US20070029085A1 - Prevention of Water and Condensate Blocks in Wells - Google Patents

Prevention of Water and Condensate Blocks in Wells Download PDF

Info

Publication number
US20070029085A1
US20070029085A1 US11/460,843 US46084306A US2007029085A1 US 20070029085 A1 US20070029085 A1 US 20070029085A1 US 46084306 A US46084306 A US 46084306A US 2007029085 A1 US2007029085 A1 US 2007029085A1
Authority
US
United States
Prior art keywords
water
wettability
formation
wettability modifier
gas
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
US11/460,843
Inventor
Mohan Panga
Mathew Samuel
Keng Chan
Philippe Enkababian
Pascal Cheneviere
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.)
Schlumberger Technology Corp
Original Assignee
Schlumberger Technology Corp
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
Application filed by Schlumberger Technology Corp filed Critical Schlumberger Technology Corp
Priority to US11/460,843 priority Critical patent/US20070029085A1/en
Priority to CA002617315A priority patent/CA2617315A1/en
Priority to PCT/IB2006/052653 priority patent/WO2007017806A2/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: ENKABABIAN, PHILIPPE, CHENEVIERE, PASCAL, PANGA, MOHAN K.R., CHAN, KENG SENG, SAMUEL, MATHEW
Publication of US20070029085A1 publication Critical patent/US20070029085A1/en
Abandoned legal-status Critical Current

Links

Images

Classifications

    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02Well-drilling compositions
    • C09K8/03Specific additives for general use in well-drilling compositions
    • C09K8/035Organic additives
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/584Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific surfactants
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/588Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/602Compositions for stimulating production by acting on the underground formation containing surfactants
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/84Compositions based on water or polar solvents
    • C09K8/86Compositions based on water or polar solvents containing organic compounds
    • C09K8/88Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25Methods for stimulating production
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/30Viscoelastic surfactants [VES]

