Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3308885 A
Publication typeGrant
Publication dateMar 14, 1967
Filing dateDec 28, 1965
Priority dateDec 28, 1965
Publication numberUS 3308885 A, US 3308885A, US-A-3308885, US3308885 A, US3308885A
InventorsBurton B Sandiford
Original AssigneeUnion Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Treatment of subsurface hydrocarbon fluid-bearing formations to reduce water production therefrom
US 3308885 A
Images(4)
Previous page
Next page
Description  (OCR text may contain errors)

United States Patent O TREATMENT OF SUBSURFACE HYDROCARBON FLUID-BEARING FORMATIONS TO REDUCE WATER PRODUCTION THEREFROM Burton B. Sandiford, Placeutla, Califi, assignor to Union Oil Company of California, Los Angeles, Calif., a corporation of California No Dram'ng. Filed Dec. 28, 1965, Ser. No. 517,109

Claims. (Cl. 16633) This application is a continuation-in-part of prior co-' pending application Serial No. 285,216, filed June 4, 1963, and now abandoned.

This invention relates to the treatment of subterranean hydrocarboniferous formations so as to improve the efli ciency of recovery of fluid hydrocarbons therefrom via producing wells traversing such formations. More specifically, the invention relates to methods for decreasing the water/ oil ratio in the total well eflluent, and for increasing the daily production rate of hydrocarbonaceous fluids.

In broad aspect, the invention comprises injecting into the formation, through a producing well, a substantial quantity of an aqueous solution, or sol, of a high molecular weight, water-soluble polyacrylamide (PAM) wherein at least about 8%, but not more than about 70% of the amide groups have been hydrolyzed to carboxylic acid groups. Following injection of the aqueous PAM solution into the formation, the well is then placed back on production, and it is found that, under the same conditions as were employed prior to the treatment, there is a substantial reduction in water/oil ratio of the well efliuent, due primarily to a reduced flow rate of water into the well bore. Moreover, as a result of this decreased water flow rate, there will be, at the same gross production rate, a reduction in fluid level over the pump, with resultant decrease in back pressure on the formation, thus permitting oil to move more rapidly out of the formation into the well bore. Thus, although the immediate effect of the treating process of this invention is to decrease the rate of flow of water into the well bore, a secondary effect of increasing the absolute daily production rate of oil is also obtainable.

As those skilled in the art are Well aware, the production of large amounts of water from oil wells and gas wells constitutes one of the major items of expense in the overall recovery of hydrocarbons therefrom. Many oil wells will produce a gross eflluent comprising 80-90% by volume of water and only 10-20% of oil. Most of the pumping energy is therefore expended in lifting water from the well, and thereafter the eflluent must be put through expensive separation procedures to recover waterfree oil. The remaining foul water constitutes a troublesome and expensive disposal problem. It is therefore highly desirable to decrease the volume of water produced from oil wells and gas wells, this being the major objective of the present invention. But, by decreasing the flow rate of water into the well bore without decreasing the flow rate of oil, another beneficial effect is obtained in that, at a given pumping rate, there will be a lower liquid level over the pump in the well bore, thus reducing back-pressure on the formation, and improving pumping efliciency and net daily oil production.

.I am unable to account with any degree of certainty for the beneficial effects observed herein, but it would appear that such effects are attributable primarily to an actual combining or coating of the mineral particle surfaces in the formation with the PAM treating agent. Production water from wells treated by the process of this invention does not become entirely free of the PAM treating agent for many weeks after the treatment. -It is therefore believed that the said treating agent has some considerable tendency to remain affixed in the formation, either by chemical bonding or electrostatic attraction, to the mineral surfaces defining the pores thereof, and behaves as a surfactant, or perhaps a selective plugging agent, to restrict the flow of water in the formaion without restricting the flow of oil.

The process of this invention is not to be confused with secondary recovery processes, wherein a depleted or partially depleted well is put back into production, or production is improved, by water flooding, or fluid drive techniques. In these latter processes, water or other aqueous media is pumped into one or more injection wells under a pressure sufficient to cause the water to flow outwardly therefrom through the oil-bearing formation towards one or more relatively depleted producing wells. Theoretically, as the water flows through the oilbearing formation the oil contained therein is forced ahead of the advancing water front into the producing wells. It is well known that water alone is relatively inefficient in this flooding technique because the water chooses the path of least resistance, i.e., the strata of highest permeability, and hence travels from the injection well to the producing wells in more or less well defined channels and fails to sweep the oil efficiently from the formation as a whole. Normally, the strata of high est permeability are water-bearing, or at least water-wet, and their permeabilities are higher with respect to water than to other fluids, particularly petroleum, and this condition aggravates the channeling of the sweep fluid.

