CA1145667A - Treatment of subsuraface gas-bearing formations to reduce water production therefrom - Google Patents
Treatment of subsuraface gas-bearing formations to reduce water production therefromInfo
- Publication number
- CA1145667A CA1145667A CA000361673A CA361673A CA1145667A CA 1145667 A CA1145667 A CA 1145667A CA 000361673 A CA000361673 A CA 000361673A CA 361673 A CA361673 A CA 361673A CA 1145667 A CA1145667 A CA 1145667A
- Authority
- CA
- Canada
- Prior art keywords
- hydrocarbon
- water
- polymeric latex
- gas
- latex concentrate
- 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.)
- Expired
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Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/82—Oil-based compositions
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/502—Oil-based compositions
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
Abstract
TREATMENT OF SUBSURFACE GAS-BEARING FORMATIONS TO REDUCE WATER PRODUCTION THEREFROM Abstract of the Disclosure Excessive water production from a producing gas well is substantially reduced by the injection of a hydrocarbon-diluted water-in-oil emulsion comprising a viscosifying polymer such as polyacrylamide, the injected emulsified polymer swelling on contact with connate water in the subsurface gas producing formation to restrict transfer of water therethrough toward the producing gas well.
Description
~ ~5~ 27963 TREATMENT OF SUBSURFACE GAS-BEARING FORMATIONS
TO REDUCE WATER PRODUCTION THEREFROM
This invention relates generally to improvements in the production of gas from subsurface gas-bearing formations. In one aspect the invention relates to methods of increasing the gas-to-water ratio of fluids produced from a gas well penetrating a gas-bearing formation.
As is well known by those skilled in the art, the production of large amounts of water from oil wells and gas wells constitutes a major item of expense in the recovery of hydrocarbons therefrom. This problem is of particular significance in the production of gas from gas wells where water can load the production tubing to the extent that the gas well dies and no longer produces gas. Under such conditions it is often necessary to periodically pump the water out of the production tubing in order to place the woll back in condition to 1ow gas.
It would, thereforo, be advnntngoous to ~reat the subsurface formations penetruted by the well bore of a gns well and forming the subsurface gas-producLng intorval so as to provont or substantiAlly reduce or rostrict the flow of wnter from the formatioll into the well bore while malntaining substantially unrestricted gas flow into the well bore.
In accordance with the present invention, we have discovered that water production in producing gas wells can be significantly reduced or restricted without significant adverse effect on gas production by injecting a hydrocarbon-diluted polymeric concentrate containing a viscosifying polymer down the well bore of a producing gas well and into the gas-producing formation penetrated by the well bore, and allowing the ~ ~5~i~'i' viscosifying polymer to contact cormate water in the for~ation so as to swell the polymer in the formation and thereby restrict the flow of wflter through the formation toward the producing gas well.
It is, therefore, an object of the invention to provide a method of enhancing the production of gas from gas production wells.
Another object of the invention is to provide a method of reducing the cost of producing gas from producing gas wells.
Yet another object of the invention is to provide a method of treatin~ previously shut-in gas wells to place them back into economical gas production.
Other objects, aspects and advantages of the present invention will become readily apparent to those skilled in the art from a reading of the following detailed description and claims.
In accordance with the present invention, a suitable water-in-oil emulsion comprising a suitable viscosifying polymer, such as for example polyacrylamide, and diluted with a suitable hydrocarbon, such as for example diesel oil, is injected into a gas producing well to diminish water production and thereby greatly increase the effluent gas-tc-water ratio. The treatment method of the present invention decreases water permeability in the formation penetrated by the gas producing well significantly whereas the gas permeability of the formation remains essentially unchanged. It is presumed that the treating agent in the form of a suitable water-in-oil emulsion tends to remain in the formation subsequent to polymer hydration upon contnct with connate water in the formation, wlth the viscosifying polymer bellnving as a selective p]ugging a8ent to restrict the flow oL wn~er Ln the formation without significantly restrlctillg thO flow of gQS throllgh the formation.