Definitions

  • the invention relates to the prevention of water blocks and the prevention of condensate banking in oil and gas producing subterranean formations. More particularly, it relates to treating subterranean formations to change the wettability from oil or water wet to intermediate wet or gas wet.
  • the accumulation of water near the wellbore in an oil or gas well can decrease the productivity by decreasing the relative permeability of oil or gas.
  • the sources for water accumulation could be filtrate water from drilling mud, cross flow of water from water-bearing zones, water from completion or workover operations, water from matrix/fracture treatments, water from emulsions, etc.
  • the problem of productivity decline because of an increase in near wellbore water saturation is known as water block.
  • liquid hydrocarbons that accumulate near the wellbore can also decrease the productivity of gas.
  • the sources for the accumulation of hydrocarbons could be the use of oil-based drilling mud in drilling operations, hydrocarbon liquids used in workover operations, the use of oil-based fracturing fluids, etc.
  • the liquid hydrocarbons that condense out of the gas phase (called condensates) due to the decline in pressure below the dew point pressure of the gas also hinder the gas production. This phenomenon of condensation with a decrease in pressure is called retrograde condensation.
  • condensates block the production the problem is called condensate block or condensate banking.
  • condensate banking is used for a decline in gas production due to any liquid hydrocarbons, condensates, or hydrocarbons from external sources such as those mentioned above, for example oil based drilling muds.
  • Water blocks and condensate banks can occur together or independently, leading to a decrease in well productivity and in some cases to complete shut down in production. (See, for example, SPE papers 13650, 28479, and 30767.)
  • condensate banking occurs close to the wellbore where the pressure first decreases below the dew point pressure. Even for a small amount of condensate drop out (as a fraction of the produced hydrocarbon), significant condensate build-up can occur, as several pore volumes of gas pass through the wellbore. With time, the condensate bank extends deep into the reservoir due to drawdown and depletion of the reservoir pressure.
  • Condensate banking is a continuing problem, because the condensate accumulates with time even after an initial cleanup.
  • fracturing the purpose is to bypass the zone damaged by water or by condensate blocks and to increase the bottomhole pressure, if possible, above the dew point pressure to decrease the formation of condensate.
  • dry gas injection the clean up is by vaporization of condensate into the gas (see, for example, SPE papers 68683 and 71526).
  • solvents such as methanol, isopropyl alcohol, and others, are injected into the well. The solvents mix with water or condensate and enhance clean up by reducing the interfacial tension and by increasing the volatility of the liquid.
  • a method for prevention of water blocks in gas and oil wells and condensate blocks in gas wells using wettability modifiers may be applied to all oil or gas wells with no water or condensate block problems as a preventive solution. It may also be used as a remedial method for clean-up of most or all of existing water or condensate blocks; after these clean-ups it will act to prevent future water block or condensate blocking in the same location.
  • the chemical system may be mixed with fluids used in fracturing, acidizing, drilling and other workover operations to unload the unwanted oil or water based fluids that enter the formation during the operation.
  • the method may also be used to enhance production in oil wells and injection of water in injector wells because of low near well bore pressure drop resulting from the wettability alteration. The wettability alteration is permanent.
  • the application of this method to treating a subterranean formation may involve single or multiple stages, separated into pretreatment, main and post treatment stages.
  • the pretreatment stage may involve injection of a preflush of water or brine, one or more alcohols, one or more of other solvents, one or more clay stabilizers, one or more water-solvent mixtures, or one or more treatment fluids used in such oilfield treatments as matrix stimulation, and other treatments, one or more other fluids, or mixtures of such fluids.
  • the wettability modifier may be dispersed or mixed in a carrier fluid that may be a solvent or water and may be injected into the well.
  • the formation may be soaked in the fluid that contains a wettability modifier for a period of time (shut-in period).
  • the soaking may not be necessary for some wettability modifiers, some formations, or some conditions.
  • the wettability modifier adheres to the formation by adsorption, chemical bonding, aggregation, electrostatic attraction, precipitation, aggregation, etc.
  • the fluid injected in the main stage is displaced immediately after the main stage, or after a shut-in period, using a gas such as N 2 , CO 2 , etc., or any of the fluids used in the pretreatment stage, or fluids similar to those fluids.
  • This procedure provides better placement of the wettability modifier, and/or enhancement of the flow back of the fluid or fluids injected in the main stage.
  • solvent or “carrier fluid” for any of the pretreatment main or post treatment fluids.
  • the wettability modifiers may include cationic, anionic, or zwitterionic surfactants, or polymers containing chemical groups or moieties that have a tendency to repel oil or water.
  • the presence of fluorine in the surfactant or polymer may give both hydrophobic and oleophobic nature to the chemical.
  • Preferred wettability modifiers include partially or completely fluorinated surfactants or polymers, for example fluorosilanes such as perfluorosilanes, urethane oligomers containing perfluoro alkyl moieties, fluoroacrylates, and fluoroalkyl containing terpolymers.
  • Other examples include surfactants, such as cationic, zwitterionic, anionic, and nonionic surfactants.
  • the wettability modifier may be introduced in solution, for example in water, brine, an alcohol such as methanol, isopropyl alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as petroleum distillates, diesel, biodiesel, or their derivatives, or a mixture of these solvents.
  • the carrier fluid for the chemicals may optionally contain solvents that are volatile (e.g.: alcohol-based solvents) or have low interfacial tension with the gas phase (low capillary pressure) so that, when the well is put on production, the fluid flows out of the formation or deeper into the formation either because of displacement by the gas or evaporation into the gas phase because of high volatility. Since the wettability modifier is adhering to the formation and cannot easily be removed by the flow of fluids or gas, this composition and method provides a long-term solution for the prevention of water/condensate blocks.
  • solvents that are volatile (e.g.: alcohol-based solvents) or have low interfacial tension with the gas phase (low capillary pressure) so that, when the well is put on production, the fluid flows out of the formation or deeper into the formation either because of displacement by the gas or evaporation into the gas phase because of high volatility. Since the wettability modifier is adhering to the formation and cannot easily be removed by the flow of fluids or gas, this composition and method provides
  • FIG. 1 shows the contact angle ⁇ of water when placed on a solid surface.
  • FIG. 2 shows the experimental set-up for the imbibition test.
  • FIG. 3 shows imbibition data for a fluorocarbon wettability modifier of the Invention, before and after treatment.
  • FIG. 4 shows imbibition data with another fluorocarbon wettability modifier of the Invention, before and after treatment.
  • FIG. 5 shows imbibition data with a cationic surfactant wettability modifier of the Invention, before and after treatment.
  • FIG. 6 shows brine saturation in a core before and after treatment with a fluorocarbon wettability modifier of the Invention.
  • Water and condensate blocks occur when a formation is liquid wet, i.e. either water wet or oil wet.
  • the wettability of the formation is altered from water-wet or oil-wet to intermediate or gas-wetting conditions.
  • the alteration of wettability of a formation that is initially water or oil wet to intermediate or gas wetting creates a hydrophobic (water repelling) and oleophobic (oil repelling) surface. Because of this wettability alteration, water or condensate blocks can be cleaned up easily.
  • the chemicals used in this method adhere to the pore walls of the formation by chemical bonding, adsorption, precipitation, aggregation, or electrostatic attraction, etc., with minimal damage, and cannot easily be removed by the flow of liquids or gases.
  • the induced intermediate or gas wettability by treatment with the chemical lasts for a long time, thus providing a long-term preventive solution to the formation of water and condensate blocks.
  • This prevention method may be applied to newly drilled oil or gas wells before putting them on production or to producing wells to prevent formation of water or condensate blocks.
  • use of this method enhances clean-up (flow back of water and oil that enter the formation during the operation or by cross flow) and may be used for remediation.
  • the chemical system may be mixed with fluids used in fracturing, acidizing, drilling or other well intervention operations to unload the water or oil that may invade the formation during these operations.
  • the wettability modifier along with the carrier fluid, may also be pumped as a preflush or post flush before pumping a treatment such as hydraulic fracturing, acid fracturing, matrix stimulation, drilling, gravel packing, frac packing, stim packing, water packing, water fracing, lost circulation control, diversion, sand control, scale dissolution, scale removal, scale control, water control, mud damage removal, completion, mud cake cleaning, or other.
  • the low pressure drop experienced by flowing liquids in such wettability-altered formations (altered from oil or water-wet to intermediate or gas-wet) may also be used to decrease the near wellbore pressure drop, thus enhancing both the production of oil in producing wells and the injectivity of water in injector wells.
  • the wettability modifier adheres to the formation and creates an intermediate or gas-wetting surface that enhances the flow back of water and oil that enter the formation during the operation.
  • a producing oil well or water injection well may be treated with the carrier fluid containing a wettability modifier to alter the wettability of the formation to intermediate or gas wetting.
  • the altered wettability increases the liquid permeability of the medium, thereby enhancing production from oil wells and injectivity of injection wells.
  • the invasion of water into a formation or a layer of a formation may occur when the fluid pressure, for example in a well or fracture or layer of a formation, is greater than the formation fluid pressure or the pressure in a layer, or when there is a pressure difference between different layers in the formation, or when there is imbibition, for example from a well or fracture or another layer into a given layer or formation.
  • the fluid pressure for example in a well or fracture or layer of a formation
  • the high injection pressure of the fluid used to fracture a well may cause water-based fracturing fluids to leak into the formation.
  • Water may also enter the formation through imbibition, a process in which a wetting phase displaces a non-wetting phase in a porous medium.
  • a wetting phase displaces a non-wetting phase in a porous medium.
  • the wetting phase is water (i.e., the formation is water wet) and the non-wetting phase is gas and/or oil, then if the formation contains mobile oil and/or gas, upon contact, water will imbibe into the porous medium, displacing the gas and/or oil in the medium.
  • water Once water enters the formation it may be trapped there, creating a water block if the formation fluids (oil and/or gas) cannot displace it.
  • the reasons for water-trapping could be high capillary pressure at the water-gas or water-oil interface, interaction of water with minerals such as clays in the formation, etc.
  • water trapping may also occur due to viscous fingering because the gas has lower viscosity than water. In such a case, the gas breaks through the trapped water (fingers through the water) leaving a high saturation of water near the wellbore, which creates a water block.
  • condensate banking condensate drops out of the gas phase when the gas pressure falls below the dew point pressure. This phenomenon, where liquid hydrocarbons condense out of the gas phase with a decrease in pressure below the dew point, is called retrograde condensation. Due to a steep decrease in pressure near the well bore, the well flowing pressure first falls below the dew point, at which time liquid hydrocarbons condense out of the gas phase. Due to drawdown and reservoir depletion, the pressure farther and farther away from the wellbore gradually decreases below the dew point and the condensed liquid hydrocarbon slowly accumulates, forming a condensate bank. As mentioned earlier, in addition to condensates, liquid hydrocarbons may also accumulate in the formation because of external sources.
  • the mean radius of curvature is approximated by the mean pore size, which may be approximated further by the relation r ⁇ square root over (k/ ⁇ ) ⁇ where k is the permeability and ⁇ is the porosity of the porous medium.
  • capillary pressure is strong in low permeability formations and weak in high permeability formations.
  • the problem of water and condensate blocks may be reduced if the capillary pressure across the gas-liquid interface can be decreased. From Eq. 1, it can be seen that the capillary pressure can be decreased by reducing the interfacial tension between the fluid and the gas, by increasing the contact angle, or by increasing the permeability of the medium.
  • interfacial tension reducers such as surfactants or alcohol-based solvents can decrease the capillary pressure.
  • this method is only temporary, because the conventionally used surfactants and solvents flow out of the formation once the well is put into production. If the water block or condensate-banking problem occurs again, which is to be expected because the underlying cause has not been addressed, then the well has to be re-treated with solvents or surfactants when necessary.
  • An alternative method of decreasing the capillary pressure is to alter the wettability of the formation or pore surface permanently in such a way that the contact angle ⁇ of the liquid with the pore surface is increased. For example, if the contact angle is altered from 0° to 90°, then the capillary pressure can be reduced to zero (from Eq. 1), which helps in removal of water or condensate blocks. Wettability alteration for removal of water or condensate blocks is a long-term solution, because the formation wettability is permanently altered.
  • Wettability is defined as the ability of one fluid to spread on to a solid surface in the presence of another immiscible fluid.
  • two fluids, mutually immiscible with each other both contact a solid surface, the less-wetting fluid will retreat from contact with the solid while the stronger-wetting fluid will be attracted to the surface.
  • a contact angle is produced (see FIG. 1 ).
  • ⁇ SG is the interfacial tension between solid and gas
  • ⁇ SL is the interfacial tension between solid and liquid (water or oil)
  • ⁇ LG is the interfacial tension between the liquid (water or oil) and gas.
  • FC754 could alter the wettability from strong water wetting to intermediate gas-wetting and from strong oil wetting to less oil wetting.
  • FC722 could alter the wettability from strong water and oil wetting to preferential gas wetting.
  • Tang and Firoozabadi (Tang, G., and Firoozabadi, A., SPE Reservoir Eval. & Eng., 427-436, December, 2002; Tang G., and Firoozabadi, A., Transport in Porous Media, 52, 185-211, 2003) have investigated FC722 and FC759, that are manufactured by 3M, at temperatures in the range of 25° C. to 93° C. Their experiments show good wettability alteration of formations initially oil or water wet to gas wetting after treatment with FC722 and FC759.
  • the invention is a method of changing the wettability of a formation from oil wet or water wet to intermediate wet or gas wet by contacting the formation with a wettability modifier.
  • the treatment eliminates or greatly reduces the tendency to form water blocks and condensate blocks (or condensate banking). It may be applied to prevent water blocks and/or condensate blocks in new gas wells, oil wells, oil and gas wells, and injection wells (for example in enhanced recovery), or to reduce or eliminate water blocks and/or condensate blocks in producing gas wells, oil wells, and oil and gas wells, and in injection wells. It may also be used in wells that produce other materials such as helium or carbon dioxide, or that are used for other purposes such as for material storage or disposal. It may also be used as part of a treatment (for example drilling, stimulation, or workover) of a well.
  • the fluid used for wettability modification contains two main components, a carrier fluid, and a wettability modifier.
  • the wettability modifier is dispersed or mixed or diluted in the carrier fluid to a specified concentration to achieve suitable wettability alteration from water or oil wet to intermediate or gas wetting conditions. This concentration depends upon the formation type.
  • One method of determining a suitable concentration of a wettability modifier required for good wettability alteration is to perform a contact angle test. The concentration that gives the maximum contact angle is preferred.
  • the carrier fluid may be, for example, water, brine, an alcohol such as methanol, isopropyl alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as petroleum distillates, diesel, biodiesel, or their derivatives, or a mixture of these solvents, but the solvent is not limited to these materials.
  • the wettability modifier may be a partially or completely fluorinated surfactant or polymer.
  • a polymer is the family of fluorosilanes such as, but not limited to, 1H, 1H,2H,2H-perfluourodecyltriethoxysilane, and 1H,1H,2H,2H-perfluorooctylmethyldimethoxysilane, which may be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume. (Note that these concentrations are expressed here as volumes of active ingredients, not as volumes of as-received commercial materials, which are usually purchased as concentrates in solvents.)
  • urethane oligomers containing perfluoro alkyl moieties such as but not limited to those described in the following patents and published patent applications: US 20050075471, US 20040147188, U.S. Pat. No. 6,803,109, U.S. Pat. No. 6,753,380, US 6,646,088, WO 2005037884, WO 0214443, and WO 0162687.
  • US publications are hereby incorporated in their entirety.
  • Such materials may also be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • a polymer is fluoroacrylates that have the general formula: C n F 2n+1 -X—OC(O)NH-A-HNC(O)O—(C p H 2p )(O) COC(R′) ⁇ CH 2 in which n is 1 to 5;
  • X is —SO 2 —M(R)—C m H 2m —, —CO—NH—C m H 2m —, —CH(R f )—C y H 2y —, or —C q H 2q —;
  • R is H or an alkyl group of from 1 to 4 carbon atoms; m is 2 to 8; R f is C n F 2n+1 ; y is 0 to 6; q is 1 to 8;
  • A is an unbranched symmetric alkylene group, arylene group, or aralkylene group;
  • p is 2 to 30; and
  • R′ is H, CH 3 , or F.
  • Such materials may also be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • polystyrene resin polystyrene resin
  • fluoroalkyl containing terpolymer of the type described in U.S. Pat. No. 5,945,493, U.S. Pat. No. 6,238,792, and U.S. Pat. No.
  • X is a C 2-10 alkyl, C 6-12 aryl, or C 4-12 alkoxy radical, d is from about 3 to about 50, R is a fluoroalkyl radical R f --(A) v --(B) w --, R f is a fully fluorinated straight or branched aliphatic radical optionally interrupted by at least one oxygen atom,
  • A is a divalent radical selected from —SO 2 N(R′′)--, —CON(R′′)—, —S—, or —SO 2 --, where R′′ is H, or a C 1-6 alkyl radical
  • B is a divalent linear hydrocarbon radical —C t H 2t --, where t is 1 to 12
  • Y is a divalent radical —CH 2 —O—
  • u, v, and w are each independently zero or 1
  • R′ is hydrogen or methyl
  • e is from about 0.05 to about 10
  • M is hydrogen
  • Suitable surfactants are those used as viscoelastic surfactants in fracturing fluids.
  • Suitable cationic surfactants of this type such as quaternary amines, such as erucyl bis-(2-hydroxyethyl) methyl ammonium chloride, are described in U.S. Pat. Nos. 5,964,295, 5,979,557, 6,306,800 and 6,435,277;
  • suitable zwitterionic surfactants of this type such as betaines, such as erucic amidopropyl dimethyl betaine are described in U.S. Pat. Nos. 6,258,859 and 6,399,546. All of these patents are hereby incorporated in their entirety.
  • Suitable cationic surfactants that may be used include those that are commonly used as emulsifiers, such as cocoalkyl amines, cocoalkyl acetates, cocoalkyl betaines, tallow alkyl amine acetates, cocoamphodiacetates, cocoamidobetaines, and their mixtures with or without cosurfactants, solvents, paraffins, and hydrocarbons.
  • Suitable anionic surfactants may be based on phosphate head groups (for example branched alcohol ethoxylate phosphate esters). These surfactants are not adsorbed as strongly as are the fluoropolymers, so they work best at lower temperatures, and the effects may not be as long-lasting, especially at higher temperatures.
  • These surfactants may also be used in the concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • compositions and methods may be used as stand-alone treatments intended to prevent or remediate water blocks and gas or condensate banking, or the wettability modifiers can be used in other treatment fluids.
  • the compositions of the Invention may be added to a number of main treatment fluids with beneficial results. Examples are drilling fluids, completion fluids, stimulation fluids, for example matrix treatment fluids, fracture fluids and gravel packing fluids.
  • drilling and completion fluids the compositions prevent the formation of water blocks.
  • the compositions speed up and increase the extent of clean up and increase oil and gas production after the treatment.
  • the compositions of the Invention increase injectivity.
  • treatments may be done as a pre-treatment before stimulation, or as a post treatment after drilling, completion, and stimulation.
  • fluids containing the wettability modifiers may be selectively introduced into certain layers of a multilayer formation (for example by isolating them with packers), to alter the wettability of those layers, and thereby alter either the relative productivity or injectivity of those layers, or the relative permeability to oil/gas or water of those layers.
  • treatment fluids are known for use in stand-alone treatments; these are generally mixtures of components such as alcohols, mutual solvents, ethers, esters, ketones hydrocarbons, and mixtures of these. These fluids may alter the wettability, but the effect is usually temporary.
  • the compositions of the Invention may be added to such fluids, especially at low temperatures, to make the effects more long-lasting so that the single fluid treatment can act as both a remedial and a prevention treatment.
  • Wettability in a water-gas-rock system was determined by observing the contact angle made by a drop of water 2 on a rock 4 with gas 6 as the third phase (see FIG. 1 ).
  • the angle ⁇ was measured from the rock-water interface through the liquid to the water-gas interface as shown in FIG. 1 .
  • the angle ⁇ was small, then water was said to wet the rock or the rock was water-wet in nature.
  • the angle ⁇ was large, then water did not wet the rock or the rock was intermediate gas wetting. The observation was similarly extended to oil-gas-rock systems.
  • Imbibition is the process in which a wetting phase displaces a non-wetting phase in a porous medium.
  • the experimental apparatus used for the tests is shown in FIG. 2 .
  • a dry core 8 of known porosity and permeability was brought into contact with a liquid 10 , for example water, such that one end of the core was slightly immersed in the liquid. Because of capillary pressure the liquid rose into the core, displacing the air inside the core. The amount of liquid that had imbibed into the core was estimated by measuring the decrease in mass of liquid with the scale 12 .
  • the core was suspended from a line 14 connected to a stand 16 .
  • the amount of water imbibed was more than 40% of the void volume inside the core. However, this percentage changed depending upon the capillary pressure, which in turn depended upon the water-gas interfacial tension, and upon core properties such as permeability, porosity, etc. (see Eq. 1).
  • the oil wetting nature of the core was estimated using oil instead of water as the liquid phase for the imbibition test.
  • an imbibition test was performed on a dry core to establish the initial wettability of the core. Then the core was treated with a solution containing the wettability modifier and a solvent that was either alcohol-based or water-based, by flowing the solution through the core and soaking the core in the solution for a period of time that depended on the wettability modifier used and on the temperature. Tests were also conducted to determine the errors due to evaporation, and corrections were made. The wettability modifier is believed to adhere to the surface of the pores inside the core in this test. Then the core was dried and an imbibition test was again performed to check the liquid imbibition rate and volume. If either the rate of liquid intake or total volume of liquid imbibed decreased when compared to the initial imbibition test before treatment with the wettability modifying solution then the wettability was considered to have been altered to an intermediate or gas wetting nature.
  • a soak may optionally be used in the method of the invention. Whether or not a soak is required in practice depends upon the formation, and its temperature, and the choice of the wettability modifier. Not to be limited by theory, but it is believed that if a head group of the wettability modifier, for example a silane head group, reacts with the surface of the formation, for example in the pores, for example quartz components, this occurs more rapidly at higher temperature, so less soak time or no time will be required at higher temperatures for such materials.
  • a head group of the wettability modifier for example a silane head group
  • Formation minerals affect the adsorption of surfactants, depending upon the head group charge and the charge of the mineral surface, and this affects the required shut-in period. Consequently, at higher temperatures desorption may occur and wettability modifiers that act by adsorption may perform better at low temperature than at high temperature. These factors may be tested by simple laboratory experiments with core samples and wettability modifier chemicals.
  • the contact angle test on a core chip was observed using water as the fluid phase, before and after treatment with a wettability modifier (Rhodafac-PA-32®, a linear alcohol ethoxylate phosphate ester, available from Rhodia Inc., Cranbury, N.J., U. S. A.). Before treatment, water spread on the core chip (the contact angle was close to zero) showing that the core was water-wet. After treatment the contact angle was greater than 90° showing that the wettability had been altered to gas wetting.
  • a wettability modifier Rhodafac-PA-32®, a linear alcohol ethoxylate phosphate ester, available from Rhodia Inc., Cranbury, N.J., U. S. A.
  • FIG. 3 shows the data from an initial imbibition test on a dry core and then an imbibition test on the same core after treatment with Zonyl 8740®.
  • Zonyl 8740® is an aqueous dispersion containing 30% by weight of a perfluoroalkyl methacrylic copolymer. It is commercially available from DuPont Specialty Chemicals, Wilmington, Del., U. S. A., and is described as being a “waterborne oil and water repellent” material.
  • the y-axis shows the percentage of void volume in the core occupied by water as a function of time. Before treatment, 55% of the void volume was filled with water in less than 50 minutes, showing that the core was water-wet. After treatment with the wettability modifier, the water intake was drastically reduced, showing that the wettability of the core had been changed from water-wet to gas wetting.
  • the contact angle test was performed on a core chip that had been treated with a solution of 5% Zonyl 8740® +93 % water+2% KCl. The contact angle was greater than 90° after the treatment, indicating that the wettability had been altered to gas wetting.
  • the imbibition test data for this fluid system was given in example 2. From the contact angle and imbibition data it can be seen that this system may be used for prevention of water blocks.
  • the contact angle test was also performed on a core chip that had been treated with a dilute solution of Novec® fluorosurfactant FC-4430, available from 3M, Performance Materials Division, St. Paul, Minn., U. S. A.
  • This material is a non-ionic polymeric fluorochemical surfactant (fluoroaliphatic polymeric esters) obtained as a solution that was 2%, in water and methanol, of a mixture that had been 90% active ingredient, 8% non-fluorochemical additives (polyether polymer), and 2% N-methyl-2-pyrrolidone/toluene solvent. From the contact angle data (not shown) it was seen that this system may be used for prevention of water blocks. Similar experiments were also done to evaluate the performance of additives to prevent condensate banking.
  • fluorochemical surfactant fluoroaliphatic polymeric esters
  • FIG. 4 shows the results of imbibition tests made with the wettability modifier SRC-220®, a commercial fluorochemical urethane material obtained from 3M Specialty Materials, St. Paul, Minn., U. S. A, and described as a “Stain Resistant Additive”. As received, the material is 19-22% active material, 70-76% water, and 4-7% 2-methoxymethylethoxypropanol. It was used as 2% SRC-220® +96% of 50% isopropyl alcohol+2% KCl.
  • the contact angle test showed that the wettability of the rock was changed to gas wetting conditions (the contact angle was greater than 90° after the treatment).
  • FIG. 4 shows that the initial imbibition into the core was 45% of the void volume of the core. After treatment with the fluid, the final imbibition volume was reduced to 10%, which shows that the system may be used for water block and condensate banking prevention.
  • FIG. 5 shows the results of imbibition tests with a wettability modifier that is a cationic surfactant; it was obtained from Baker Petrolite, Sugar Land, Tex., U. S. A., as Aquet 942®, which is supplied as about 50% active ingredient and about 50% organic solvents. It was used as 5% Aquet 942® +93% of 50% isopropyl alcohol+2% KCl.
  • the contact angle test showed that the wettability was altered to gas wetting conditions (the contact angle was greater than 90° after the treatment).
  • the imbibition data showed that, before treatment with the chemical system, over 90% water was imbibed in a little over 150 minutes, and that after treatment with the chemical the imbibition rate of water and the total water imbibed were drastically reduced.
  • T 1 was the time taken for 60% imbibition of water before treatment with the chemical
  • T 2 was the time taken for 60% imbibition of water after treatment with the chemical.
  • the ratio of T 2 /T 1 is a convenient measure of the ability of the chemical to alter the wettability of the formation. A large ratio indicates better wettability alteration; “inf” means infinite.
  • Cationic Surfactant C is N-cis-13-docosenoic-N,N,-bis(2-hydroxymethyl)-N-methyl ammonium chloride.
  • Cationic Surfactant D is a mixture of alkyl and alkenyl bis(2-hydroxyethyl) ammonium chlorides.
  • Zwitterionic Surfactant is erucic amidopropyl dimethyl betaine. Note that the concentrations given in Table 1 are of as-received material concentrates including solvents.
  • a different type of test was performed to determine the effectiveness, the extent of possible damage imparted by this chemical, and the permanency of the treatments of the Invention.
  • the core was treated with a solution containing 5% Zonyl 8470® and 95% of 6% KCl brine, by injecting 5 pore volumes of the solution into the core; the core was not shut-in.
  • 6% KCl brine was injected into the core as a post flush to displace the treatment solution.
  • N 2 gas was again injected at three different pressure gradients, and the water removed from the core was measured and compared to that obtained before treatment. After this stage, four more brine-gas cycles were done (to check the long-term efficiency of the system); in these, the core was again saturated with brine and then a gas flush was performed to measure the water expelled from the core. Note that from the brine that was expelled from the core, the remaining brine saturation could be calculated since the porosity of the core was known.
  • FIG. 6 shows the brine saturations (Sw) in the untreated and treated core when the three different gas pressure gradients were applied across the core.
  • the brine saturations in the core were 73%, 58% and 57%, at differential pressures of 0.034 MPa (5 psi), 0.103 MPa (15 psi) and 0.276 MPa (40 psi) respectively.
  • the pressure gradient was increased from 0. 103 MPa (15 psi) to 0.276 MPa (40 psi)
  • the additional decrease in brine saturation was only 1%. This shows that a large amount of brine was trapped in small pores whose capillary entry pressure was greater than 0.276 MPa (40 psi).
  • a typical field application of this method may have three stages: pretreatment, main treatment, and post treatment stages.
  • a preflush fluid is injected into the formation.
  • the fluid may contain brine, solvent, organic or inorganic clay stabilizer solution, matrix stimulation fluids, etc.
  • a carrier fluid containing the wettability modifier, solvents and other components is pumped into the formation.
  • the fluid is then left in the formation for a period of time that depends upon the fluid and upon the temperature of the formation. In some cases, it may not be necessary to leave the fluid in the formation.
  • the wettability modifier adheres to the pore walls in the formation either by adsorption, by chemical bonding, by precipitation, by aggregation or by electrostatic attraction.
  • a post treatment stage may optionally be performed, either immediately after the main stage or after the shut-in period.
  • a gas, foam or brine may be injected into the formation to displace the main stage fluid further into the formation or to spread the wettability modifier uniformly.
  • the post treatment stage may also be done to enhance the flow back of the carrier fluid, solvents, and excess wettability modifier injected in the main stage.
  • the fluids flow back to the surface, leaving a coating of wettability modifier on the pore walls of the formation. Because of the wettability modifier, the formation becomes intermediate or gas wetting, which prevents the formation of water or condensate blocks. The treatment will be long-lasting.