In US. Patents Nos. 2,827,964, and 3,039,529, it is shown that the aforedescribed water flooding techniques can be materially improved by using as the flooding media, somewhat viscous solutions of partially hydrolyzed PAM-solutions of the same nature as may be employed in the treating process of this invention. US. Patent No. 3,020,953 shows that solutions of completely unhydrolyzed PAM can also be used in water flooding operations. The effect of all of these viscous PAM solutions, hydrolyzed or unhydrolyzed, is to cause the flooding medium to advance through the formation to the producing wells in a more or less plane front rather than in channels through the more permeable strata. beneficial effect of PAM solutions in these flooding techniques thus is believed to rest primarily upon their rheological properties, rather than upon the specific chemical The producing well, in the process of this invention the beneficial effects accrue only while there is a significant amount of treating agent in the formation surrounding the well bore, and they theoretically will terminate when all of the treating agent has been swept from the formation back into the well bore.

US. Patent No. 3,087,543 to Arendt describes a treating process which, in its essential mechanics, is the same as the present process. However, there is no disclosure in the Arendt patent of the 870% hydrolyzed poly-acrylamides required herein. As will be shown hereinafter, this specific class of treating agents has been found to be much more effective in reducing water permeability than the acrylamide-carboxylic acid copolymer disclosed in the Arendt patent.

The PAM treating agents of the present invention are characterized in general by a molecular weight of at least about 200,000 and preferably at least about 1,000,- 000, with at least about 8%, and up to about 70%, preferably up to about 25%, of the amide groups being bydrolyzed to canboxylic groups. A 0.5% by weight aqueous solution of the treating agent should have a viscosity of at least about 4, and preferably at least about 10 centipoises (Ostwald) at 21.5 C. Hydrolysis of the acrylamide polymer is accomplished by reacting the same with sufficient of aqueous alkali, e.g., sodium hydroxide, to hydrolyze between about 8% and 70% of the amide groups present in the polymer molecule. The resulting products consist of a long hydrocanbon chain, the alternate carbon atoms of which bear either amide or carboxylic groups. A number of partially hydrolyzed acrylamide polymers suitable for use herein are commercially available, for example materials marketed by Dow Chemical Company under the trade names Separan NP-ZO or ET-601. Polymers hydrolyzed to an extent greater than about 70% are undesirable in that they have a greater tendency to form precipitates with polyvalent metal ions found in connate (reservoir) waters, with resultant plugging of the formation. Polymers wherein less than about 8% of the amide group have been hydrolyzed are considerably less effective in reducing water permeability, and are hence excluded herein.

The concentration of PAM treating agent in the aqueous solution pumped down the well may vary over a wide range, from about 1 p.p.m. to about 5% by weight. The optimum concentration will depend to a large extent upon the volume of reservoir water with which the treating solution will be diluted in the formation. It is preferred to adjust the concentration of treating agent, and the volume of the aqueous slug injected, so that the concentration of treating agent in the formation waters will be between about 0.01% and 0.5% by weight. It is further preferred that the volume of the aqueous slug injected be between about 0.02% and 5% of the oil volume in the oil recovery area around the given producing well being treated.

In carrying out the process of this invention, conventional injection procedures are employed, i.e., the well to be treated is suitably fitted with packers if required, and the aqueous treating agent is forced down the well bore and out into the reservoir formation by means of conventional pumping equipment (if required) located at the well head. Normally, the injection can be completed in about /2-3 days, after which the well may be substantially immediately placed back on production. The initial well effluent following the treatment is sharply reduced in water/ oil ratio, and production may be continued for several weeks or months with improved oil recovery and reduced water production. Gradually however the wateroil ratio will begin to rise again, and when the ratio reaches an undesirably high level, the well may be again shut in and the treatment repeated to again improve production.