The novel process of the present invontioll is characteriY.ed by optionally in.jecting n preflustl of alcohol, arl inor~ gas or a suLtable hydrocarbon Lnto a gas producLng well to ramove water from the well bore aren. A suLtable water-in-oil emulsioll, sucll as for example Q polymeric latex concentrate, is diluted with a sult~lblo hydrocarbon such as diesel oil. This hydrocarbon-diluted polymeric concentrate, optionally containing a suitable emulsion breaker, is then introduced into the gas producing well. This essentially water-free slug or charge of hydrocarbon-diluted pclymeric concentrate is then flushsd into the ~as .
producing formation with a suitab]e drive fluid such as nitrogen or other suitable drive gas or diesel oil or other suitable liquid hydrocarbon drive fluid. The gas producing well is then allowed to produce back, giving a portion of the previously injected material from the gas producing zone together with minor amounts of water and larger quantities of gas resulting in a greatly increased gas-to-water ratio of the produced effluent.
Hydrocarbon-diluted water-in-oil emulsions suitable for injection into gas producing wells in the performance of the method of the present invention comprise suitable amounts of water, a suitable viscosifying polymer, a suitable hydrocarbon diluent, and, optionally, a suitable water-in-oil emulsifying agent. While any suitable amount of water can be present in the hydrocarbon-diluted water-in-oil emulsion whlch will maintain the stability of the emulsion during injection, water is generally present in the range from about 0.01 to about 5.0 weight percent and preferably from about 0.01 to about 3.0 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
The hydrocarbon-diluted water-in-oil emulsion further comprises a quantity of a suitable viscosifying polymer of any suitable amount, however the amount of viscosifying polymer generally ranges from about 1.0 to about 20 weight percent and preferably from about 5 to about 15 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
The hydrocarbon-diluted wator-irl-o.il omulsions suitnble for use in the present invention furthor compr.ise a suitnble hydrocnrbon diluent .i.ll a suitabl~ amount. Whi.le nny amollnt of suLtable hydrocarbon diluent c~m be omployed which will mnintain tlle viscosifying polymer in a water-in-oi]. ~muls:Loll prior to colltact wlth connato water in the gas producing formation, th~ hydrocnrbon dilucnt is gonerally present in an amount in the rnnge from ubout 75 to about 99 woight percetlt and preferably in the range from about 85 to about 95 wci.gllt percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
A suitable hydrocarbon-diluted water-in-oil emulsion further comprises, on an optional basis, a suitable water-in-oil emulsifying agent in a quantity sufficient to facilitate the formation of the water-in-oil emulsion. While any suitable quantity of water-in-oil emulsifying a&ent can be employed, a quantity in the range from about 0.001 to about 30 weight percen-t and preferably in the range from about 0.1 to about 10 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion is deemed suitable.
Suitable water-in-oil emulsions comprising polymeric viscosifiers, which emulsions are sometimes referred to as polymeric latex concentrates, can be prepared by a number of methods well known in the art. For example, such emulsions can be prepared by using high speed agitation or ultrasonic techniques. In most instances, however, it is desirable that the emulsion be a stable emulsion and to achieve this end it is often necessary to employ an oil-soluble emulsifying agent. The amount of emulsifying agent necessary to provide an emulsion will have to be determined by routine experimentation. As a general rule it can be said that the amount of oil-soluble emulsifier can range from about 0.1 to about 30 percent by weight based on the weight of the oil. To produce stable emulsions, the amount of emulsifier will normally be within the range from about 12 to about 20 percent by weight of the oil.
Several polymeric latex concentrates suitable for use in the process of the present invention can be purchased as items of commerce and dlluted with a suitable hydrocarbon solvent prior to use. One such suitable polymeric latex concentrate for use in the process of the present inventi.on is designated as ALCOFLOOD ~ llOOL, available from ; Allied Colloid Limited, which polymeric latex concentrate comprises 50 weight percent polyacrylnmide in u water-in-oil emulsion.
Water-in-otl emulsions, or po]ymoric latex concontrates, suitable for di.l.ution with a suitablc hydrocarbon d.Lluent or use in the process o the present inventlon generAlly comprise wntcr, vi.scosifying polymer~ hydrocarbon diluent nnd nn optionAl water-in-oil cmulsifying agellt. Whilo any suitablo qunntity of wntor can be cmployed wh.ich will maintaill a stable water-in-oil emulsion, wnter is generally present in the range from about l to about 25 woight percent ~nd preferably in the range from about 1 to about 15 weight percent based on the weight of the . water-in-oil emulsion. Viscosifying polymer can also be employed in any suitable quantity which will provide a stable water-in-oil emulsion, but generally viscosifying polymer is provided in an amount in the range from about 20 weigùt percent to aùout 50 weight percent and pre~erably in the ., .