Abstract

Compositions and methods are given to prevent, alleviate and remedy water blocks and gas blocks (condensate block or condensate banking). Wettability modifiers are contacted with the formation to change the surfaces from water wet or oil wet to intermediate wet or gas wet. Preferred wettability modifiers include partially or completely fluorinated surfactants or polymers, for example fluorosilanes such as perfluorosilanes, urethane oligomers containing perfluoro alkyl moieties, fluoroacrylates, and fluoroalkyl containing terpolymers or their mixtures. Other examples include surfactants, for example viscoelastic surfactants such as cationic surfactants such as quaternary amines, and zwitterionic surfactants, such as betaines, optionally mixed with co-surfactants.

Description

  • This application claims the benefit of U.S. Provisional Patent Application No. 60/706238, filed on Aug. 5, 2005.
  • FIELD OF THE INVENTION
  • The invention relates to the prevention of water blocks and the prevention of condensate banking in oil and gas producing subterranean formations. More particularly, it relates to treating subterranean formations to change the wettability from oil or water wet to intermediate wet or gas wet.
  • BACKGROUND OF THE INVENTION
  • The accumulation of water near the wellbore in an oil or gas well can decrease the productivity by decreasing the relative permeability of oil or gas. The sources for water accumulation could be filtrate water from drilling mud, cross flow of water from water-bearing zones, water from completion or workover operations, water from matrix/fracture treatments, water from emulsions, etc. The problem of productivity decline because of an increase in near wellbore water saturation is known as water block.
  • In gas wells, in addition to water, liquid hydrocarbons that accumulate near the wellbore can also decrease the productivity of gas. The sources for the accumulation of hydrocarbons could be the use of oil-based drilling mud in drilling operations, hydrocarbon liquids used in workover operations, the use of oil-based fracturing fluids, etc. In addition to such external sources, the liquid hydrocarbons that condense out of the gas phase (called condensates) due to the decline in pressure below the dew point pressure of the gas also hinder the gas production. This phenomenon of condensation with a decrease in pressure is called retrograde condensation. When condensates block the production, the problem is called condensate block or condensate banking. In this specification, the term condensate banking is used for a decline in gas production due to any liquid hydrocarbons, condensates, or hydrocarbons from external sources such as those mentioned above, for example oil based drilling muds.
  • Water blocks and condensate banks can occur together or independently, leading to a decrease in well productivity and in some cases to complete shut down in production. (See, for example, SPE papers 13650, 28479, and 30767.) During the early stages of production, condensate banking occurs close to the wellbore where the pressure first decreases below the dew point pressure. Even for a small amount of condensate drop out (as a fraction of the produced hydrocarbon), significant condensate build-up can occur, as several pore volumes of gas pass through the wellbore. With time, the condensate bank extends deep into the reservoir due to drawdown and depletion of the reservoir pressure. Unlike water blocks, which mainly affect the near wellbore region, condensate banks can affect a region far from the wellbore. Condensate banking is a continuing problem, because the condensate accumulates with time even after an initial cleanup.
  • To increase temporarily the production in a well affected by water block or condensate bank the following methods have been employed (see SPE paper 77546): fracturing the well; dry gas injection; and solvent injection (see, for example, SPE papers 62935, 63161, 68683, 80901, and 84216). In fracturing, the purpose is to bypass the zone damaged by water or by condensate blocks and to increase the bottomhole pressure, if possible, above the dew point pressure to decrease the formation of condensate. In dry gas injection, the clean up is by vaporization of condensate into the gas (see, for example, SPE papers 68683 and 71526). In the third method, solvents such as methanol, isopropyl alcohol, and others, are injected into the well. The solvents mix with water or condensate and enhance clean up by reducing the interfacial tension and by increasing the volatility of the liquid.
  • The methods described above are remedial, and help in the temporary clean-up of existing water or condensate blocks. If the above-mentioned methods are used, then if the water block or condensate bank problem reoccurs, then the well must be treated again. It would be beneficial to have a more permanent method of preventing water block and gas banking.
  • SUMMARY OF THE INVENTION
  • A method has been developed for prevention of water blocks in gas and oil wells and condensate blocks in gas wells using wettability modifiers. This method may be applied to all oil or gas wells with no water or condensate block problems as a preventive solution. It may also be used as a remedial method for clean-up of most or all of existing water or condensate blocks; after these clean-ups it will act to prevent future water block or condensate blocking in the same location. Alternatively, the chemical system may be mixed with fluids used in fracturing, acidizing, drilling and other workover operations to unload the unwanted oil or water based fluids that enter the formation during the operation. The method may also be used to enhance production in oil wells and injection of water in injector wells because of low near well bore pressure drop resulting from the wettability alteration. The wettability alteration is permanent.
  • The application of this method to treating a subterranean formation may involve single or multiple stages, separated into pretreatment, main and post treatment stages. The pretreatment stage may involve injection of a preflush of water or brine, one or more alcohols, one or more of other solvents, one or more clay stabilizers, one or more water-solvent mixtures, or one or more treatment fluids used in such oilfield treatments as matrix stimulation, and other treatments, one or more other fluids, or mixtures of such fluids. In the main stage, the wettability modifier may be dispersed or mixed in a carrier fluid that may be a solvent or water and may be injected into the well. Optionally, the formation may be soaked in the fluid that contains a wettability modifier for a period of time (shut-in period). The soaking may not be necessary for some wettability modifiers, some formations, or some conditions. The wettability modifier adheres to the formation by adsorption, chemical bonding, aggregation, electrostatic attraction, precipitation, aggregation, etc. In a typical post treatment stage the fluid injected in the main stage is displaced immediately after the main stage, or after a shut-in period, using a gas such as N2, CO2, etc., or any of the fluids used in the pretreatment stage, or fluids similar to those fluids. This procedure provides better placement of the wettability modifier, and/or enhancement of the flow back of the fluid or fluids injected in the main stage. In this specification, we may occasionally use the term “solvent” or “carrier fluid” for any of the pretreatment main or post treatment fluids. When the well is put into production, or back on production, or used as an injector, the solvent and the left-over wettability modifier flow out of the formation or deeper into the formation, leaving a coating of the wettability modifier in the formation. This alters the wettability of the formation that is initially water or oil wet to an intermediate or gas wetting condition that reduces the capillary pressure of the formation. During the production life cycle of the well, although it generally will not occur, if any water or condensate accumulate in this wettability altered zone, they may easily be cleaned up, thus preventing the formation of water or condensate blocks and enhancing production.
  • The wettability modifiers may include cationic, anionic, or zwitterionic surfactants, or polymers containing chemical groups or moieties that have a tendency to repel oil or water. For example, the presence of fluorine in the surfactant or polymer may give both hydrophobic and oleophobic nature to the chemical. Preferred wettability modifiers include partially or completely fluorinated surfactants or polymers, for example fluorosilanes such as perfluorosilanes, urethane oligomers containing perfluoro alkyl moieties, fluoroacrylates, and fluoroalkyl containing terpolymers. Other examples include surfactants, such as cationic, zwitterionic, anionic, and nonionic surfactants.
  • The wettability modifier may be introduced in solution, for example in water, brine, an alcohol such as methanol, isopropyl alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as petroleum distillates, diesel, biodiesel, or their derivatives, or a mixture of these solvents.
  • Since this is a preventive or remediative treatment, the fluids injected into the formation should not create an additional water or condensate block. Thus, the carrier fluid for the chemicals may optionally contain solvents that are volatile (e.g.: alcohol-based solvents) or have low interfacial tension with the gas phase (low capillary pressure) so that, when the well is put on production, the fluid flows out of the formation or deeper into the formation either because of displacement by the gas or evaporation into the gas phase because of high volatility. Since the wettability modifier is adhering to the formation and cannot easily be removed by the flow of fluids or gas, this composition and method provides a long-term solution for the prevention of water/condensate blocks.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • FIG. 1 shows the contact angle θ of water when placed on a solid surface.
  • FIG. 2 shows the experimental set-up for the imbibition test.
  • FIG. 3 shows imbibition data for a fluorocarbon wettability modifier of the Invention, before and after treatment.
  • FIG. 4 shows imbibition data with another fluorocarbon wettability modifier of the Invention, before and after treatment.
  • FIG. 5 shows imbibition data with a cationic surfactant wettability modifier of the Invention, before and after treatment.
  • FIG. 6 shows brine saturation in a core before and after treatment with a fluorocarbon wettability modifier of the Invention.
  • DETAILED DESCRIPTION OF THE INVENTION
  • A long-term solution for preventing or remediating water block and condensate banking (gas blocking) has been found. A well that does not have a water block or condensate bank problem is treated with the method to prevent formation of water blocks or condensate banks in the future. This method may also be used to clean up existing water or condensate blocks in the well and to protect against the occurrence of future water block and condensate banking. (The terms “gas banking” and “condensate banking/block” are used interchangeably here.)
  • Water and condensate blocks occur when a formation is liquid wet, i.e. either water wet or oil wet. When a well is treated using the chemical method described here, the wettability of the formation is altered from water-wet or oil-wet to intermediate or gas-wetting conditions. The alteration of wettability of a formation that is initially water or oil wet to intermediate or gas wetting creates a hydrophobic (water repelling) and oleophobic (oil repelling) surface. Because of this wettability alteration, water or condensate blocks can be cleaned up easily. The chemicals used in this method adhere to the pore walls of the formation by chemical bonding, adsorption, precipitation, aggregation, or electrostatic attraction, etc., with minimal damage, and cannot easily be removed by the flow of liquids or gases. As a result, the induced intermediate or gas wettability by treatment with the chemical lasts for a long time, thus providing a long-term preventive solution to the formation of water and condensate blocks.
  • This prevention method may be applied to newly drilled oil or gas wells before putting them on production or to producing wells to prevent formation of water or condensate blocks. In cases in which the well is already affected by water or condensate blocks, use of this method enhances clean-up (flow back of water and oil that enter the formation during the operation or by cross flow) and may be used for remediation. The chemical system may be mixed with fluids used in fracturing, acidizing, drilling or other well intervention operations to unload the water or oil that may invade the formation during these operations. The wettability modifier, along with the carrier fluid, may also be pumped as a preflush or post flush before pumping a treatment such as hydraulic fracturing, acid fracturing, matrix stimulation, drilling, gravel packing, frac packing, stim packing, water packing, water fracing, lost circulation control, diversion, sand control, scale dissolution, scale removal, scale control, water control, mud damage removal, completion, mud cake cleaning, or other. The low pressure drop experienced by flowing liquids in such wettability-altered formations (altered from oil or water-wet to intermediate or gas-wet) may also be used to decrease the near wellbore pressure drop, thus enhancing both the production of oil in producing wells and the injectivity of water in injector wells. The wettability modifier adheres to the formation and creates an intermediate or gas-wetting surface that enhances the flow back of water and oil that enter the formation during the operation.
  • In another application of this method a producing oil well or water injection well may be treated with the carrier fluid containing a wettability modifier to alter the wettability of the formation to intermediate or gas wetting. The altered wettability increases the liquid permeability of the medium, thereby enhancing production from oil wells and injectivity of injection wells.
  • The invasion of water into a formation or a layer of a formation may occur when the fluid pressure, for example in a well or fracture or layer of a formation, is greater than the formation fluid pressure or the pressure in a layer, or when there is a pressure difference between different layers in the formation, or when there is imbibition, for example from a well or fracture or another layer into a given layer or formation. For example, in hydraulic fracturing, the high injection pressure of the fluid used to fracture a well may cause water-based fracturing fluids to leak into the formation. This is very typical in a fracturing treatment and clean-up of the fluid entering the formation may or may not be a problem depending on the nature of the fluid, the nature of the formation, and the amount of fluid that enters the formation (see for example SPE paper 38620). Water may also enter the formation through imbibition, a process in which a wetting phase displaces a non-wetting phase in a porous medium. For example, if, for a porous medium, the wetting phase is water (i.e., the formation is water wet) and the non-wetting phase is gas and/or oil, then if the formation contains mobile oil and/or gas, upon contact, water will imbibe into the porous medium, displacing the gas and/or oil in the medium. Once water enters the formation it may be trapped there, creating a water block if the formation fluids (oil and/or gas) cannot displace it. The reasons for water-trapping could be high capillary pressure at the water-gas or water-oil interface, interaction of water with minerals such as clays in the formation, etc. In gas wells, water trapping may also occur due to viscous fingering because the gas has lower viscosity than water. In such a case, the gas breaks through the trapped water (fingers through the water) leaving a high saturation of water near the wellbore, which creates a water block.
  • In condensate banking, condensate drops out of the gas phase when the gas pressure falls below the dew point pressure. This phenomenon, where liquid hydrocarbons condense out of the gas phase with a decrease in pressure below the dew point, is called retrograde condensation. Due to a steep decrease in pressure near the well bore, the well flowing pressure first falls below the dew point, at which time liquid hydrocarbons condense out of the gas phase. Due to drawdown and reservoir depletion, the pressure farther and farther away from the wellbore gradually decreases below the dew point and the condensed liquid hydrocarbon slowly accumulates, forming a condensate bank. As mentioned earlier, in addition to condensates, liquid hydrocarbons may also accumulate in the formation because of external sources.
  • One of the ways of enhancing clean-up of trapped water or trapped liquid hydrocarbons is by decreasing the capillary pressure at the water-gas or oil-gas interface. The capillary pressure across a gas-liquid interface is given by the Young-Laplace equation,
    Pc=2πcpsθ/r  (Eq. 1)
    where Pc is the capillary pressure, σ is the interfacial tension at the gas-liquid interface, θ is the contact angle and r is the mean radius of curvature of the gas-liquid interface. In a porous medium, the mean radius of curvature is approximated by the mean pore size, which may be approximated further by the relation r˜√{square root over (k/φ)} where k is the permeability and φ is the porosity of the porous medium. Thus, in general, capillary pressure is strong in low permeability formations and weak in high permeability formations. The problem of water and condensate blocks may be reduced if the capillary pressure across the gas-liquid interface can be decreased. From Eq. 1, it can be seen that the capillary pressure can be decreased by reducing the interfacial tension between the fluid and the gas, by increasing the contact angle, or by increasing the permeability of the medium.
  • Addition of interfacial tension reducers such as surfactants or alcohol-based solvents can decrease the capillary pressure. However, this method is only temporary, because the conventionally used surfactants and solvents flow out of the formation once the well is put into production. If the water block or condensate-banking problem occurs again, which is to be expected because the underlying cause has not been addressed, then the well has to be re-treated with solvents or surfactants when necessary.
  • An alternative method of decreasing the capillary pressure is to alter the wettability of the formation or pore surface permanently in such a way that the contact angle θ of the liquid with the pore surface is increased. For example, if the contact angle is altered from 0° to 90°, then the capillary pressure can be reduced to zero (from Eq. 1), which helps in removal of water or condensate blocks. Wettability alteration for removal of water or condensate blocks is a long-term solution, because the formation wettability is permanently altered.
  • Wettability is defined as the ability of one fluid to spread on to a solid surface in the presence of another immiscible fluid. When two fluids, mutually immiscible with each other, both contact a solid surface, the less-wetting fluid will retreat from contact with the solid while the stronger-wetting fluid will be attracted to the surface. At the point of intersection between the two fluid phases and the solid surface, a contact angle is produced (see FIG. 1). The three-phase contact angle that forms as a result of the equilibrium of the three interfacial tensions is described by Young's equation, which for a solid, liquid and gas system is shown in Eq. 2:
    σSG−σSLLGcpsθ  (Eq. 2)
    where σSG is the interfacial tension between solid and gas, σSL is the interfacial tension between solid and liquid (water or oil) and σLG is the interfacial tension between the liquid (water or oil) and gas. When the contact angle is less than 50°, the surface is referred to as being water-wet or oil-wet; when it is greater than 90°, the surface is considered to be gas-wet; and the intermediate range of contact angles from 50° to 90° is considered to be representative of an intermediate wet condition. The contact angle of water with most reservoir rocks is very low, which means that these rocks are water wet. To reduce capillary pressure for removal of water blocks, the contact angle of water with the reservoir rock should be made close to or greater than 90°. Thus, the wettability of the rock has to be altered from water wet to intermediate wet or gas wetting conditions.
  • Experimental studies have been reported in the literature for clean-up of condensate blocks in gas condensate reservoirs by altering the wetting nature of the formation from oil or water wet to intermediate or gas wetting. Li and Firoozabadi (Li, K., and Firoozabadi, A., SPE Reservoir Eval. & Eng., 3(2), 139-149, April, 2000) have used 3M-manufactured FC722 and FC754 to alter the wettability of Berea and chalk core samples from water or oil-wet to gas-wet. FC722 is a fluoropolymer and FC754 is a cationic surfactant. They observed that FC754 could alter the wettability from strong water wetting to intermediate gas-wetting and from strong oil wetting to less oil wetting. FC722 could alter the wettability from strong water and oil wetting to preferential gas wetting. Tang and Firoozabadi (Tang, G., and Firoozabadi, A., SPE Reservoir Eval. & Eng., 427-436, December, 2002; Tang G., and Firoozabadi, A., Transport in Porous Media, 52, 185-211, 2003) have investigated FC722 and FC759, that are manufactured by 3M, at temperatures in the range of 25° C. to 93° C. Their experiments show good wettability alteration of formations initially oil or water wet to gas wetting after treatment with FC722 and FC759.
  • The above laboratory studies investigated the use of wettability alteration as a remedial operation to treat gas wells affected by condensate blocks. However, experimental or field studies reported thus far have not used wettability modification as a preventive method for formation of water blocks in gas or oil wells and condensate blocks in gas wells.
  • The invention is a method of changing the wettability of a formation from oil wet or water wet to intermediate wet or gas wet by contacting the formation with a wettability modifier. The treatment eliminates or greatly reduces the tendency to form water blocks and condensate blocks (or condensate banking). It may be applied to prevent water blocks and/or condensate blocks in new gas wells, oil wells, oil and gas wells, and injection wells (for example in enhanced recovery), or to reduce or eliminate water blocks and/or condensate blocks in producing gas wells, oil wells, and oil and gas wells, and in injection wells. It may also be used in wells that produce other materials such as helium or carbon dioxide, or that are used for other purposes such as for material storage or disposal. It may also be used as part of a treatment (for example drilling, stimulation, or workover) of a well.
  • In general, the fluid used for wettability modification contains two main components, a carrier fluid, and a wettability modifier. However, the number of components may vary. The wettability modifier is dispersed or mixed or diluted in the carrier fluid to a specified concentration to achieve suitable wettability alteration from water or oil wet to intermediate or gas wetting conditions. This concentration depends upon the formation type. One method of determining a suitable concentration of a wettability modifier required for good wettability alteration is to perform a contact angle test. The concentration that gives the maximum contact angle is preferred. The carrier fluid may be, for example, water, brine, an alcohol such as methanol, isopropyl alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as petroleum distillates, diesel, biodiesel, or their derivatives, or a mixture of these solvents, but the solvent is not limited to these materials.
  • The wettability modifier may be a partially or completely fluorinated surfactant or polymer. One example of such a polymer is the family of fluorosilanes such as, but not limited to, 1H, 1H,2H,2H-perfluourodecyltriethoxysilane, and 1H,1H,2H,2H-perfluorooctylmethyldimethoxysilane, which may be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume. (Note that these concentrations are expressed here as volumes of active ingredients, not as volumes of as-received commercial materials, which are usually purchased as concentrates in solvents.)
  • Another example of such a polymer is urethane oligomers containing perfluoro alkyl moieties, such as but not limited to those described in the following patents and published patent applications: US 20050075471, US 20040147188, U.S. Pat. No. 6,803,109, U.S. Pat. No. 6,753,380, US 6,646,088, WO 2005037884, WO 0214443, and WO 0162687. The US publications are hereby incorporated in their entirety. Such materials may also be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • Yet another example of such a polymer is fluoroacrylates that have the general formula:
    CnF2n+1-X—OC(O)NH-A-HNC(O)O—(CpH2p)(O) COC(R′)═CH2
    in which n is 1 to 5; X is —SO2—M(R)—CmH2m—, —CO—NH—CmH2m—, —CH(Rf)—CyH2y—, or —CqH2q—; R is H or an alkyl group of from 1 to 4 carbon atoms; m is 2 to 8; Rf is CnF2n+1; y is 0 to 6; q is 1 to 8; A is an unbranched symmetric alkylene group, arylene group, or aralkylene group; p is 2 to 30; and R′ is H, CH3, or F. Examples of this are given in patent applications US20050143541 (hereby incorporated in its entirety), and WO2005066224. Such materials may also be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • Another example of such a polymer is a fluoroalkyl containing terpolymer of the type described in U.S. Pat. No. 5,945,493, U.S. Pat. No. 6,238,792, and U.S. Pat. No. 6,245,116 (all hereby incorporated in their entirety):
    Figure US20070029085A1-20070208-C00001