Following a given treatment, the initial production water recovered when the well is placed back on production may be fairly rich in the PAM treating agent. If

desired this portion of the aqueous effiuent may be reused, or employed for treating other wells. As previously noted however, most of the PAM treating agent remains in the formation for long periods of time, and the production water following a given treatment very rapidly declines in PAM concentration, such that reuse is not feasible.

In one mode of operation it is contemplated that the retention of PAM in the formation, and its resultant effectiveness as a treating agent, may be further improved by first treating the formation wit-h a hydrocarbon solvent in order to dissolve out heavy hydrocarbonaceous materials, thus opening up the pores and rendering the mineral surfaces more readily available for contact with the PAM treating agent to be subsequently injected. Suitable solvents include for example pentane, benzene, light aromatic gasoline fractions and the like. Such a pretreatment with hydrocarbon solvent is accomplished by pumping, e.g., about 10-500 barrels of the desired solvent into the formation, and then putting the well back on production for a short time to remove the tar-laden solvent, after which the PAM treating agent is injected.

The process of this invention is designed for treating substantially any type of producing well, either an oil well or a gas well. Such well may be operating under natural flow conditions, or it may be a producing well involved in a secondary recovery operation wherein a flooding medium, or gaseous driving medium, is being injected into an adjacent well. It is contemplated that in such secondary recovery operations, treatment of the producing well will cause the selective diversion of reservoir waters to other wells, or to adjacent aquafer structures, thus reducing the water/ oil ratio in the producing well effluent.

The following examples are cited to illustrate the invention, and to demonstrate the beneficial results obtained, but are not to be construed as limiting in scope.

Example I This example demonstrates the effect of the PAM treating agents in reducing the permeability of oil-bearing formations with respect to water, without reducing the permeability to oil. A Nevada sand pack core (length, 5 inches; diameter, 1%,2-l110h) was mounted in a plastic core holder equipped with pressure fittings on its opposite faces so that desired liquids could be forced lengthwise through the core. The core was first placed in a simulated restored state (as it might exist in an oiland water-bearing formation) by saturating it with mineral oil (viscosity 62 cp.) and water containing 2.3% NaCl.

Upon flooding the restored-state core with water, its permeability with respect to water, K was determined to be 940 md. (millidarcies). The core was then resaturated with mineral oil and its permeability with respect to oil, K was determined to be 2,680 md. The core was then Water-flooded to displace 15% of the recoverable, stock tank oil therefrom. At this point a small slug of a 0.35 weight-percent water solution of an 8l0% hydrolyzed polyacrylamide of about 2,000,000 molecular weight was injected into the core. The slug was equivalent to 8.5% of the undisplaced oil volume. The core was then water flooded to completion of oil recovery; K was found to be only 166 md. On resaturation with mineral oil, K was 2,685 md. Thus, the water permeability decreased from 940 md. to 166 md., while the oil permeability remained essentially unchanged.

Example 11 This example compares the effectiveness as treating agents of various polyacrylamides wherein the amide groups have been hydrolyzed in varying degrees.

Four Nevada 135 sand pack cores were placed in simulated restored state and tested for oil and water permeability as in Example I. Each core was then treated with 14 ml. of a 0.05% aqueous solution of the indicated PAM treating agent, and permeabilities were then again determined, with the following results:

tially improved oil recovery and reduced water production continued for a period of at least about three months.

Core

A B C D Initial Permeabilities, md.:

Water 744 777 743 773 Oil 1, 970 2, 510 2, 440 2, 405 PAM Treating Agent:

Percent Hydrolysis of amide groups 0-1 4-5 8-10 25-35 Av. Mol. Wt -5, 000, 000 1, 000, 000 -2, 000, 000 1, 000,000

Posiaflgeaunent Permeabilities, md.:

er 372 Percent of Initial Water Permeability 50 on 1, 760 Percent of Initial Oil Permeability 89 From the foregoing, it is apparent that the polyacrylamides hydrolyzed to the extent of 8-35 are more than twice as effective in reducing water permeability as compared to polyacrylamides hydrolyzed to the extent of only 05% Example III This example demonstrates the useful effects obtainable by treating a producing well in a flooding operation. A 3 /-inch diameter core from the Caprock Queen field in New Mexico was mounted in plastic and three simulated wells were drilled into the core parallel to the axis thereof, and spaced at equidistant points from each other at the apices of an imaginary isometric triangle. Oil and water was injected simultaneously into one of the simulated wells, A, and efiiuent was recovered from the other two wells, designated as producing wells B and C, and water/ oil ratios of the respective efiiuents were determined. Producing well B was then treated by injecting a slug of the 0.35% aqueous PAM treating solution employed in Example 1, equivalent to about 2% of the pore volume of the core. Producing well C was untreated. Oil-Water injection into well A was then resumed, and water/oil ratios from the producing wells B and C were again determined. The results were as follows:

Since gross production rates from wells B and C were approximately the same, it is clear that treatment of well B caused relatively more water to be diverted to well C.