s range from about 25 weight percent to about 35 weight percent based on the weight of the water-in-oil emulsion. Any suitable amount of hydrocarboll can be employed in -the water-in-oil emulsion which will provide the desired stable emulsion, but generally hydrocarbon is provided in the range from about S weight percent to about 35 weight percent and preferably in the range from about 15 weight percent to about 25 weight percent basecl on the weight of the water-in-oil emulsion. The optional water-in-oil emulsifying agent is provided in a quantity which will provide a stable water-in-oil emulsion, but generally such emulsifying agent is provided in an amount in the range from about 0.1 to about 30 weight percent and preferably in the range from about 0.5 to about 5 weight percent based on the weight of the water-in-oil emulsion.
Viscosifying polymers suitable for use in the polymeric latex concentrates employed in the process of the present invention are well known in the art and have been previously described in numerous publications and patents. The polymers most commonly employed in many industrial applications are acrylamide polymers which include polyacrylamide and its water-soluble copolymeric derivatives such as, for instance, acrylamide-acrylic acid, and acrylamide-acrylic acid salt copolymers which contain from about 95 to about 5 percent by weight of acry]amide. A]so useful are copolymers of acrylamide with other vinyl monomers such as maleic anhydride, acrylonitrile, styrene and the like.
Polymers and copolymers derived from acrylamide are preferred for employment in the process of the pre.sent invention.
Hydrocarbon liquids suitable for dilution of the water-in-oil emuls:ions or polymeric la~ex concontrates include aliphatic and aromatic compouncls sllch as toluerle, xylene, banæene, crude oil, diesel fuel, kerosene, nnphthAs~ condensates nAturally produced with ~as from a ~AS
production well arld the like. It is contemplated and withirl the scope of the present lnventiorl tha- a suitable polymeric latex concentrate or water-in-oil emulsion can be used without dilution, that is, the polymeric latex concentrate or water-in-oil emulsion can be pumped directly into the gas producing formation penetrated by the gas producing well without the addition of any diluent if so desired.
The following examples are provided to illustrate the operability and the application of the process of the present invention.
XAMPLE I
The following provides a calculated hypothetical example describing the process of the present invention when performed on a wfltered out gas-producing well. A newly completed gas-producing well yields 2,500,000 standard cubic feet of gas per day and 6 barrels of condensate per day at a flowing wellhead pressure of 250 psi. After 5 years of continuous production, gas production is down to 400,000 standard cubic feet per day and maximum wellhead pressure is reduced to 40 psi. Significant water production is also in evidence as the production tubing is periodically filled with water resulting in complete gas production stoppage. Thus, from time to time it becomes necessary to install a beam pumping unit, controlled by an automatic timer, to periodically pump water out of the production tubing so that the well can continue to flow gas.
At this point it becomes advantageous to apply the process of the present invention. Initially the water in the production tubing is pumped of with a beam pumping unit, the lead line valve is closed, and the production tubing is pressured to 200 psi surface pressure. A
nitrogen flush is then used to dry the annulus between the production tubing and the cased well bore followed by the injection of 500 gallons of methanol to remove the remaining water before finally drying the annulus flgain with nitrogen. After injecting 100 gallons of diesel oil into the well, a drum of polymeric latex concentrate diluted with 400 gallons of dicsel oil is injected into the well nnd overflushed with an addition~l 100 ~flllons of diosol oil. The proviously mentioned annulus is then flushed dry with nitrogen with su~icient prossure to force tho proviously in.joctod liqulds i.nto tho gns-producing formation to a distnnco of npproximntely 10 feot outsido tho woll bore aren. The gas production woll is thon returned to production lmmedia~oly.
~Iydrntion of tho in~ected viscoslying polymor by the connnte wnter in thc formation penotra~od by ~ho woll bore decrcnses the formation pormeability to wntor whereas formntion pcrmeability to gas remains essentially unchanged. As n result, the hydrocarbon liquid injected along with the viscosifying polymer is produced along with gas through the production tubing with only relatively small amounts of water to thereby achieve and increase gas-to-water ratio in the well effluent.
Retreatment of the producing gas well in accordance with the process of the present invention can be carried out repeatedly as desired to maintain a favorable gas-to-water ratio in the producing well effluent. The process of the present invention can be readily performed through the existing production tubing and associated equipment in the producing well bore without requiring removal and resetting of production tubing, packers and the like.