    wherein X is a C 2-10 alkyl, C 6-12 aryl, or C 4-12 alkoxy radical, d is from about 3 to about 50, R is a fluoroalkyl radical R f --(A) v --(B) w --, R f is a fully fluorinated straight or branched aliphatic radical optionally interrupted by at least one oxygen atom, A is a divalent radical selected from —SO 2 N(R″)--, —CON(R″)—, —S—, or —SO 2 --, where R″ is H, or a C 1-6 alkyl radical, B is a divalent linear hydrocarbon radical —C t H 2t --, where t is 1 to 12, Y is a divalent radical —CH 2 —O—, u, v, and w are each independently zero or 1, R′ is hydrogen or methyl, e is from about 0.05 to about 10, M is hydrogen, alkali metal, or ammonium, and f is from about 5 to about 40. Such materials may also be used in a concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • Examples of suitable surfactants are those used as viscoelastic surfactants in fracturing fluids. Suitable cationic surfactants of this type, such as quaternary amines, such as erucyl bis-(2-hydroxyethyl) methyl ammonium chloride, are described in U.S. Pat. Nos. 5,964,295, 5,979,557, 6,306,800 and 6,435,277; suitable zwitterionic surfactants of this type, such as betaines, such as erucic amidopropyl dimethyl betaine are described in U.S. Pat. Nos. 6,258,859 and 6,399,546. All of these patents are hereby incorporated in their entirety. Suitable cationic surfactants that may be used include those that are commonly used as emulsifiers, such as cocoalkyl amines, cocoalkyl acetates, cocoalkyl betaines, tallow alkyl amine acetates, cocoamphodiacetates, cocoamidobetaines, and their mixtures with or without cosurfactants, solvents, paraffins, and hydrocarbons. Suitable anionic surfactants may be based on phosphate head groups (for example branched alcohol ethoxylate phosphate esters). These surfactants are not adsorbed as strongly as are the fluoropolymers, so they work best at lower temperatures, and the effects may not be as long-lasting, especially at higher temperatures. These surfactants may also be used in the concentration range of from about 0.1% to about 10% by volume, preferably at a concentration of from about 0.5% to about 2% by volume (based on active ingredients).
  • The compositions and methods may be used as stand-alone treatments intended to prevent or remediate water blocks and gas or condensate banking, or the wettability modifiers can be used in other treatment fluids. Thus, in addition to stand-alone treatments, the compositions of the Invention may be added to a number of main treatment fluids with beneficial results. Examples are drilling fluids, completion fluids, stimulation fluids, for example matrix treatment fluids, fracture fluids and gravel packing fluids. When used in drilling and completion fluids, the compositions prevent the formation of water blocks. When used as additives in stimulation fluids in production wells, the compositions speed up and increase the extent of clean up and increase oil and gas production after the treatment. When used as additives in stimulation fluids in water injection wells, the compositions of the Invention increase injectivity. Alternatively, treatments may be done as a pre-treatment before stimulation, or as a post treatment after drilling, completion, and stimulation. In another use, fluids containing the wettability modifiers may be selectively introduced into certain layers of a multilayer formation (for example by isolating them with packers), to alter the wettability of those layers, and thereby alter either the relative productivity or injectivity of those layers, or the relative permeability to oil/gas or water of those layers.
  • Other treatment fluids are known for use in stand-alone treatments; these are generally mixtures of components such as alcohols, mutual solvents, ethers, esters, ketones hydrocarbons, and mixtures of these. These fluids may alter the wettability, but the effect is usually temporary. The compositions of the Invention may be added to such fluids, especially at low temperatures, to make the effects more long-lasting so that the single fluid treatment can act as both a remedial and a prevention treatment.
  • EXAMPLES
  • Two types of tests were conducted to check the ability of chemical systems to alter wettability. First a contact angle test was performed, followed by an imbibition test.
  • Wettability in a water-gas-rock system was determined by observing the contact angle made by a drop of water 2 on a rock 4 with gas 6 as the third phase (see FIG. 1). The angle θ was measured from the rock-water interface through the liquid to the water-gas interface as shown in FIG. 1. When the angle θ was small, then water was said to wet the rock or the rock was water-wet in nature. When the angle θ was large, then water did not wet the rock or the rock was intermediate gas wetting. The observation was similarly extended to oil-gas-rock systems.
  • In a porous medium, the ability of water to wet the medium was determined by means of an imbibition test. Imbibition is the process in which a wetting phase displaces a non-wetting phase in a porous medium. The experimental apparatus used for the tests is shown in FIG. 2. In this test, a dry core 8 of known porosity and permeability was brought into contact with a liquid 10, for example water, such that one end of the core was slightly immersed in the liquid. Because of capillary pressure the liquid rose into the core, displacing the air inside the core. The amount of liquid that had imbibed into the core was estimated by measuring the decrease in mass of liquid with the scale 12. The core was suspended from a line 14 connected to a stand 16. In general, if the core was initially water wet then the amount of water imbibed was more than 40% of the void volume inside the core. However, this percentage changed depending upon the capillary pressure, which in turn depended upon the water-gas interfacial tension, and upon core properties such as permeability, porosity, etc. (see Eq. 1). Similarly, the oil wetting nature of the core was estimated using oil instead of water as the liquid phase for the imbibition test.
  • Typically, a pair of imbibition tests was performed. First, an imbibition test was performed on a dry core to establish the initial wettability of the core. Then the core was treated with a solution containing the wettability modifier and a solvent that was either alcohol-based or water-based, by flowing the solution through the core and soaking the core in the solution for a period of time that depended on the wettability modifier used and on the temperature. Tests were also conducted to determine the errors due to evaporation, and corrections were made. The wettability modifier is believed to adhere to the surface of the pores inside the core in this test. Then the core was dried and an imbibition test was again performed to check the liquid imbibition rate and volume. If either the rate of liquid intake or total volume of liquid imbibed decreased when compared to the initial imbibition test before treatment with the wettability modifying solution then the wettability was considered to have been altered to an intermediate or gas wetting nature.
  • To judge the ability of the method and of a specific wettability modifier to alter wettability of the formation so that prevention of water blocks was achieved, the following tests were conducted. Cores used were typical sandstones, such as Berea, from Ohio, U.S. A., Bandera, from Kansas, U. S. A., and Tunu from Indonesia; the latter contains carbonates. The choice of sandstone made little difference in the tests with these three sandstones, and similar results are expected with carbonate cores. First, the contact angle of water with a dry core chip (a thin slice of a core) was observed by placing a drop of water on the core. Then the core chip was treated with a solution containing a wettability modifier by soaking it in the solution. Then the core chip was dried and a drop of water was placed on it to check the contact angle. If the contact angle was more than the initial contact angle, then the wettability modifier had increased the gas wetting nature of the core, which was desired for prevention of water blocks.
  • A soak (shut in period) may optionally be used in the method of the invention. Whether or not a soak is required in practice depends upon the formation, and its temperature, and the choice of the wettability modifier. Not to be limited by theory, but it is believed that if a head group of the wettability modifier, for example a silane head group, reacts with the surface of the formation, for example in the pores, for example quartz components, this occurs more rapidly at higher temperature, so less soak time or no time will be required at higher temperatures for such materials.
  • Formation minerals affect the adsorption of surfactants, depending upon the head group charge and the charge of the mineral surface, and this affects the required shut-in period. Consequently, at higher temperatures desorption may occur and wettability modifiers that act by adsorption may perform better at low temperature than at high temperature. These factors may be tested by simple laboratory experiments with core samples and wettability modifier chemicals.
  • Example 1
  • The contact angle test on a core chip was observed using water as the fluid phase, before and after treatment with a wettability modifier (Rhodafac-PA-32®, a linear alcohol ethoxylate phosphate ester, available from Rhodia Inc., Cranbury, N.J., U. S. A.). Before treatment, water spread on the core chip (the contact angle was close to zero) showing that the core was water-wet. After treatment the contact angle was greater than 90° showing that the wettability had been altered to gas wetting.
  • Example 2
  • FIG. 3 shows the data from an initial imbibition test on a dry core and then an imbibition test on the same core after treatment with Zonyl 8740®. Zonyl 8740® is an aqueous dispersion containing 30% by weight of a perfluoroalkyl methacrylic copolymer. It is commercially available from DuPont Specialty Chemicals, Wilmington, Del., U. S. A., and is described as being a “waterborne oil and water repellent” material. The y-axis shows the percentage of void volume in the core occupied by water as a function of time. Before treatment, 55% of the void volume was filled with water in less than 50 minutes, showing that the core was water-wet. After treatment with the wettability modifier, the water intake was drastically reduced, showing that the wettability of the core had been changed from water-wet to gas wetting.
  • Example 3
  • The contact angle test was performed on a core chip that had been treated with a solution of 5% Zonyl 8740® +93 % water+2% KCl. The contact angle was greater than 90° after the treatment, indicating that the wettability had been altered to gas wetting. The imbibition test data for this fluid system was given in example 2. From the contact angle and imbibition data it can be seen that this system may be used for prevention of water blocks. The contact angle test was also performed on a core chip that had been treated with a dilute solution of Novec® fluorosurfactant FC-4430, available from 3M, Performance Materials Division, St. Paul, Minn., U. S. A. This material is a non-ionic polymeric fluorochemical surfactant (fluoroaliphatic polymeric esters) obtained as a solution that was 2%, in water and methanol, of a mixture that had been 90% active ingredient, 8% non-fluorochemical additives (polyether polymer), and 2% N-methyl-2-pyrrolidone/toluene solvent. From the contact angle data (not shown) it was seen that this system may be used for prevention of water blocks. Similar experiments were also done to evaluate the performance of additives to prevent condensate banking.
  • Example 4
  • FIG. 4 shows the results of imbibition tests made with the wettability modifier SRC-220®, a commercial fluorochemical urethane material obtained from 3M Specialty Materials, St. Paul, Minn., U. S. A, and described as a “Stain Resistant Additive”. As received, the material is 19-22% active material, 70-76% water, and 4-7% 2-methoxymethylethoxypropanol. It was used as 2% SRC-220® +96% of 50% isopropyl alcohol+2% KCl. The contact angle test showed that the wettability of the rock was changed to gas wetting conditions (the contact angle was greater than 90° after the treatment). FIG. 4 shows that the initial imbibition into the core was 45% of the void volume of the core. After treatment with the fluid, the final imbibition volume was reduced to 10%, which shows that the system may be used for water block and condensate banking prevention.
  • Example 5
  • FIG. 5 shows the results of imbibition tests with a wettability modifier that is a cationic surfactant; it was obtained from Baker Petrolite, Sugar Land, Tex., U. S. A., as Aquet 942®, which is supplied as about 50% active ingredient and about 50% organic solvents. It was used as 5% Aquet 942® +93% of 50% isopropyl alcohol+2% KCl. The contact angle test showed that the wettability was altered to gas wetting conditions (the contact angle was greater than 90° after the treatment). The imbibition data showed that, before treatment with the chemical system, over 90% water was imbibed in a little over 150 minutes, and that after treatment with the chemical the imbibition rate of water and the total water imbibed were drastically reduced.
  • Example 6
  • Several tests were performed using cationic, anionic, and zwitterionic surfactants, fluorosurfactants, and fluoropolymer based chemicals to check their ability to alter wettability of the formation and thereby to prevent water block formation. Table 1 shows the experimental data. T1 was the time taken for 60% imbibition of water before treatment with the chemical, and T2 was the time taken for 60% imbibition of water after treatment with the chemical. The ratio of T2/T1 is a convenient measure of the ability of the chemical to alter the wettability of the formation. A large ratio indicates better wettability alteration; “inf” means infinite.
    TABLE 1
    Chemical (Vol %) T1 (min) T2 (min) T2/T1
    Aquet 942 ® 5 63 786 12.5
    Cationic Surfactant A 5 63 612 9.7
    Cationic Surfactant B 5 83 1210 14.6
    Cationic Surfactant C 5 42 954 22.7
    Cationic Surfactant D 5 20 84 4.2
    Zwitterionic Surfactant 2 10 38 3.8
    3M SRC-220 ® 2 16 inf inf
    (Fluoropolymer)
    Dupont Zonyl 8470 ® 5 40 inf inf
    (Fluorosurfactant)
    Rhodia Rhodafac PA-32 ® 5 16 117 7.3