Example IV This example illustrates the beneficial effects of the invention in an actual field test on a producing Well producing 16 API gravity oil from a depth of about 3,100 feet at a reservoir pressure of about 500 psi. and a temperature of 146 F. This well was producing at an average rate of about 900 b./ d. gross and about 40 b./d. net oil (860 b./ d. water), at a liquid level over the pump of about 515 feet.

For the test, production was suspended for one day, and 500 barrels of a 0.5% solution of the PAM treating agent employed in Example 1 dissolved in fresh water was injected into the well, followed by 200 barrels of fresh water. Upon resuming production the following day, water production was only 600 barrels per day, a reduction of 30%. During the succeeding month, net oil production increased from an average of about 40 b./d. to about 150 b./d. Also the fluid level over the pump fell from about 515 feet to about 350 feet. Substan- Substantially similar beneficial results are obtained when other partially hydrolyzed PAM treating agents within the purview of this invention, and when other contemplated modes of application thereof, are employed in lieu of those illustrated in the foregoing examples. It is therefore not intended that the invention should be limited to the details described above, but broadly as defined in the following claims.

I claim:

1. A method for recovering fluid hydrocarbons from a subterranean formation which is penetrated by a well bore, and for reducing the concomitant production of reservoir water therefrom, which comprises: injecting into said formation through said well bore an aqueous treating solution comprising a minor proportion of a water-soluble, partially hydrolyzed polyacrylamide treating agent having a molecular weight in excess of about 200,000, at least about 8% but not more than about 70% of the amide groups thereof having been hydrolyzed to carboxyl groups, then terminating the injection of said treating agent and thereafter placing the treated well on production.

2. A method as defined in claim 1 wherein said fluid hydrocarbons comprise liquid petroleum.

3. A method as defined in claim 1 wherein said fluid hydrocarbons comprise natural gas.

4. A method as defined in claim 1 wherein sufficient of said polyacrylamide treating agent is injected into said formation to provide a concentration thereof in the reservoir waters of between about 0.01% and 0.5 by weight.

5. A method as defined in claim 1 wherein said partially hydrolyzed polyacrylamide has a molecular Weight in excess of about 1,000,000, at least about 8% but not more than about 25% of the amide groups thereof having been hydrolyzed to carboxyl groups.

6. A method as defined in claim 1 wherein said subterranean formation is treated with an extraneous hydrocarbon solvent to dissolve out heavy hydrocarbonaceous materials prior to said injection of aqueous treating solution.

7. A method for beneficiating oil production from an oil well traversing a subterranean petroleumand waterbearing formation, and wherein said oil well is being pumped at a rate such that there is a substantial liquid level over the pump, so as to increase the daily oil production rate and decrease water production, which comprises: interrupting oil production from said well, injecting down said well and into said formation an aqueous solution comprising a minor proportion of a water-soluble, partially hydrolyzed polyacrylamide treating agent having a molecular weight in excess of about 200,000, at least about 8% but not more than about 70% of the amide groups thereof having been hydrolyzed to carboxyl groups, then terminating the injection of said treating agent, and thereafter placing said well back on production at a pumping rate such that there is a substantial reduction in liquid level over said pump, and recovering from said well a liquid effluent of substantially reduced Water/ oil ratio.

8. A process as defined in claim 7 wherein suflicient of said polyacrylamide treating agent is injected into said formation to provide a concentration thereof in the reservoir waters of between about 0.01% and 0.5% by weight.

9. A process as defined in claim 7 wherein sufficient of said aqueous solution containing polyacrylamide treating agent is injected into said formation to provide a volume thereof equivalent to between about 0.2% and 5% of the oil volume in the oil recovery area adjacent to said well.