EXAMPLE II
Two identical tubes of l-inch (2.54 cm.) diameter and 12-inch (30.48 cm.) length were used to contain sand packs of Mill Creek sand to demonstrate the effectiveness of the process of the present invention in decreasing water permeabi.lity to a much greater degree than any decrease in gas permeability in a gas producing formation. Each of the tubes was packed with Mill Creek sand and equipped with fittings such that each of the vertlcally positioned tubes was connected at its upper end into a common effluent line. A common regulated pressurized gas source was attached to the lower end of one tube which was designated as the gas system sand pack via a rotometer. This same regulated pressurized gas source was also connected to the top of a water reservoir vessel which vessel was connected at the bottom thereof to the lower end of the second tube, which second tube was designated as the water system sand pack, in order to inje.ct water under pressure through the designated water system sand pack. Initially, the gas and water were flowed freely through the respective sand pack tubes exiting from the uppor ends thereof through the common effluent lino. Tho lnitial pormenbilities of the two sand packs, respoctively, to gas and wator wt~rt.~ dctormi.nod to be 6.76 and 6.92 darcies. A small slug oE mothanol was tho1l pumpocl through the effluent line and downwflrdly throug11 thc snnd pncks fo110wcd by fl hydrOCarbOrl-d:i.luLt3d pol.ymeric latox conccntrate in the form of ~ so111tLon mixture 30 consist:Lng of '~0 grams of No. 2 diosel oi.l, ~.S grams of A1.(,0FLOOD 11.00L
(50 wei~ht pcrcent polyncry1amide suspor1dot1 in oil and available from All:ied Collol.d Limited), and l.S gramx of Activator 478 (a detergent emulsion breaker available from American Cyanimid Co.). The injection of the last-mentioned solution mixture into the upper end of each tube and through each sand pack resulted in the permeability changes recorded in Table I.
TABLE I
Relative Permeabilities to Water And Gas in Sand Pack Time Elapsed After Water System Gas System Injecting Hydrocarbon- Sand Pack Sand Pack Diluted Polymeric Permeability, Permeability, % of Initial Gas ~atex Concentratein darcies in darcies Permeability _.
Initial 6.92 6.76 10 Minutes Plugged 0.81 12 1 Hour Plugged 1.142 17
TO REDUCE WATER PRODUCTION THEREFROM
This invention relates generally to improvements in the production of gas from subsurface gas-bearing formations. In one aspect the invention relates to methods of increasing the gas-to-water ratio of fluids produced from a gas well penetrating a gas-bearing formation.
As is well known by those skilled in the art, the production of large amounts of water from oil wells and gas wells constitutes a major item of expense in the recovery of hydrocarbons therefrom. This problem is of particular significance in the production of gas from gas wells where water can load the production tubing to the extent that the gas well dies and no longer produces gas. Under such conditions it is often necessary to periodically pump the water out of the production tubing in order to place the woll back in condition to 1ow gas.
It would, thereforo, be advnntngoous to ~reat the subsurface formations penetruted by the well bore of a gns well and forming the subsurface gas-producLng intorval so as to provont or substantiAlly reduce or rostrict the flow of wnter from the formatioll into the well bore while malntaining substantially unrestricted gas flow into the well bore.
In accordance with the present invention, we have discovered that water production in producing gas wells can be significantly reduced or restricted without significant adverse effect on gas production by injecting a hydrocarbon-diluted polymeric concentrate containing a viscosifying polymer down the well bore of a producing gas well and into the gas-producing formation penetrated by the well bore, and allowing the ~ ~5~i~'i' viscosifying polymer to contact cormate water in the for~ation so as to swell the polymer in the formation and thereby restrict the flow of wflter through the formation toward the producing gas well.
It is, therefore, an object of the invention to provide a method of enhancing the production of gas from gas production wells.
Another object of the invention is to provide a method of reducing the cost of producing gas from producing gas wells.
Yet another object of the invention is to provide a method of treatin~ previously shut-in gas wells to place them back into economical gas production.
Other objects, aspects and advantages of the present invention will become readily apparent to those skilled in the art from a reading of the following detailed description and claims.