    Cationic Surfactants A and B are blends of cocoalkyl amines and acetates. Cationic Surfactant C is N-cis-13-docosenoic-N,N,-bis(2-hydroxymethyl)-N-methyl ammonium chloride. Cationic Surfactant D is a mixture of alkyl and alkenyl bis(2-hydroxyethyl) ammonium chlorides. Zwitterionic Surfactant is erucic amidopropyl dimethyl betaine. Note that the concentrations given in Table 1 are of as-received material concentrates including solvents.
  • Example 8
  • Core Test
  • A different type of test was performed to determine the effectiveness, the extent of possible damage imparted by this chemical, and the permanency of the treatments of the Invention. A core test was conducted at 126.6° C. (260° F.) using a standard Hassler cell. In this test, the core (length=6.35 cm; diameter=3.77 cm, permeability=12 mD, porosity=14%) was initially saturated with 6% KCl brine, and N2 gas was then injected into the core to displace water. The removal of water was measured by applying different gas pressure gradients along the length of the core and weighing the water expelled from the core at each pressure gradient. Then the core was treated with a solution containing 5% Zonyl 8470® and 95% of 6% KCl brine, by injecting 5 pore volumes of the solution into the core; the core was not shut-in. After the treatment, 6% KCl brine was injected into the core as a post flush to displace the treatment solution. Once the core was fully saturated with brine, N2 gas was again injected at three different pressure gradients, and the water removed from the core was measured and compared to that obtained before treatment. After this stage, four more brine-gas cycles were done (to check the long-term efficiency of the system); in these, the core was again saturated with brine and then a gas flush was performed to measure the water expelled from the core. Note that from the brine that was expelled from the core, the remaining brine saturation could be calculated since the porosity of the core was known.
  • FIG. 6 (the data are shown in Table 2) shows the brine saturations (Sw) in the untreated and treated core when the three different gas pressure gradients were applied across the core. For the untreated core, the brine saturations in the core were 73%, 58% and 57%, at differential pressures of 0.034 MPa (5 psi), 0.103 MPa (15 psi) and 0.276 MPa (40 psi) respectively. When the pressure gradient was increased from 0. 103 MPa (15 psi) to 0.276 MPa (40 psi), the additional water removed was very low for the untreated core. The additional decrease in brine saturation was only 1%. This shows that a large amount of brine was trapped in small pores whose capillary entry pressure was greater than 0.276 MPa (40 psi).
  • After treatment (cycles 1-5), the brine saturation in the core was lower than that of the untreated core at all pressure gradients. This was due to capillary pressure reduction by Zonyl 8470® which allowed the clean up of water from smaller pores. When differential pressure was increased from 0.103 MPa (15 psi) to 0.276 MPa (40 psi), reduction in brine saturation was in the range of 6%-13%, compared to 1% before treatment. The slope of the lines between 0.103 MPa (15 psi) and 0.276 MPa (40 psi), after treatment showed that higher differential pressures resulted in further clean up. Before treatment, the line was almost vertical, showing that increasing pressure did not enhance clean up at the same rate as for a treated core.
    TABLE 2
    ΔP1 ΔP2 ΔP3
    (MPa) Sw1 (MPa) Sw2 (MPa) Sw3
    Untreated 0.032 0.73 0.106 0.58 0.278 0.57
    Treated
    Cycle 1 0.037 0.65 0.099 0.55 0.273 0.45
    Cycle 2 0.057 0.65 0.110 0.56 0.272 0.49
    Cycle 3 0.055 0.67 0.113 0.58 0.272 0.45
    Cycle 4 0.038 0.58 0.103 0.49 0.276 0.42
    Cycle 5 0.035 0.67 0.101 0.54 0.273 0.48
  • Example 9
  • Field Application
  • A typical field application of this method may have three stages: pretreatment, main treatment, and post treatment stages. In the pretreatment stage, a preflush fluid is injected into the formation. The fluid may contain brine, solvent, organic or inorganic clay stabilizer solution, matrix stimulation fluids, etc. In the main stage, a carrier fluid containing the wettability modifier, solvents and other components, is pumped into the formation. The fluid is then left in the formation for a period of time that depends upon the fluid and upon the temperature of the formation. In some cases, it may not be necessary to leave the fluid in the formation. The wettability modifier adheres to the pore walls in the formation either by adsorption, by chemical bonding, by precipitation, by aggregation or by electrostatic attraction. Following the main stage, a post treatment stage may optionally be performed, either immediately after the main stage or after the shut-in period. In the post treatment stage, a gas, foam or brine may be injected into the formation to displace the main stage fluid further into the formation or to spread the wettability modifier uniformly. The post treatment stage may also be done to enhance the flow back of the carrier fluid, solvents, and excess wettability modifier injected in the main stage. When the well is put on production, the fluids flow back to the surface, leaving a coating of wettability modifier on the pore walls of the formation. Because of the wettability modifier, the formation becomes intermediate or gas wetting, which prevents the formation of water or condensate blocks. The treatment will be long-lasting.

Claims (32)

