) |
CA (1) | CA2804663C (en) |
GB (1) | GB2494826A (en) |
MX (1) | MX2013000464A (en) |
NO (1) | NO20130019A1 (en) |
WO (1) | WO2012009184A2 (en) |
Families Citing this family (6)
Publication number | Priority date | Publication date | Assignee | Title |
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US9051819B2 (en) | 2011-08-22 | 2015-06-09 | Baker Hughes Incorporated | Method and apparatus for selectively controlling fluid flow |
CN102364041B (en) * | 2011-10-26 | 2014-03-26 | 王胜存 | Oil extraction method for establishing oil permeable water stop sieve by filling fusheng sand in horizontal well fracture |
US9334708B2 (en) | 2012-04-23 | 2016-05-10 | Baker Hughes Incorporated | Flow control device, method and production adjustment arrangement |
CN110486004B (en) * | 2018-05-14 | 2022-05-10 | 中国石油天然气股份有限公司 | Method and device for identifying water flow dominant channel of sandstone reservoir |
CN109932489B (en) * | 2019-03-20 | 2024-02-13 | 西安航空学院 | Gas pretreatment device with mixing instrument and gas detection device |
US20230075579A1 (en) * | 2021-09-09 | 2023-03-09 | Baker Hughes Oilfield Operations Llc | Pseudoplastic flow control device, method and system |
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US5701956A (en) * | 1996-04-17 | 1997-12-30 | Halliburton Energy Services, Inc. | Methods and compositions for reducing water production from subterranean formations |
US20090301726A1 (en) * | 2007-10-12 | 2009-12-10 | Baker Hughes Incorporated | Apparatus and Method for Controlling Water In-Flow Into Wellbores |
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US3878893A (en) * | 1972-10-06 | 1975-04-22 | Dow Chemical Co | Method for forming a consolidated gravel pack in a well borehole |
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US5981447A (en) * | 1997-05-28 | 1999-11-09 | Schlumberger Technology Corporation | Method and composition for controlling fluid loss in high permeability hydrocarbon bearing formations |
US6228812B1 (en) * | 1998-12-10 | 2001-05-08 | Bj Services Company | Compositions and methods for selective modification of subterranean formation permeability |
US7008908B2 (en) * | 2002-11-22 | 2006-03-07 | Schlumberger Technology Corporation | Selective stimulation with selective water reduction |
US7117942B2 (en) * | 2004-06-29 | 2006-10-10 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss during sand control operations |
US7207386B2 (en) * | 2003-06-20 | 2007-04-24 | Bj Services Company | Method of hydraulic fracturing to reduce unwanted water production |
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-
2010
- 2010-07-13 US US12/835,023 patent/US20110005752A1/en not_active Abandoned
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2011
- 2011-07-06 MX MX2013000464A patent/MX2013000464A/en unknown
- 2011-07-06 AU AU2011279476A patent/AU2011279476A1/en not_active Abandoned
- 2011-07-06 CA CA2804663A patent/CA2804663C/en not_active Expired - Fee Related
- 2011-07-06 CN CN2011800345143A patent/CN103080472A/en active Pending
- 2011-07-06 GB GB1300119.3A patent/GB2494826A/en not_active Withdrawn
- 2011-07-06 BR BR112013000803A patent/BR112013000803A2/en not_active IP Right Cessation
- 2011-07-06 WO PCT/US2011/042993 patent/WO2012009184A2/en active Application Filing
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2013
- 2013-01-04 NO NO20130019A patent/NO20130019A1/en not_active Application Discontinuation
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US4095651A (en) * | 1975-09-25 | 1978-06-20 | Institut Francais Du Petrole | Process for selectively plugging areas in the vicinity of oil or gas producing wells in order to reduce water penetration |
US5529124A (en) * | 1994-12-19 | 1996-06-25 | Texaco Inc. | Method for retarding water coning |
US5701956A (en) * | 1996-04-17 | 1997-12-30 | Halliburton Energy Services, Inc. | Methods and compositions for reducing water production from subterranean formations |
US20090301726A1 (en) * | 2007-10-12 | 2009-12-10 | Baker Hughes Incorporated | Apparatus and Method for Controlling Water In-Flow Into Wellbores |
Also Published As
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NO20130019A1 (en) | 2013-02-13 |
GB2494826A (en) | 2013-03-20 |
BR112013000803A2 (en) | 2017-11-14 |
CA2804663A1 (en) | 2012-01-19 |
GB201300119D0 (en) | 2013-02-20 |
US20110005752A1 (en) | 2011-01-13 |
AU2011279476A1 (en) | 2013-01-24 |
CA2804663C (en) | 2015-06-02 |
CN103080472A (en) | 2013-05-01 |
MX2013000464A (en) | 2013-02-27 |
WO2012009184A3 (en) | 2012-04-05 |
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