In accordance with the present invention, a suitable water-in-oil emulsion comprising a suitable viscosifying polymer, such as for example polyacrylamide, and diluted with a suitable hydrocarbon, such as for example diesel oil, is injected into a gas producing well to diminish water production and thereby greatly increase the effluent gas-tc-water ratio. The treatment method of the present invention decreases water permeability in the formation penetrated by the gas producing well significantly whereas the gas permeability of the formation remains essentially unchanged. It is presumed that the treating agent in the form of a suitable water-in-oil emulsion tends to remain in the formation subsequent to polymer hydration upon contnct with connate water in the formation, wlth the viscosifying polymer bellnving as a selective p]ugging a8ent to restrict the flow oL wn~er Ln the formation without significantly restrlctillg thO flow of gQS throllgh the formation.
The novel process of the present invontioll is characteriY.ed by optionally in.jecting n preflustl of alcohol, arl inor~ gas or a suLtable hydrocarbon Lnto a gas producLng well to ramove water from the well bore aren. A suLtable water-in-oil emulsioll, sucll as for example Q polymeric latex concentrate, is diluted with a sult~lblo hydrocarbon such as diesel oil. This hydrocarbon-diluted polymeric concentrate, optionally containing a suitable emulsion breaker, is then introduced into the gas producing well. This essentially water-free slug or charge of hydrocarbon-diluted pclymeric concentrate is then flushsd into the ~as .
producing formation with a suitab]e drive fluid such as nitrogen or other suitable drive gas or diesel oil or other suitable liquid hydrocarbon drive fluid. The gas producing well is then allowed to produce back, giving a portion of the previously injected material from the gas producing zone together with minor amounts of water and larger quantities of gas resulting in a greatly increased gas-to-water ratio of the produced effluent.
Hydrocarbon-diluted water-in-oil emulsions suitable for injection into gas producing wells in the performance of the method of the present invention comprise suitable amounts of water, a suitable viscosifying polymer, a suitable hydrocarbon diluent, and, optionally, a suitable water-in-oil emulsifying agent. While any suitable amount of water can be present in the hydrocarbon-diluted water-in-oil emulsion whlch will maintain the stability of the emulsion during injection, water is generally present in the range from about 0.01 to about 5.0 weight percent and preferably from about 0.01 to about 3.0 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
The hydrocarbon-diluted water-in-oil emulsion further comprises a quantity of a suitable viscosifying polymer of any suitable amount, however the amount of viscosifying polymer generally ranges from about 1.0 to about 20 weight percent and preferably from about 5 to about 15 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
The hydrocarbon-diluted wator-irl-o.il omulsions suitnble for use in the present invention furthor compr.ise a suitnble hydrocnrbon diluent .i.ll a suitabl~ amount. Whi.le nny amollnt of suLtable hydrocarbon diluent c~m be omployed which will mnintain tlle viscosifying polymer in a water-in-oi]. ~muls:Loll prior to colltact wlth connato water in the gas producing formation, th~ hydrocnrbon dilucnt is gonerally present in an amount in the rnnge from ubout 75 to about 99 woight percetlt and preferably in the range from about 85 to about 95 wci.gllt percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion.
A suitable hydrocarbon-diluted water-in-oil emulsion further comprises, on an optional basis, a suitable water-in-oil emulsifying agent in a quantity sufficient to facilitate the formation of the water-in-oil emulsion. While any suitable quantity of water-in-oil emulsifying a&ent can be employed, a quantity in the range from about 0.001 to about 30 weight percen-t and preferably in the range from about 0.1 to about 10 weight percent based on the weight of the hydrocarbon-diluted water-in-oil emulsion is deemed suitable.
Suitable water-in-oil emulsions comprising polymeric viscosifiers, which emulsions are sometimes referred to as polymeric latex concentrates, can be prepared by a number of methods well known in the art. For example, such emulsions can be prepared by using high speed agitation or ultrasonic techniques. In most instances, however, it is desirable that the emulsion be a stable emulsion and to achieve this end it is often necessary to employ an oil-soluble emulsifying agent. The amount of emulsifying agent necessary to provide an emulsion will have to be determined by routine experimentation. As a general rule it can be said that the amount of oil-soluble emulsifier can range from about 0.1 to about 30 percent by weight based on the weight of the oil. To produce stable emulsions, the amount of emulsifier will normally be within the range from about 12 to about 20 percent by weight of the oil.
Several polymeric latex concentrates suitable for use in the process of the present invention can be purchased as items of commerce and dlluted with a suitable hydrocarbon solvent prior to use. One such suitable polymeric latex concentrate for use in the process of the present inventi.on is designated as ALCOFLOOD ~ llOOL, available from ; Allied Colloid Limited, which polymeric latex concentrate comprises 50 weight percent polyacrylnmide in u water-in-oil emulsion.