1. In a subterranean formation penetrated by a well bore, the formation containing an accumulation of liquid, selected from water, oil, condensate, and mixtures thereof, that is blocking at least some flow of fluid in the formation, a method for removing at least a portion of the accumulation of liquid, selected from water, oil, condensate, and mixtures thereof, by altering the wettability of the formation from an initially oil or water wet state to an intermediate or gas wet state, comprising the step of contacting the formation with a treatment fluid comprising a wettability modifier.
2. The method of claim 1 wherein the step of contacting is preceded by a preflush step.
3. The method of claim 1 wherein the step of contacting is followed by a postflush step.
4. The method of claim 1 wherein the step of contacting further comprises a soak period.
5. The method of claim 1 wherein the treatment fluid comprises more than one wettability modifier.
6. The method of claim 1 wherein the wettability modifier is selected from the group consisting of cationic surfactants, quaternary amines, erucyl bis-(2-hydroxyethyl) methyl ammonium chloride, zwitterionic surfactants, betaines, erucic amidopropyl dimethyl betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl amines, cocoalkyl acetates, tallow alkyl amine acetates, and cocoamphodiacetates.
7. The method of claim 1 wherein the wettability modifier is selected from the group consisting of fluorosurfactants and fluoropolymers.
8. The method of claim 7 wherein the fluoropolymers are selected from the group consisting of fluorosilanes, fluoroalkoxysilanes, polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and mixtures thereof.
9. The method of claim 1 wherein the wettability modifier is present in a concentration of between about 0.1 per cent by volume and about 10 per cent by volume of active material.
10. The method of claim 9 wherein the wettability modifier is present in a concentration of between about 0.5 per cent by volume and about 5 per cent by volume of active material.
11. In a subterranean formation penetrated by a well bore, a method for reducing the formation of an accumulation of liquid, selected from water, oil, condensate, and mixtures thereof, that would block the flow of fluid, by altering the wettability of the formation from an initially oil or water wet state to an intermediate or gas wetting state by the step of contacting the formation with a wettability modifier.
12. The method of claim 11 wherein the step of contacting is preceded by a preflush step.
13. The method of claim 11 wherein the step of contacting is followed by a postflush step.
14. The method of claim 11 wherein the step of contacting further comprises a soak period.
15. The method of claim 11 wherein the treatment fluid comprises more than one wettability modifier.
16. The method of claim 11 the wettability modifier is selected from the group consisting of cationic surfactants, quaternary amines, erucyl bis-(2-hydroxyethyl) methyl ammonium chloride, zwitterionic surfactants, betaines, erucic amidopropyl dimethyl betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl amines, cocoalkyl acetates, tallow alkyl amine acetates, and cocoamphodiacetates.
17. The method of claim 11 wherein the wettability modifier is selected from the group consisting of fluorosurfactants and fluoropolymers.
18. The method of claim 17 wherein the fluoropolymers are selected from the group consisting of fluorosilanes, fluoroalkoxysilanes, polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and mixtures thereof.
19. The method of claim 11 wherein the wettability modifier is present in a concentration of between about 0.1 per cent by volume and about 10 per cent by volume of active material.
20. The method of claim 19 wherein the wettability modifier is present in a concentration of between about 0.5 per cent by volume and about 5 per cent by volume of active material.
21. The method of claim 11 wherein the step of contacting the formation with a wettability modifier comprises incorporating the wettability modifier in a treatment fluid selected from the group consisting of drilling fluids, completion fluids, and stimulation fluids.
22. In a subterranean formation penetrated by a well bore, a method for preventing the formation of an accumulation of liquid, selected from water, oil, condensate, and mixtures thereof, that would block the flow of fluid, by altering the wettability of the formation from an initially oil or water wet state to an intermediate or gas wetting state by the step of contacting the formation with a wettability modifier.
23. The method of claim 22 wherein the step of contacting is preceded by a preflush step.
24. The method of claim 22 wherein the step of contacting is followed by a postflush step.
25. The method of claim 22 wherein the step of contacting further comprises a soak period.
26. The method of claim 22 wherein the treatment fluid comprises more than one wettability modifier.
27. The method of claim 22 wherein the wettability modifier is selected from the group consisting of cationic surfactants, quaternary amines, erucyl bis-(2-hydroxyethyl) methyl ammonium chloride, zwitterionic surfactants, betaines, erucic amidopropyl dimethyl betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl amines, cocoalkyl acetates, tallow alkyl amine acetates, and cocoamphodiacetates.
28. The method of claim 22 wherein the wettability modifier is selected from the group consisting of fluorosurfactants and fluoropolymers.
29. The method of claim 28 wherein the fluoropolymers are selected from the group consisting of fluorosilanes, fluoroalkoxysilanes, polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and mixtures thereof.
30. The method of claim 22 wherein the wettability modifier is present in a concentration of between about 0.1 per cent by volume and about 10 per cent by volume of active material.
31. The method of claim 30 wherein the wettability modifier is present in a concentration of between about 0.5 per cent by volume and about 5 per cent by volume of active material.
32. The method of claim 22 wherein the step of contacting the formation with a wettability modifier comprises incorporating the wettability modifier in a treatment fluid selected from the group consisting of drilling fluids, completion fluids, and stimulation fluids.
US11/460,843 2005-08-05 2006-07-28 Prevention of Water and Condensate Blocks in Wells Abandoned US20070029085A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US11/460,843 US20070029085A1 (en) 2005-08-05 2006-07-28 Prevention of Water and Condensate Blocks in Wells
CA002617315A CA2617315A1 (en) 2005-08-05 2006-08-02 Prevention of water and condensate blocks in wells
PCT/IB2006/052653 WO2007017806A2 (en) 2005-08-05 2006-08-02 Prevention of water and condensate blocks in wells

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US70623805P 2005-08-05 2005-08-05
US11/460,843 US20070029085A1 (en) 2005-08-05 2006-07-28 Prevention of Water and Condensate Blocks in Wells

Publications (1)

Publication Number Publication Date
US20070029085A1 true US20070029085A1 (en) 2007-02-08

Family

ID=37716614

Family Applications (1)

Application Number Title Priority Date Filing Date
US11/460,843 Abandoned US20070029085A1 (en) 2005-08-05 2006-07-28 Prevention of Water and Condensate Blocks in Wells

Country Status (3)

Country Link
US (1) US20070029085A1 (en)
CA (1) CA2617315A1 (en)
WO (1) WO2007017806A2 (en)

Cited By (72)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20070225176A1 (en) * 2006-03-27 2007-09-27 Pope Gary A Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US20080051551A1 (en) * 2006-08-23 2008-02-28 Board Of Regents, The University Of Texas System Compositions and methods for improving the productivity of hydrocarbon producing wells
US20080047706A1 (en) * 2006-08-23 2008-02-28 Pope Gary A Method of obtaining a treatment composition for improving the productivity of hydrocarbon producing wells
US20080113882A1 (en) * 2006-02-21 2008-05-15 3M Innovative Properties Company Sandstone having a modified wettability and a method for modifying the surface energy of sandstone
US20080209997A1 (en) * 2007-02-16 2008-09-04 William John Bailey System, method, and apparatus for fracture design optimization
US20090120642A1 (en) * 2007-11-14 2009-05-14 Halliburton Energy Services, Inc. Methods to enhance gas production following a relative-permeability-modifier treatment
WO2009076080A1 (en) * 2007-12-05 2009-06-18 3M Innovative Properties Company Method of treating proppants and fractures in-situ with fluorinated silane
WO2009073484A3 (en) * 2007-11-30 2009-08-13 Univ Texas Methods for improving the productivity of oil producing wells
US20090275490A1 (en) * 2008-05-05 2009-11-05 Arthur Milne Disproportionate Permeability Reduction Using A Viscoelastic Surfactant
US20090281002A1 (en) * 2008-05-09 2009-11-12 E. I. Du Pont De Nemours And Company Prevention and remediation of water and condensate blocks in wells
EP2132240A1 (en) * 2007-03-23 2009-12-16 Board of Regents, The University of Texas System Compositions and methods for treating a water blocked well
EP2140103A1 (en) * 2007-03-23 2010-01-06 Board of Regents, The University of Texas System Compositions and methods for treating a water blocked well
US20100018706A1 (en) * 2006-12-07 2010-01-28 Fan Wayne W Particles comprising a fluorinated siloxane and methods of making and using the same
US20100137169A1 (en) * 2007-03-23 2010-06-03 Board Of Regents, The University Of Texas System Method for Treating a Fractured Formation
US20100147515A1 (en) * 2008-12-16 2010-06-17 Trevor Lloyd Hughes Surface modification for cross-linking or breaking interactions with injected fluid
US20100163234A1 (en) * 2008-12-30 2010-07-01 Fuller Michael J Surface-Modifying Agents for Wettability Modification
US20100181068A1 (en) * 2007-03-23 2010-07-22 Board Of Regents, The University Of Texas System Method and System for Treating Hydrocarbon Formations
US7772162B2 (en) 2006-03-27 2010-08-10 Board Of Regents, The University Of Texas System Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US20100270020A1 (en) * 2007-12-21 2010-10-28 Baran Jr Jimmie R Methods for treating hydrocarbon-bearing formations with fluorinated anionic surfactant compositions
US20100270021A1 (en) * 2007-12-21 2010-10-28 Baran Jr Jimmie R Methods for treating hydrocarbon-bearing formations with fluorinated polymer compositions
US20100276149A1 (en) * 2007-03-23 2010-11-04 Pope Gary A Method for Treating a Hydrocarbon Formation
US20100285999A1 (en) * 2009-05-08 2010-11-11 Norman Lewis R Treatment fluids for reduction of water blocks, Oil blocks, and/or gas condensates and associated methods
US20100288498A1 (en) * 2007-12-21 2010-11-18 Moore George G I Fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
US20110021386A1 (en) * 2009-07-27 2011-01-27 Ali Syed A Microemulsion to improve shale gas production by controlling water imbibition
US20110053810A1 (en) * 2009-09-03 2011-03-03 Halliburton Energy Services, Inc. Fluorosurfactants and Treatment Fluids for Reduction of Water Blocks, Oil Blocks, and/or Gas Condensates and Associated Methods
US20110052874A1 (en) * 2009-07-02 2011-03-03 Wensheng Zhou Roofing articles with highly reflective coated granules
EP2300555A2 (en) * 2008-06-02 2011-03-30 Board of Regents, The University of Texas System Method for treating hydrocarbon-bearing formations with fluorinated epoxides
US20110092395A1 (en) * 2009-10-15 2011-04-21 E. I. Dupont De Nemours And Company Fluorinated vinylidene cationic surfactant
US20110092394A1 (en) * 2009-10-15 2011-04-21 E. I. Dupont De Nemours And Company Fluorinated cationic surfactant
US20110177985A1 (en) * 2010-01-15 2011-07-21 Saini Rajesh K Surfactants for Reduction of Water Blocks and/or Gas Condensates and Associated Methods
US20110177983A1 (en) * 2008-07-18 2011-07-21 Baran Jr Jimmie R Cationic fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
EP2451891A2 (en) * 2009-07-09 2012-05-16 3M Innovative Properties Company Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amphoteric compounds
CN102504790A (en) * 2011-11-09 2012-06-20 蒋官澄 Method for reversing gas humidity on surface of rock core by using cationic fluorocarbon surfactant
US20120181019A1 (en) * 2011-01-13 2012-07-19 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for altering wettability in oil field applications
US20120267109A1 (en) * 2011-04-25 2012-10-25 University Of Tulsa Method of treating a fractured well
US20120285689A1 (en) * 2011-05-12 2012-11-15 Halliburton Energy Services, Inc. Methods and Compositions for Clay Control
US20120285690A1 (en) * 2011-05-12 2012-11-15 Halliburton Energy Services, Inc. Multi-Stage Methods and Compositions for Desensitizing Subterranean Formations Faces
DE112010004042T5 (en) 2009-10-16 2012-11-29 Exxonmobil Upstream Research Co. Hydrocarbon operating fluids and methods for their use
DE112010004045T5 (en) 2009-10-16 2012-11-29 Exxonmobil Upstream Research Company Hydrocarbon operating fluids and methods for their use
CN103146371A (en) * 2011-12-06 2013-06-12 中国石油化工股份有限公司 Molecular film drag-reduction injection-stimulation agent for low permeability sandstone reservoir
CN103498650A (en) * 2013-10-24 2014-01-08 中国地质大学(北京) Method for improving yield of coal-bed gas well by achieving coal-bed surface gas reverse wetting
US8629089B2 (en) 2008-12-18 2014-01-14 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated ether compositions
US8701763B2 (en) 2008-05-05 2014-04-22 3M Innovative Properties Company Methods for treating hydrocarbon-bearing formations having brine
US8716198B2 (en) 2008-05-09 2014-05-06 E I Du Pont De Nemours And Company Prevention and remediation of water and condensate blocks in wells
EP2371924B1 (en) * 2009-05-12 2014-07-02 Clearwater International LLC Methods for increase gas production and load recovery
AU2013215336B2 (en) * 2012-02-02 2015-04-16 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for altering wettability in oil field applications
US9057012B2 (en) 2008-12-18 2015-06-16 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated phosphate and phosphonate compositions
WO2015171596A1 (en) * 2014-05-05 2015-11-12 Aramco Services Company Flash point adjustment of wettability alteration chemicals in hydrocarbon solvents
US20150354332A1 (en) * 2013-02-04 2015-12-10 Basf Se Process for treating subterranean oil-bearing formations comprising carbonate rocks
US20160069159A1 (en) * 2014-09-09 2016-03-10 Tadesse Weldu Teklu Matrix-fracture interface cleanup method for tight sandstone, carbonate, and shale reservoirs
US9353309B2 (en) 2007-03-23 2016-05-31 Board Of Regents, The University Of Texas System Method for treating a formation with a solvent
US9499737B2 (en) 2010-12-21 2016-11-22 3M Innovative Properties Company Method for treating hydrocarbon-bearing formations with fluorinated amine
US9624422B2 (en) 2010-12-20 2017-04-18 3M Innovative Properties Company Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amine oxides
US9701889B2 (en) 2011-01-13 2017-07-11 3M Innovative Properties Company Methods for treating siliciclastic hydrocarbon-bearing formations with fluorinated amine oxides
US9890294B2 (en) 2012-11-19 2018-02-13 3M Innovative Properties Company Composition including a fluorinated polymer and a non-fluorinated polymer and methods of making and using the same
CN107989581A (en) * 2016-10-26 2018-05-04 中国石油天然气股份有限公司 A kind of method and its verification method for improving High water cut densification Recovery of Gas Condensate Reservoirs
US10106724B2 (en) 2012-11-19 2018-10-23 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated ionic polymers
CN109138998A (en) * 2018-09-10 2019-01-04 西南石油大学 A kind of experimental test procedures of low permeability reservoir high temperature and pressure imbibition oil-recovering rate
US10227780B2 (en) 2009-12-31 2019-03-12 Firestone Building Products Co., LLC Asphaltic membrane with mullite-containing granules
CN110337479A (en) * 2017-02-27 2019-10-15 沙特阿拉伯石油公司 Interfacial tension is reduced using metal oxide nanoparticles and changes wetability to reduce condensate accumulation
CN111119819A (en) * 2020-01-21 2020-05-08 中国石油大学(华东) Method for reducing polymer adsorption of polymer injection flooding oil well
CN112029490A (en) * 2020-08-10 2020-12-04 中国石油天然气集团有限公司 Formula and preparation method of low-pressure gas field old well complex-production liquid-locking treatment agent
US10975292B2 (en) 2019-06-12 2021-04-13 Halliburton Energy Sendees, Inc. Omniphobic emulsions for mitigating gas condensate banking and methods of making and using same
US11015111B2 (en) 2017-07-20 2021-05-25 Saudi Arabian Oil Company Mitigation of condensate banking using surface modification
US11066593B2 (en) 2017-11-14 2021-07-20 Stepan Company Microemulsion flowback aids for oilfield uses
US11186762B2 (en) * 2017-08-31 2021-11-30 Halliburton Energy Services, Inc. Wettability modification for enhanced oil recovery
CN114479809A (en) * 2020-10-23 2022-05-13 中国石油化工股份有限公司 Water-lock-releasing chemical agent suitable for low-permeability natural gas reservoir containing condensate oil and preparation method and application thereof
US11485900B2 (en) 2019-01-23 2022-11-01 Saudi Arabian Oil Company Mitigation of condensate and water banking using functionalized nanoparticles
CN115572589A (en) * 2022-10-28 2023-01-06 中国石油天然气集团有限公司 Formula of water shutoff agent for gas well and preparation method thereof
US11572761B1 (en) 2021-12-14 2023-02-07 Saudi Arabian Oil Company Rigless method for selective zonal isolation in subterranean formations using colloidal silica
US11708521B2 (en) 2021-12-14 2023-07-25 Saudi Arabian Oil Company Rigless method for selective zonal isolation in subterranean formations using polymer gels
US11802232B2 (en) 2021-03-10 2023-10-31 Saudi Arabian Oil Company Polymer-nanofiller hydrogels