References Cited by the Examiner UNITED STATES PATENTS 2,827,964 3/1958 Sandiford et al l669 3,039,529 6/ 1962 McKennon l669 3,087,543 4/1963 Arendt 16-6'30 3,121,462 2/1964 Martin et al. l6629 CHARLES OCONNELL, Primary Examiner.

10. A method as defined in claim 7 wherein said par- 15 NOVOSAD, Assistant Ex ine

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2827964 *Jun 11, 1956Mar 25, 1958Union Oil CoSecondary recovery of petroleum
US3039529 *May 19, 1959Jun 19, 1962Dow Chemical CoSecondary recovery of petroleum
US3087543 *Jan 27, 1960Apr 30, 1963Jersey Prod Res CoMethod for improving oil-water ratios of oil and gas wells
US3121462 *Sep 17, 1959Feb 18, 1964Continental Oil CoMethod of formation consolidation
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3372748 *Apr 14, 1966Mar 12, 1968Mobil Oil CorpPolymer redeposition process for waterflood
US3396790 *Jul 11, 1966Aug 13, 1968Union Oil CoSelective plugging of permeable water channels in subterranean formations
US3421584 *Mar 23, 1967Jan 14, 1969Dow Chemical CoGrouting,plugging,and consolidating method
US3455393 *Aug 2, 1967Jul 15, 1969Dow Chemical CoModifying water injection well profiles
US3461965 *Jun 29, 1967Aug 19, 1969Exxon Production Research CoFracturing of earth formations
US3483925 *Feb 6, 1968Dec 16, 1969Calgon C0RpSqueeze treatment of producing oil wells
US3490533 *Feb 28, 1968Jan 20, 1970Halliburton CoMethod of placement of polymer solutions in primary production and secondary recovery wells
US3580337 *Apr 14, 1969May 25, 1971Marathon Oil CoMethod for stabilizing the mobility of polyacrylamide solutions flowing through porous media
US3603397 *May 14, 1969Sep 7, 1971Grace W R & CoIntrinsic mobility control in petroleum recovery
US3724551 *Jan 6, 1972Apr 3, 1973Nalco Chemical CoSecondary recovery of petroleum
US3757863 *Dec 27, 1971Sep 11, 1973Phillips Petroleum CoSecondary recovery methods
US3785437 *Oct 4, 1972Jan 15, 1974Phillips Petroleum CoMethod for controlling formation permeability
US3798838 *Aug 23, 1972Mar 26, 1974Union Oil CoMethod of irrigation and fertilization
US3826311 *Jun 13, 1973Jul 30, 1974Calgon CorpProducing well treatment
US3830302 *Jun 25, 1973Aug 20, 1974Marathon Oil CoMethod for improving oil-water ratios in oil producing wells
US3833061 *Dec 27, 1972Sep 3, 1974Phillips Petroleum CoMethod for selectively reducing brine permeability in a subterranean oil-wet formation
US3858655 *Aug 7, 1973Jan 7, 1975Phillips Petroleum CoTreating a subterranean hydrocarbon-containing formation
US3868999 *Dec 27, 1972Mar 4, 1975Texaco IncMethod for preferentially producing petroleum from reservoirs containing oil and water
US3908764 *Nov 25, 1974Sep 30, 1975Phillips Petroleum CoMethod of treating petroleum-bearing formations for supplemental oil recovery
US3949811 *Apr 19, 1974Apr 13, 1976Phillips Petroleum CompanyMethod for reducing the permeability of subterranean formations to brines
US3952806 *Jun 16, 1975Apr 27, 1976Phillips Petroleum CompanyPolymeric gel; aluminum citrate
US3967681 *Sep 30, 1975Jul 6, 1976Phillips Petroleum CompanyRepair of cement sheath around well casing
US4034809 *Mar 17, 1976Jul 12, 1977Nalco Chemical CompanyAcrylamide-acrylic acid copolymer, subterranean formations
US4039029 *Nov 6, 1975Aug 2, 1977Phillips Petroleum CompanyRetreatment of wells to reduce water production
US4095651 *Sep 24, 1976Jun 20, 1978Institut Francais Du PetroleProcess for selectively plugging areas in the vicinity of oil or gas producing wells in order to reduce water penetration
US4120361 *Sep 11, 1975Oct 17, 1978Phillips Petroleum CompanyInjecting aqueous solution of partially hydrolyzed polyacrylamide and contacting with divalent and trivalent metal cations
US4191249 *Nov 16, 1978Mar 4, 1980Union Oil Company Of CaliforniaOil soluble thickener, water soluble thickener
US4205723 *Oct 19, 1978Jun 3, 1980Texaco Inc.Injection of gas and water excluding agent