Water-in-otl emulsions, or po]ymoric latex concontrates, suitable for di.l.ution with a suitablc hydrocarbon d.Lluent or use in the process o the present inventlon generAlly comprise wntcr, vi.scosifying polymer~ hydrocarbon diluent nnd nn optionAl water-in-oil cmulsifying agellt. Whilo any suitablo qunntity of wntor can be cmployed wh.ich will maintaill a stable water-in-oil emulsion, wnter is generally present in the range from about l to about 25 woight percent ~nd preferably in the range from about 1 to about 15 weight percent based on the weight of the . water-in-oil emulsion. Viscosifying polymer can also be employed in any suitable quantity which will provide a stable water-in-oil emulsion, but generally viscosifying polymer is provided in an amount in the range from about 20 weigùt percent to aùout 50 weight percent and pre~erably in the ., .
s range from about 25 weight percent to about 35 weight percent based on the weight of the water-in-oil emulsion. Any suitable amount of hydrocarboll can be employed in -the water-in-oil emulsion which will provide the desired stable emulsion, but generally hydrocarbon is provided in the range from about S weight percent to about 35 weight percent and preferably in the range from about 15 weight percent to about 25 weight percent basecl on the weight of the water-in-oil emulsion. The optional water-in-oil emulsifying agent is provided in a quantity which will provide a stable water-in-oil emulsion, but generally such emulsifying agent is provided in an amount in the range from about 0.1 to about 30 weight percent and preferably in the range from about 0.5 to about 5 weight percent based on the weight of the water-in-oil emulsion.
Viscosifying polymers suitable for use in the polymeric latex concentrates employed in the process of the present invention are well known in the art and have been previously described in numerous publications and patents. The polymers most commonly employed in many industrial applications are acrylamide polymers which include polyacrylamide and its water-soluble copolymeric derivatives such as, for instance, acrylamide-acrylic acid, and acrylamide-acrylic acid salt copolymers which contain from about 95 to about 5 percent by weight of acry]amide. A]so useful are copolymers of acrylamide with other vinyl monomers such as maleic anhydride, acrylonitrile, styrene and the like.
Polymers and copolymers derived from acrylamide are preferred for employment in the process of the pre.sent invention.
Hydrocarbon liquids suitable for dilution of the water-in-oil emuls:ions or polymeric la~ex concontrates include aliphatic and aromatic compouncls sllch as toluerle, xylene, banæene, crude oil, diesel fuel, kerosene, nnphthAs~ condensates nAturally produced with ~as from a ~AS
production well arld the like. It is contemplated and withirl the scope of the present lnventiorl tha- a suitable polymeric latex concentrate or water-in-oil emulsion can be used without dilution, that is, the polymeric latex concentrate or water-in-oil emulsion can be pumped directly into the gas producing formation penetrated by the gas producing well without the addition of any diluent if so desired.
The following examples are provided to illustrate the operability and the application of the process of the present invention.
XAMPLE I
The following provides a calculated hypothetical example describing the process of the present invention when performed on a wfltered out gas-producing well. A newly completed gas-producing well yields 2,500,000 standard cubic feet of gas per day and 6 barrels of condensate per day at a flowing wellhead pressure of 250 psi. After 5 years of continuous production, gas production is down to 400,000 standard cubic feet per day and maximum wellhead pressure is reduced to 40 psi. Significant water production is also in evidence as the production tubing is periodically filled with water resulting in complete gas production stoppage. Thus, from time to time it becomes necessary to install a beam pumping unit, controlled by an automatic timer, to periodically pump water out of the production tubing so that the well can continue to flow gas.
At this point it becomes advantageous to apply the process of the present invention. Initially the water in the production tubing is pumped of with a beam pumping unit, the lead line valve is closed, and the production tubing is pressured to 200 psi surface pressure. A
nitrogen flush is then used to dry the annulus between the production tubing and the cased well bore followed by the injection of 500 gallons of methanol to remove the remaining water before finally drying the annulus flgain with nitrogen. After injecting 100 gallons of diesel oil into the well, a drum of polymeric latex concentrate diluted with 400 gallons of dicsel oil is injected into the well nnd overflushed with an addition~l 100 ~flllons of diosol oil. The proviously mentioned annulus is then flushed dry with nitrogen with su~icient prossure to force tho proviously in.joctod liqulds i.nto tho gns-producing formation to a distnnco of npproximntely 10 feot outsido tho woll bore aren. The gas production woll is thon returned to production lmmedia~oly.