Families Citing this family (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
MX2016002733A (en) * 2016-03-02 2017-09-01 Univ Nacional Autónoma De México Synthesis process for the production of quarternary cationic salts that are useful as chemical tracers in carbonate reservoirs, and products produced with same.
CN108977185B (en) * 2017-06-02 2021-06-01 中国石油天然气集团公司 Cleaning fluid for removing pulverized coal, and preparation method and application thereof
US11741239B2 (en) 2018-10-17 2023-08-29 Omnitracs, Llc Blockchain-based hours-of-service system
EP4025666A1 (en) 2019-09-05 2022-07-13 Saudi Arabian Oil Company Propping open hydraulic fractures

Citations (19)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3100524A (en) * 1959-09-09 1963-08-13 Jersey Prod Res Co Recovery of oil from partially depleted reservoirs
US3653442A (en) * 1970-03-16 1972-04-04 Marathon Oil Co Stimulating low pressure natural gas producing wells
US5945493A (en) * 1998-06-19 1999-08-31 E. I. Du Pont De Nemours And Company Fluorine-containing maleic acid terpolymer soil and stain resists
US5964295A (en) * 1996-10-09 1999-10-12 Schlumberger Technology Corporation, Dowell Division Methods and compositions for testing subterranean formations
US6225263B1 (en) * 1996-07-17 2001-05-01 Bp Chemicals Limited Use of oil and gas field chemicals
US6258859B1 (en) * 1997-06-10 2001-07-10 Rhodia, Inc. Viscoelastic surfactant fluids and related methods of use
US6399546B1 (en) * 1999-10-15 2002-06-04 Schlumberger Technology Corporation Fluid system having controllable reversible viscosity
US6435277B1 (en) * 1996-10-09 2002-08-20 Schlumberger Technology Corporation Compositions containing aqueous viscosifying surfactants and methods for applying such compositions in subterranean formations
US6579572B2 (en) * 2001-08-13 2003-06-17 Intevep, S.A. Water-based system for altering wettability of porous media
US6646088B2 (en) * 2000-08-16 2003-11-11 3M Innovative Properties Company Urethane-based stain-release coatings
US6689854B2 (en) * 2001-08-23 2004-02-10 3M Innovative Properties Company Water and oil repellent masonry treatments
US6753380B2 (en) * 2001-03-09 2004-06-22 3M Innovative Properties Company Water-and oil-repellency imparting ester oligomers comprising perfluoroalkyl moieties
US20040147188A1 (en) * 2003-01-28 2004-07-29 3M Innovative Properties Company Fluorochemical urethane composition for treatment of fibrous substrates
US6803109B2 (en) * 2001-03-09 2004-10-12 3M Innovative Properties Company Water-and oil-repellency imparting urethane oligomers comprising perfluoroalkyl moieties
US20050075471A1 (en) * 2003-10-06 2005-04-07 3M Innovative Properties Company Stain resistant polyurethane coatings
US6911417B2 (en) * 2003-04-29 2005-06-28 Conocophillips Company Water block removal with surfactant based hydrocarbonaceous liquid system
US20050143541A1 (en) * 2003-12-31 2005-06-30 3M Innovative Properties Company Water- and oil-repellent fluoroacrylates
US6945327B2 (en) * 2003-02-11 2005-09-20 Ely & Associates, Inc. Method for reducing permeability restriction near wellbore
US7255166B1 (en) * 2004-07-28 2007-08-14 William Weiss Imbibition well stimulation via neural network design

Family Cites Families (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2127462B (en) * 1982-09-01 1986-02-19 British Petroleum Co Plc Compositions suitable for modifying wettability and their use
US5247993A (en) * 1992-06-16 1993-09-28 Union Oil Company Of California Enhanced imbibition oil recovery process
FR2744760B1 (en) * 1996-02-14 1998-04-17 Inst Francais Du Petrole PROCESS FOR IMPROVING THE RECOVERY OF HYDROCARBONS IN A POROUS MEDIUM AND PRODUCTS FOR IMPLEMENTING SAME

Patent Citations (23)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3100524A (en) * 1959-09-09 1963-08-13 Jersey Prod Res Co Recovery of oil from partially depleted reservoirs
US3653442A (en) * 1970-03-16 1972-04-04 Marathon Oil Co Stimulating low pressure natural gas producing wells
US6225263B1 (en) * 1996-07-17 2001-05-01 Bp Chemicals Limited Use of oil and gas field chemicals
US6435277B1 (en) * 1996-10-09 2002-08-20 Schlumberger Technology Corporation Compositions containing aqueous viscosifying surfactants and methods for applying such compositions in subterranean formations
US5964295A (en) * 1996-10-09 1999-10-12 Schlumberger Technology Corporation, Dowell Division Methods and compositions for testing subterranean formations
US5979557A (en) * 1996-10-09 1999-11-09 Schlumberger Technology Corporation Methods for limiting the inflow of formation water and for stimulating subterranean formations
US6306800B1 (en) * 1996-10-09 2001-10-23 Schlumberger Technology Corporation Methods of fracturing subterranean formations
US6258859B1 (en) * 1997-06-10 2001-07-10 Rhodia, Inc. Viscoelastic surfactant fluids and related methods of use
US5945493A (en) * 1998-06-19 1999-08-31 E. I. Du Pont De Nemours And Company Fluorine-containing maleic acid terpolymer soil and stain resists
US6238792B1 (en) * 1998-06-19 2001-05-29 E. I. Du Pont De Nemours And Company Fluorine-containing maleic acid terpolymer soil and stain resists
US6245116B1 (en) * 1998-06-19 2001-06-12 E. I. Du Pont De Nemours And Company Fluorine-containing maleic acid terpolymer soil and stain resists
US6399546B1 (en) * 1999-10-15 2002-06-04 Schlumberger Technology Corporation Fluid system having controllable reversible viscosity
US6646088B2 (en) * 2000-08-16 2003-11-11 3M Innovative Properties Company Urethane-based stain-release coatings
US6753380B2 (en) * 2001-03-09 2004-06-22 3M Innovative Properties Company Water-and oil-repellency imparting ester oligomers comprising perfluoroalkyl moieties
US6803109B2 (en) * 2001-03-09 2004-10-12 3M Innovative Properties Company Water-and oil-repellency imparting urethane oligomers comprising perfluoroalkyl moieties
US6579572B2 (en) * 2001-08-13 2003-06-17 Intevep, S.A. Water-based system for altering wettability of porous media
US6689854B2 (en) * 2001-08-23 2004-02-10 3M Innovative Properties Company Water and oil repellent masonry treatments
US20040147188A1 (en) * 2003-01-28 2004-07-29 3M Innovative Properties Company Fluorochemical urethane composition for treatment of fibrous substrates
US6945327B2 (en) * 2003-02-11 2005-09-20 Ely & Associates, Inc. Method for reducing permeability restriction near wellbore
US6911417B2 (en) * 2003-04-29 2005-06-28 Conocophillips Company Water block removal with surfactant based hydrocarbonaceous liquid system
US20050075471A1 (en) * 2003-10-06 2005-04-07 3M Innovative Properties Company Stain resistant polyurethane coatings
US20050143541A1 (en) * 2003-12-31 2005-06-30 3M Innovative Properties Company Water- and oil-repellent fluoroacrylates
US7255166B1 (en) * 2004-07-28 2007-08-14 William Weiss Imbibition well stimulation via neural network design