US4276935 *Oct 30, 1979Jul 7, 1981Phillips Petroleum CompanyTreatment of subsurface gas-bearing formations to reduce water production therefrom
US4290485 *May 8, 1972Sep 22, 1981The Dow Chemical CompanyReduction of water production from hydrocarbon containing subsurface formations
US4476931 *Sep 17, 1982Oct 16, 1984Hughes Tool CompanyInjecting an amphoteric polymer, solvent, surfactant and carrier; permeability
US4508629 *Apr 8, 1983Apr 2, 1985Halliburton CompanyMethod of viscosifying aqueous fluids and process for recovery of hydrocarbons from subterranean formations
US4524003 *Apr 8, 1983Jun 18, 1985Halliburton CompanyMethod of viscosifying aqueous fluids and process for recovery of hydrocarbons from subterranean formations
US4560003 *Jan 22, 1985Dec 24, 1985Mobil Oil CorporationSolvent stimulation in heavy oil wells producing a large fraction of water
US4579175 *Aug 10, 1984Apr 1, 1986Deutsche Texaco AktiengesellschaftMethod of reducing water production
US4600057 *Oct 23, 1984Jul 15, 1986Halliburton CompanyMethod of reducing the permeability of a subterranean formation
US4709759 *Dec 29, 1986Dec 1, 1987Exxon Research And Engineering CompanyTetrapolymers; acrylic acid salts, nalkyl acrylamides pressure injection
US5529124 *Dec 19, 1994Jun 25, 1996Texaco Inc.Method for retarding water coning
US5939362 *Oct 27, 1997Aug 17, 1999Nalco/Exxon Energy Chemicals, L.P.Enhanced corrosion protection by use of friction reducers in conjuction with corrosion inhibitors
US6913081Feb 6, 2003Jul 5, 2005Baker Hughes IncorporatedWater control treatment requires fewer steps than the sum of each treatment procedure practiced separately. The control of water production simultaneously further reduces the amount of scale formed. water control chemicals and scale inhibitors of
US6978836 *May 23, 2003Dec 27, 2005Halliburton Energy Services, Inc.Methods for controlling water and particulate production
US7013976Jun 25, 2003Mar 21, 2006Halliburton Energy Services, Inc.Compositions and methods for consolidating unconsolidated subterranean formations
US7017665Aug 26, 2003Mar 28, 2006Halliburton Energy Services, Inc.Strengthening near well bore subterranean formations
US7021379Jul 7, 2003Apr 4, 2006Halliburton Energy Services, Inc.Methods and compositions for enhancing consolidation strength of proppant in subterranean fractures
US7028774 *Aug 16, 2005Apr 18, 2006Halliburton Energy Services, Inc.Applying a preflush solution of an aqueous liquid and a water-resistant polymer, surfactant, low viscosity consolidating fluid and afterflush fluid to the subterranean formation
US7032667Sep 10, 2003Apr 25, 2006Halliburtonn Energy Services, Inc.Methods for enhancing the consolidation strength of resin coated particulates
US7059406Aug 26, 2003Jun 13, 2006Halliburton Energy Services, Inc.Production-enhancing completion methods
US7063150Nov 25, 2003Jun 20, 2006Halliburton Energy Services, Inc.Methods for preparing slurries of coated particulates
US7063151Mar 5, 2004Jun 20, 2006Halliburton Energy Services, Inc.Methods of preparing and using coated particulates
US7066258Jul 8, 2003Jun 27, 2006Halliburton Energy Services, Inc.Reduced-density proppants and methods of using reduced-density proppants to enhance their transport in well bores and fractures
US7073581Jun 15, 2004Jul 11, 2006Halliburton Energy Services, Inc.Electroconductive proppant compositions and related methods
US7114560Jun 8, 2004Oct 3, 2006Halliburton Energy Services, Inc.Methods for enhancing treatment fluid placement in a subterranean formation
US7114570Apr 7, 2003Oct 3, 2006Halliburton Energy Services, Inc.Reducing production and preventing migration of loose particulates; applying aqueous liquid and surfactant preflush solution, integrated consolidation fluid and afterflush fluid; noncatalytic
US7150319Sep 24, 2002Dec 19, 2006Clariant Uk Ltd.Method for reducing or completely eliminating water influx in an underground formation, and crosslinkable copolymers for implementing said method