~Iydrntion of tho in~ected viscoslying polymor by the connnte wnter in thc formation penotra~od by ~ho woll bore decrcnses the formation pormeability to wntor whereas formntion pcrmeability to gas remains essentially unchanged. As n result, the hydrocarbon liquid injected along with the viscosifying polymer is produced along with gas through the production tubing with only relatively small amounts of water to thereby achieve and increase gas-to-water ratio in the well effluent.
Retreatment of the producing gas well in accordance with the process of the present invention can be carried out repeatedly as desired to maintain a favorable gas-to-water ratio in the producing well effluent. The process of the present invention can be readily performed through the existing production tubing and associated equipment in the producing well bore without requiring removal and resetting of production tubing, packers and the like.
EXAMPLE II
Two identical tubes of l-inch (2.54 cm.) diameter and 12-inch (30.48 cm.) length were used to contain sand packs of Mill Creek sand to demonstrate the effectiveness of the process of the present invention in decreasing water permeabi.lity to a much greater degree than any decrease in gas permeability in a gas producing formation. Each of the tubes was packed with Mill Creek sand and equipped with fittings such that each of the vertlcally positioned tubes was connected at its upper end into a common effluent line. A common regulated pressurized gas source was attached to the lower end of one tube which was designated as the gas system sand pack via a rotometer. This same regulated pressurized gas source was also connected to the top of a water reservoir vessel which vessel was connected at the bottom thereof to the lower end of the second tube, which second tube was designated as the water system sand pack, in order to inje.ct water under pressure through the designated water system sand pack. Initially, the gas and water were flowed freely through the respective sand pack tubes exiting from the uppor ends thereof through the common effluent lino. Tho lnitial pormenbilities of the two sand packs, respoctively, to gas and wator wt~rt.~ dctormi.nod to be 6.76 and 6.92 darcies. A small slug oE mothanol was tho1l pumpocl through the effluent line and downwflrdly throug11 thc snnd pncks fo110wcd by fl hydrOCarbOrl-d:i.luLt3d pol.ymeric latox conccntrate in the form of ~ so111tLon mixture 30 consist:Lng of '~0 grams of No. 2 diosel oi.l, ~.S grams of A1.(,0FLOOD 11.00L
(50 wei~ht pcrcent polyncry1amide suspor1dot1 in oil and available from All:ied Collol.d Limited), and l.S gramx of Activator 478 (a detergent emulsion breaker available from American Cyanimid Co.). The injection of the last-mentioned solution mixture into the upper end of each tube and through each sand pack resulted in the permeability changes recorded in Table I.
TABLE I
Relative Permeabilities to Water And Gas in Sand Pack Time Elapsed After Water System Gas System Injecting Hydrocarbon- Sand Pack Sand Pack Diluted Polymeric Permeability, Permeability, % of Initial Gas ~atex Concentratein darcies in darcies Permeability _.
Initial 6.92 6.76 10 Minutes Plugged 0.81 12 1 Hour Plugged 1.142 17
2 Hours Plugged 3.08 4~
3 Hours Plugged 3.99 59
4 Hours Plugged 4.36 65 As can be seen from the data in Table I, the water system sand pack became completely plugged within 10 minutes after injection of the hydrocarbon-diluted polymeric latex concentrate and subsequent opening of the comtnon effluent line to simulate the return of a gas-bearing formation, represented by the sand packs, to production. The permeability of the gas system sand pack to gas decreased initially, but after 4 hours the gas permeability had increased to about 4.36 darcies, about 65 percent of the initial gas permeability, and the water system sand pack remained plugged. These results provide the surprising indication that injection of a hydrocarbon-diluted polymeric latex concentrate into a gas-bearing formation penetrated by a gas-producing well improves the gas-to-water ratio of the produced effluent by greatly dimini.shing the permeability of the formation to water while producing a relatlvely insigni.ficant reduction in gas permenbilLty.