Cited By (121)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7629298B2 (en) 2006-02-21 2009-12-08 3M Innovative Properties Company Sandstone having a modified wettability and a method for modifying the surface energy of sandstone
US20080113882A1 (en) * 2006-02-21 2008-05-15 3M Innovative Properties Company Sandstone having a modified wettability and a method for modifying the surface energy of sandstone
US7855169B2 (en) 2006-03-27 2010-12-21 Board Of Regents, The University Of Texas System Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US7772162B2 (en) 2006-03-27 2010-08-10 Board Of Regents, The University Of Texas System Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US20070225176A1 (en) * 2006-03-27 2007-09-27 Pope Gary A Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US20080051300A1 (en) * 2006-08-23 2008-02-28 Pope Gary A Compositions and method for improving the productivity of hydrocarbon producing wells
US7585817B2 (en) 2006-08-23 2009-09-08 Board Of Regents, The University Of Texas System Compositions and methods for improving the productivity of hydrocarbon producing wells using a non-ionic fluorinated polymeric surfactant
US20080047706A1 (en) * 2006-08-23 2008-02-28 Pope Gary A Method of obtaining a treatment composition for improving the productivity of hydrocarbon producing wells
US20080051551A1 (en) * 2006-08-23 2008-02-28 Board Of Regents, The University Of Texas System Compositions and methods for improving the productivity of hydrocarbon producing wells
US20100018706A1 (en) * 2006-12-07 2010-01-28 Fan Wayne W Particles comprising a fluorinated siloxane and methods of making and using the same
US8236737B2 (en) 2006-12-07 2012-08-07 3M Innovative Properties Company Particles comprising a fluorinated siloxane and methods of making and using the same
US20080209997A1 (en) * 2007-02-16 2008-09-04 William John Bailey System, method, and apparatus for fracture design optimization
EA017137B1 (en) * 2007-02-16 2012-10-30 Шлюмбергер Текнолоджи Б.В. System, method and apparatus for fracture design optimization
US7908230B2 (en) 2007-02-16 2011-03-15 Schlumberger Technology Corporation System, method, and apparatus for fracture design optimization
US20100224361A1 (en) * 2007-03-23 2010-09-09 Board Of Regents, The University Of Texas System Compositions and Methods for Treating a Water Blocked Well
CN101809044A (en) * 2007-03-23 2010-08-18 德克萨斯州立大学董事会 Be used to handle the composition and the method for water blocked well
EP2132240A4 (en) * 2007-03-23 2010-03-10 Univ Texas Compositions and methods for treating a water blocked well
US20100137169A1 (en) * 2007-03-23 2010-06-03 Board Of Regents, The University Of Texas System Method for Treating a Fractured Formation
EP2132240A1 (en) * 2007-03-23 2009-12-16 Board of Regents, The University of Texas System Compositions and methods for treating a water blocked well
US20100167964A1 (en) * 2007-03-23 2010-07-01 Board Of Regents, The University Of Texas System Compositions and Methods for Treating a Water Blocked Well
US8138127B2 (en) * 2007-03-23 2012-03-20 Board Of Regents, The University Of Texas Compositions and methods for treating a water blocked well using a nonionic fluorinated surfactant
US20100181068A1 (en) * 2007-03-23 2010-07-22 Board Of Regents, The University Of Texas System Method and System for Treating Hydrocarbon Formations
US8403050B2 (en) * 2007-03-23 2013-03-26 3M Innovative Properties Company Method for treating a hydrocarbon-bearing formation with a fluid followed by a nonionic fluorinated polymeric surfactant
EP2140103A1 (en) * 2007-03-23 2010-01-06 Board of Regents, The University of Texas System Compositions and methods for treating a water blocked well
US9353309B2 (en) 2007-03-23 2016-05-31 Board Of Regents, The University Of Texas System Method for treating a formation with a solvent
US8043998B2 (en) 2007-03-23 2011-10-25 Board Of Regents, The University Of Texas System Method for treating a fractured formation with a non-ionic fluorinated polymeric surfactant
EP2140103A4 (en) * 2007-03-23 2011-08-03 Univ Texas Compositions and methods for treating a water blocked well
US20100276149A1 (en) * 2007-03-23 2010-11-04 Pope Gary A Method for Treating a Hydrocarbon Formation
US20090120642A1 (en) * 2007-11-14 2009-05-14 Halliburton Energy Services, Inc. Methods to enhance gas production following a relative-permeability-modifier treatment
WO2009073484A3 (en) * 2007-11-30 2009-08-13 Univ Texas Methods for improving the productivity of oil producing wells
US20100319920A1 (en) * 2007-11-30 2010-12-23 Board Of Regents, The University Of Texas System Methods for improving the productivity of oil producing wells
US8261825B2 (en) 2007-11-30 2012-09-11 Board Of Regents, The University Of Texas System Methods for improving the productivity of oil producing wells
CN101889066A (en) * 2007-12-05 2010-11-17 3M创新有限公司 Method of treating proppants and fractures in-situ with fluorinated silane
WO2009076080A1 (en) * 2007-12-05 2009-06-18 3M Innovative Properties Company Method of treating proppants and fractures in-situ with fluorinated silane
US20100270021A1 (en) * 2007-12-21 2010-10-28 Baran Jr Jimmie R Methods for treating hydrocarbon-bearing formations with fluorinated polymer compositions
US8418759B2 (en) 2007-12-21 2013-04-16 3M Innovative Properties Company Fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
US20100288498A1 (en) * 2007-12-21 2010-11-18 Moore George G I Fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
US8678090B2 (en) 2007-12-21 2014-03-25 3M Innovative Properties Company Methods for treating hydrocarbon-bearing formations with fluorinated polymer compositions
US20100270020A1 (en) * 2007-12-21 2010-10-28 Baran Jr Jimmie R Methods for treating hydrocarbon-bearing formations with fluorinated anionic surfactant compositions
US8701763B2 (en) 2008-05-05 2014-04-22 3M Innovative Properties Company Methods for treating hydrocarbon-bearing formations having brine
US20090275490A1 (en) * 2008-05-05 2009-11-05 Arthur Milne Disproportionate Permeability Reduction Using A Viscoelastic Surfactant
US8895483B2 (en) 2008-05-05 2014-11-25 Schlumberger Technology Corporation Disproportionate permeability reduction using a viscoelastic surfactant
US8716198B2 (en) 2008-05-09 2014-05-06 E I Du Pont De Nemours And Company Prevention and remediation of water and condensate blocks in wells
US20090281002A1 (en) * 2008-05-09 2009-11-12 E. I. Du Pont De Nemours And Company Prevention and remediation of water and condensate blocks in wells
EP2300555A2 (en) * 2008-06-02 2011-03-30 Board of Regents, The University of Texas System Method for treating hydrocarbon-bearing formations with fluorinated epoxides
CN102149787A (en) * 2008-06-02 2011-08-10 德克萨斯州立大学董事会 Method for treating hydrocarbon-bearing formations with fluorinated epoxides
US20110201531A1 (en) * 2008-06-02 2011-08-18 Board Of Regents, The University Of Texas System Method for Treating Hydrocarbon-Bearing Formations with Fluorinated Epoxides
EP2300555A4 (en) * 2008-06-02 2012-01-04 Univ Texas Method for treating hydrocarbon-bearing formations with fluorinated epoxides
US20110177983A1 (en) * 2008-07-18 2011-07-21 Baran Jr Jimmie R Cationic fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
US9200102B2 (en) 2008-07-18 2015-12-01 3M Innovative Properties Company Cationic fluorinated polymer compositions and methods for treating hydrocarbon-bearing formations using the same
US8360149B2 (en) * 2008-12-16 2013-01-29 Schlumberger Technology Corporation Surface modification for cross-linking or breaking interactions with injected fluid
US20100147515A1 (en) * 2008-12-16 2010-06-17 Trevor Lloyd Hughes Surface modification for cross-linking or breaking interactions with injected fluid
US9057012B2 (en) 2008-12-18 2015-06-16 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated phosphate and phosphonate compositions
US8629089B2 (en) 2008-12-18 2014-01-14 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated ether compositions
US7921911B2 (en) 2008-12-30 2011-04-12 Schlumberger Technology Corporation Surface-modifying agents for wettability modification
US20100163234A1 (en) * 2008-12-30 2010-07-01 Fuller Michael J Surface-Modifying Agents for Wettability Modification
AU2010244262B2 (en) * 2009-05-08 2012-11-29 Halliburton Energy Services, Inc. Treatment fluids for reduction of water blocks, oil blocks, and/or gas condensates and associated methods
US8101556B2 (en) 2009-05-08 2012-01-24 Halliburton Energy Services, Inc. Treatment fluids for reduction of water blocks, oil blocks, and/or gas condensates and associated methods
WO2010128270A3 (en) * 2009-05-08 2011-03-31 Halliburton Energy Services, Inc. Treatment fluids for reduction of water blocks, oil blocks, and/or gas condensates and associated methods
US20100285999A1 (en) * 2009-05-08 2010-11-11 Norman Lewis R Treatment fluids for reduction of water blocks, Oil blocks, and/or gas condensates and associated methods
EP2251395B1 (en) * 2009-05-12 2014-07-30 Clearwater International LLC Methods for increase gas production and load recovery
EP2371924B1 (en) * 2009-05-12 2014-07-02 Clearwater International LLC Methods for increase gas production and load recovery
US20110052874A1 (en) * 2009-07-02 2011-03-03 Wensheng Zhou Roofing articles with highly reflective coated granules
EP2451891A2 (en) * 2009-07-09 2012-05-16 3M Innovative Properties Company Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amphoteric compounds
US8833449B2 (en) 2009-07-09 2014-09-16 3M Innovative Properties Company Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amphoteric compounds
EP2451891A4 (en) * 2009-07-09 2013-10-09 3M Innovative Properties Co Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amphoteric compounds
CN102575146A (en) * 2009-07-27 2012-07-11 普拉德研究及开发股份有限公司 Microemulsion to improve shale gas production by controlling water imbibition
WO2011013025A1 (en) * 2009-07-27 2011-02-03 Schlumberger Canada Limited Microemulsion to improve shale gas production by controlling water imbibition
US20110021386A1 (en) * 2009-07-27 2011-01-27 Ali Syed A Microemulsion to improve shale gas production by controlling water imbibition
US8772204B2 (en) 2009-09-03 2014-07-08 Halliburton Energy Services, Inc. Fluorosurfactants and treatment fluids for reduction of water blocks, oil blocks, and/or gas condensates and associated methods
US20110053810A1 (en) * 2009-09-03 2011-03-03 Halliburton Energy Services, Inc. Fluorosurfactants and Treatment Fluids for Reduction of Water Blocks, Oil Blocks, and/or Gas Condensates and Associated Methods
US8669212B2 (en) * 2009-09-03 2014-03-11 Halliburton Energy Services, Inc. Fluorosurfactants and treatment fluids for reduction of water blocks, oil blocks, and/or gas condensates and associated methods
US20110092394A1 (en) * 2009-10-15 2011-04-21 E. I. Dupont De Nemours And Company Fluorinated cationic surfactant
US8168683B2 (en) 2009-10-15 2012-05-01 E. I. Du Pont De Nemours And Company Fluorinated vinylidene cationic surfactant
US8580715B2 (en) 2009-10-15 2013-11-12 E I Du Pont De Nemours And Company Fluorinated cationic surfactant
US20110092395A1 (en) * 2009-10-15 2011-04-21 E. I. Dupont De Nemours And Company Fluorinated vinylidene cationic surfactant
DE112010004045T5 (en) 2009-10-16 2012-11-29 Exxonmobil Upstream Research Company Hydrocarbon operating fluids and methods for their use
DE112010004042T5 (en) 2009-10-16 2012-11-29 Exxonmobil Upstream Research Co. Hydrocarbon operating fluids and methods for their use
US10626615B2 (en) 2009-12-31 2020-04-21 Firestone Building Products Co., LLC Asphaltic membrane with mullite-containing granules
US10227780B2 (en) 2009-12-31 2019-03-12 Firestone Building Products Co., LLC Asphaltic membrane with mullite-containing granules
US20110177985A1 (en) * 2010-01-15 2011-07-21 Saini Rajesh K Surfactants for Reduction of Water Blocks and/or Gas Condensates and Associated Methods
US9624422B2 (en) 2010-12-20 2017-04-18 3M Innovative Properties Company Methods for treating carbonate hydrocarbon-bearing formations with fluorinated amine oxides
US9499737B2 (en) 2010-12-21 2016-11-22 3M Innovative Properties Company Method for treating hydrocarbon-bearing formations with fluorinated amine
US8763703B2 (en) * 2011-01-13 2014-07-01 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for altering wettability in oil field applications
US20120181019A1 (en) * 2011-01-13 2012-07-19 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for altering wettability in oil field applications
US9701889B2 (en) 2011-01-13 2017-07-11 3M Innovative Properties Company Methods for treating siliciclastic hydrocarbon-bearing formations with fluorinated amine oxides
US20120267109A1 (en) * 2011-04-25 2012-10-25 University Of Tulsa Method of treating a fractured well
AU2012252122B2 (en) * 2011-05-12 2014-08-07 Halliburton Energy Services Inc Methods and compositions for clay control
US20120285689A1 (en) * 2011-05-12 2012-11-15 Halliburton Energy Services, Inc. Methods and Compositions for Clay Control
US8757261B2 (en) * 2011-05-12 2014-06-24 Halliburton Energy Services, Inc. Methods and compositions for clay control
US20120285690A1 (en) * 2011-05-12 2012-11-15 Halliburton Energy Services, Inc. Multi-Stage Methods and Compositions for Desensitizing Subterranean Formations Faces
CN102504790A (en) * 2011-11-09 2012-06-20 蒋官澄 Method for reversing gas humidity on surface of rock core by using cationic fluorocarbon surfactant
CN103146371A (en) * 2011-12-06 2013-06-12 中国石油化工股份有限公司 Molecular film drag-reduction injection-stimulation agent for low permeability sandstone reservoir
AU2013215336B2 (en) * 2012-02-02 2015-04-16 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for altering wettability in oil field applications
US9890294B2 (en) 2012-11-19 2018-02-13 3M Innovative Properties Company Composition including a fluorinated polymer and a non-fluorinated polymer and methods of making and using the same
US10106724B2 (en) 2012-11-19 2018-10-23 3M Innovative Properties Company Method of contacting hydrocarbon-bearing formations with fluorinated ionic polymers
US10494907B2 (en) * 2013-02-04 2019-12-03 Basf Se Process for treating subterranean oil-bearing formations comprising carbonate rocks
US20150354332A1 (en) * 2013-02-04 2015-12-10 Basf Se Process for treating subterranean oil-bearing formations comprising carbonate rocks
CN103498650A (en) * 2013-10-24 2014-01-08 中国地质大学(北京) Method for improving yield of coal-bed gas well by achieving coal-bed surface gas reverse wetting
WO2015171596A1 (en) * 2014-05-05 2015-11-12 Aramco Services Company Flash point adjustment of wettability alteration chemicals in hydrocarbon solvents
US10577528B2 (en) 2014-05-05 2020-03-03 Saudi Arabian Oil Company Flash point adjustment of wettability alteration chemicals in hydrocarbon solvents
US10253243B2 (en) 2014-05-05 2019-04-09 Saudi Arabian Oil Company Flash point adjustment of wettability alteration chemicals in hydrocarbon solvents
US20160069159A1 (en) * 2014-09-09 2016-03-10 Tadesse Weldu Teklu Matrix-fracture interface cleanup method for tight sandstone, carbonate, and shale reservoirs
CN107989581A (en) * 2016-10-26 2018-05-04 中国石油天然气股份有限公司 A kind of method and its verification method for improving High water cut densification Recovery of Gas Condensate Reservoirs
CN110337479A (en) * 2017-02-27 2019-10-15 沙特阿拉伯石油公司 Interfacial tension is reduced using metal oxide nanoparticles and changes wetability to reduce condensate accumulation
JP2020514494A (en) * 2017-02-27 2020-05-21 サウジ アラビアン オイル カンパニー Reduction of interfacial tension and modification of wettability using metal oxide nanoparticles to reduce condensate banking
US11015111B2 (en) 2017-07-20 2021-05-25 Saudi Arabian Oil Company Mitigation of condensate banking using surface modification
US11186762B2 (en) * 2017-08-31 2021-11-30 Halliburton Energy Services, Inc. Wettability modification for enhanced oil recovery
US11697758B2 (en) 2017-08-31 2023-07-11 Halliburton Energy Services, Inc. Wettability modification for enhanced oil recovery
US11066593B2 (en) 2017-11-14 2021-07-20 Stepan Company Microemulsion flowback aids for oilfield uses
CN109138998A (en) * 2018-09-10 2019-01-04 西南石油大学 A kind of experimental test procedures of low permeability reservoir high temperature and pressure imbibition oil-recovering rate
US11485900B2 (en) 2019-01-23 2022-11-01 Saudi Arabian Oil Company Mitigation of condensate and water banking using functionalized nanoparticles
US10975292B2 (en) 2019-06-12 2021-04-13 Halliburton Energy Sendees, Inc. Omniphobic emulsions for mitigating gas condensate banking and methods of making and using same
US11578258B2 (en) 2019-06-12 2023-02-14 Halliburton Energy Services, Inc. Omniphobic emulsions for mitigating gas condensate banking and methods of making and using same
CN111119819A (en) * 2020-01-21 2020-05-08 中国石油大学(华东) Method for reducing polymer adsorption of polymer injection flooding oil well
CN112029490A (en) * 2020-08-10 2020-12-04 中国石油天然气集团有限公司 Formula and preparation method of low-pressure gas field old well complex-production liquid-locking treatment agent
CN114479809A (en) * 2020-10-23 2022-05-13 中国石油化工股份有限公司 Water-lock-releasing chemical agent suitable for low-permeability natural gas reservoir containing condensate oil and preparation method and application thereof
US11802232B2 (en) 2021-03-10 2023-10-31 Saudi Arabian Oil Company Polymer-nanofiller hydrogels
US11572761B1 (en) 2021-12-14 2023-02-07 Saudi Arabian Oil Company Rigless method for selective zonal isolation in subterranean formations using colloidal silica
US11708521B2 (en) 2021-12-14 2023-07-25 Saudi Arabian Oil Company Rigless method for selective zonal isolation in subterranean formations using polymer gels
CN115572589A (en) * 2022-10-28 2023-01-06 中国石油天然气集团有限公司 Formula of water shutoff agent for gas well and preparation method thereof

Also Published As

Publication number Publication date
CA2617315A1 (en) 2007-02-15
WO2007017806A3 (en) 2007-06-21
WO2007017806A2 (en) 2007-02-15

Similar Documents

Publication Publication Date Title
US20070029085A1 (en) Prevention of Water and Condensate Blocks in Wells
US8138127B2 (en) Compositions and methods for treating a water blocked well using a nonionic fluorinated surfactant
US8043998B2 (en) Method for treating a fractured formation with a non-ionic fluorinated polymeric surfactant
US8403050B2 (en) Method for treating a hydrocarbon-bearing formation with a fluid followed by a nonionic fluorinated polymeric surfactant
US7772162B2 (en) Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US20100224361A1 (en) Compositions and Methods for Treating a Water Blocked Well
US10648304B2 (en) Method of using surface modifying treatment agents to treat subterranean formations
US6945327B2 (en) Method for reducing permeability restriction near wellbore
US8261825B2 (en) Methods for improving the productivity of oil producing wells
Bang et al. A new solution to restore productivity of gas wells with condensate and water blocks
US20070225176A1 (en) Use of fluorocarbon surfactants to improve the productivity of gas and gas condensate wells
US7549472B2 (en) Method for increasing the production of hydrocarbon liquids and gases
US10160904B2 (en) Volatile surfactant treatment for subterranean formations
US10240078B2 (en) Volatile surfactant treatment for use in subterranean formation operations
Adibhatla et al. Effect of surfactants on wettability of near-wellbore regions of gas reservoirs
AU2014337582A1 (en) Volatile surfactant treatment for use in subterranean formation operations
AU2013403405A1 (en) Volatile surfactant treatment for subterranean formations
Rostami et al. Laboratory studies on fluid-recovery enhancement and mitigation of phase trapping by use of microemulsion in gas sandstone formations
Xie et al. Wettability alteration to increase deliverability of gas production wells
Fahimpour Wettability alteration of carbonate rocks to alleviate condensate blockage around gas-condensate wells
Tangirala Experimental study of the impact of frac fluid invasion and mitigation of formation damage using surfactants in conventional and tight formations
Elsafih Study towards improving the efficiency of matrix acidizing in oil-bearing carbonate formations
Rostami Improving fluid recovery and permeability to gas in shale formations
Garst A Low Cost Method of Production Stimulation

Legal Events

Date Code Title Description
AS Assignment

Owner name: SCHLUMBERGER TECHNOLOGY CORPORATION, TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:PANGA, MOHAN K.R.;SAMUEL, MATHEW;CHAN, KENG SENG;AND OTHERS;REEL/FRAME:018214/0478;SIGNING DATES FROM 20060801 TO 20060822

STCB Information on status: application discontinuation

Free format text: ABANDONED -- AFTER EXAMINER'S ANSWER OR BOARD OF APPEALS DECISION