US7156194Aug 26, 2003Jan 2, 2007Halliburton Energy Services, Inc.Methods of drilling and consolidating subterranean formation particulate
US7211547Mar 3, 2004May 1, 2007Halliburton Energy Services, Inc.Controlling the migration of particulates by curing and degrading a mixture of a resin, a hardening agent, a hydrocarbon diluent, a silane coupling agent, a foaming agent, a compressible gas, and a hydrolytically degradable material to form a permeable, hardened resin mass.
US7216711Jun 15, 2004May 15, 2007Halliburton Eenrgy Services, Inc.Methods of coating resin and blending resin-coated proppant
US7237609Oct 29, 2004Jul 3, 2007Halliburton Energy Services, Inc.Methods for producing fluids from acidized and consolidated portions of subterranean formations
US7252146Apr 4, 2006Aug 7, 2007Halliburton Energy Services, Inc.Methods for preparing slurries of coated particulates
US7255169Feb 2, 2005Aug 14, 2007Halliburton Energy Services, Inc.Methods of creating high porosity propped fractures
US7261156Mar 4, 2005Aug 28, 2007Halliburton Energy Services, Inc.Slurrying particulates including an adhesive coated with a subterranean treatment partitioning agent in a treatment fluid placing the slurry into a portion of a subterranean formation
US7264051Mar 4, 2005Sep 4, 2007Halliburton Energy Services, Inc.Providing partitioned, coated particulates that comprise particulates, an adhesive, and a partitioning agent, and wherein adhesive comprises an aqueous tackifying agent or a silyl modified polyamide; slurrying particulates in a treatment fluid, placing slurry into subterranean formation
US7264052May 23, 2005Sep 4, 2007Halliburton Energy Services, Inc.Methods and compositions for consolidating proppant in fractures
US7267171Oct 25, 2004Sep 11, 2007Halliburton Energy Services, Inc.Methods and compositions for stabilizing the surface of a subterranean formation
US7273099Dec 3, 2004Sep 25, 2007Halliburton Energy Services, Inc.Methods of stimulating a subterranean formation comprising multiple production intervals
US7281580Sep 9, 2004Oct 16, 2007Halliburton Energy Services, Inc.Fracturing a portion of a subterranean formation to form a propped fracture; slurrying fracturing fluid and high density plastic particles coated with adhesive
US7281581Dec 1, 2004Oct 16, 2007Halliburton Energy Services, Inc.Methods of hydraulic fracturing and of propping fractures in subterranean formations
US7299875Jun 8, 2004Nov 27, 2007Halliburton Energy Services, Inc.Methods for controlling particulate migration
US7318473Mar 7, 2005Jan 15, 2008Halliburton Energy Services, Inc.Methods relating to maintaining the structural integrity of deviated well bores
US7318474Jul 11, 2005Jan 15, 2008Halliburton Energy Services, Inc.Methods and compositions for controlling formation fines and reducing proppant flow-back
US7334635Jan 14, 2005Feb 26, 2008Halliburton Energy Services, Inc.Methods for fracturing subterranean wells
US7334636Feb 8, 2005Feb 26, 2008Halliburton Energy Services, Inc.Methods of creating high-porosity propped fractures using reticulated foam
US7343973Feb 11, 2005Mar 18, 2008Halliburton Energy Services, Inc.Methods of stabilizing surfaces of subterranean formations
US7345011Oct 14, 2003Mar 18, 2008Halliburton Energy Services, Inc.Via injecting consolidating furan-based resin
US7350571Mar 7, 2006Apr 1, 2008Halliburton Energy Services, Inc.Methods of preparing and using coated particulates
US7398825Nov 21, 2005Jul 15, 2008Halliburton Energy Services, Inc.Methods of controlling sand and water production in subterranean zones
US7407010Mar 16, 2006Aug 5, 2008Halliburton Energy Services, Inc.Methods of coating particulates
US7413010Feb 15, 2006Aug 19, 2008Halliburton Energy Services, Inc.Remediation of subterranean formations using vibrational waves and consolidating agents
US7448451Mar 29, 2005Nov 11, 2008Halliburton Energy Services, Inc.Pre-flushing with hydrocarbon, then placing low-viscosity adhesive substance diluted with aqueous dissolvable solvent into portion of subterranean formation; tackifier resins; phenol-formaldehyde resins; well bores
US7500521Jul 6, 2006Mar 10, 2009Halliburton Energy Services, Inc.Methods of enhancing uniform placement of a resin in a subterranean formation
US7541318May 26, 2004Jun 2, 2009Halliburton Energy Services, Inc.Placing discrete amounts of resin mixture into a well bore comprising a treatment fluid and allowing the resin mixture to substantially cure and form proppant particles while inside the treatment fluid
US7571767Oct 4, 2007Aug 11, 2009Halliburton Energy Services, Inc.High porosity fractures and methods of creating high porosity fractures
US7665517Feb 15, 2006Feb 23, 2010Halliburton Energy Services, Inc.Methods of cleaning sand control screens and gravel packs
US7673686Feb 10, 2006Mar 9, 2010Halliburton Energy Services, Inc.Method of stabilizing unconsolidated formation for sand control
US7712531Jul 26, 2007May 11, 2010Halliburton Energy Services, Inc.Methods for controlling particulate migration
US7757768Oct 8, 2004Jul 20, 2010Halliburton Energy Services, Inc.Determining the breakdown pressure of the subterranean formation;calculating a maximum allowable fluid viscosity for a preflushadjusting the viscosity to a viscosity less than or equal to the maximum allowable to prevent fracturing; injecting into the oil or gas well
US7762329Jan 27, 2009Jul 27, 2010Halliburton Energy Services, Inc.introducing into well bore hydrophobic well bore servicing composition comprising liquid hardenable resin, hardening agent, and weighting material selected to impart desired density to well bore servicing composition, allowing liquid hardenable resin to at least partially harden to form well bore plug
US7819192Feb 10, 2006Oct 26, 2010Halliburton Energy Services, Inc.introducing into subterranean formation treatment fluid consolidating agent emulsion comprising aqueous fluid, surfactant, and non-aqueous tackifying agent; composition comprises aqueous external phase and oil internal phase, and does not include tertiary amine surfactant; minimizes particulate migration
US7883740Dec 12, 2004Feb 8, 2011Halliburton Energy Services, Inc.Low-quality particulates and methods of making and using improved low-quality particulates
US7926591Jan 12, 2009Apr 19, 2011Halliburton Energy Services, Inc.Aqueous-based emulsified consolidating agents suitable for use in drill-in applications
US7934557Feb 15, 2007May 3, 2011Halliburton Energy Services, Inc.Methods of completing wells for controlling water and particulate production
US7963330Dec 21, 2009Jun 21, 2011Halliburton Energy Services, Inc.Resin compositions and methods of using resin compositions to control proppant flow-back
US8017561Apr 3, 2007Sep 13, 2011Halliburton Energy Services, Inc.Resin compositions and methods of using such resin compositions in subterranean applications
US8354279Feb 12, 2004Jan 15, 2013Halliburton Energy Services, Inc.For determining the source of treatment fluids being produced from a production formation having multiple zones
US8443885Aug 30, 2007May 21, 2013Halliburton Energy Services, Inc.Consolidating agent emulsions and associated methods
US8613320Feb 15, 2008Dec 24, 2013Halliburton Energy Services, Inc.Compositions and applications of resins in treating subterranean formations
US8689872Jul 24, 2007Apr 8, 2014Halliburton Energy Services, Inc.Methods and compositions for controlling formation fines and reducing proppant flow-back
USB251345 *May 8, 1972Jan 28, 1975 Title not available
USRE30230 *Jun 6, 1977Mar 18, 1980Brinadd CompanyClosed circuit method of circulating a substantially solid free drilling fluid
EP1630181A1Jul 12, 2005Mar 1, 2006Clariant GmbHThermostable, watersoluble at high temperatures curable Polymer
Classifications
U.S. Classification166/295, 166/305.1
International ClassificationC09K8/88
Cooperative ClassificationC09K8/882
European ClassificationC09K8/88A