EXAMPI.E III
Two identi.cal ~ubes of l-inch (2.54 cm.) dinmeter and 12-:lnch t30.48 cm.) length wero used to contain sfllld packs of Mill ,reek sand to further demorlstrate the effectiveness of tho process of the present inventiorl in decreasing water pormeabllity to a much grenter degree than any decrease in gas p~rmeability in a gns produclng formation. This run was carried out in essentially the same manner as described for Example II with the exception that the gas system sand pack was conditioned to produce residual hydrocarbon saturation therein prior to carrying out the run. The designated gas system sand pack was preliminarily conditioned by contacting the gas system sand pack with Soltrol 170 (a light liquid oil available from Phillips Petroleum Company) and subsequently blowing ~he gas system sand pack dry with nitrogen. The two sand pack tubes were then connected to the test system as described in Example II, and the procedure described in Example II was repeated. The initial permeabilities of the two sand packs, respec~ively, to gas and water were determined to be 4.89 and 7.86 darcies. The injection of the hydrocarbon-diluted polymeric latex concentrate following a small slug of methanol into the upper end of each tube and through each sand pack resulted in the permeability changes recorded in Table II.
TABI.E II
_l_tive Permeabilities to Water And Gas in Sand Packs Minutes Elapsed Residual After Injecting Oil-Saturated Hydrocarbon-Diluted Water System Gas System Sand % of Ini-Polymeric Latex Sand Pack Perme- Pack Perme- tial Gas Concentrate ability (Dsrcies) bility (Darcies) Permeabili~y Initial 7.86 4.89 Plugged 1.59 33 Plugged 2.08 43 Plugged 2.57 53 120 Plugged 3.05 62 180 Plugged 4.03 82 240 Plugged 4.03 82 As can be seen from the data in Table II, the water system sand pack became completely plugged within 5 minutcs after injection of the hydrocarbon-diluted polymeric latex concentrate flnd subsequent opening of the common effluent line to simulate tho return of a gas-bearing formation, reprosentod by tho sand packs, to production. The permeability of the rosidllal oil-saturated gas ~ystem salld pack to gas decrcased.l.nl~ia].ly, but aftcr 4 hours ~he gas p~rmeabili.ty hfld incre,ased to ~bout 4.03 dar.los, or about 82 porcent of the inlt:Lnl gas permeability, and ~h~ wat~r syxtcm sand pnck remained plugged. These results Agaill indi.catc the unexpocted feasibility of i.njccting a hydrocarbon-dilutod polymeric :latox concentrate into gas-bearing formations penetrated by gas produc.ing wells to increase the gas-to-water ratio of the fluids produced therefrom. As can further be seen from the results shown in Table II, the permeability to gas actually returned to about 82 percent of the original gas permeability after 3 hours whereas the permeability to water was reduced to essentially zero ~5~j7
EXAMPI.E III
Two identi.cal ~ubes of l-inch (2.54 cm.) dinmeter and 12-:lnch t30.48 cm.) length wero used to contain sfllld packs of Mill ,reek sand to further demorlstrate the effectiveness of tho process of the present inventiorl in decreasing water pormeabllity to a much grenter degree than any decrease in gas p~rmeability in a gns produclng formation. This run was carried out in essentially the same manner as described for Example II with the exception that the gas system sand pack was conditioned to produce residual hydrocarbon saturation therein prior to carrying out the run. The designated gas system sand pack was preliminarily conditioned by contacting the gas system sand pack with Soltrol 170 (a light liquid oil available from Phillips Petroleum Company) and subsequently blowing ~he gas system sand pack dry with nitrogen. The two sand pack tubes were then connected to the test system as described in Example II, and the procedure described in Example II was repeated. The initial permeabilities of the two sand packs, respec~ively, to gas and water were determined to be 4.89 and 7.86 darcies. The injection of the hydrocarbon-diluted polymeric latex concentrate following a small slug of methanol into the upper end of each tube and through each sand pack resulted in the permeability changes recorded in Table II.
TABI.E II
_l_tive Permeabilities to Water And Gas in Sand Packs Minutes Elapsed Residual After Injecting Oil-Saturated Hydrocarbon-Diluted Water System Gas System Sand % of Ini-Polymeric Latex Sand Pack Perme- Pack Perme- tial Gas Concentrate ability (Dsrcies) bility (Darcies) Permeabili~y Initial 7.86 4.89 Plugged 1.59 33 Plugged 2.08 43 Plugged 2.57 53 120 Plugged 3.05 62 180 Plugged 4.03 82 240 Plugged 4.03 82 As can be seen from the data in Table II, the water system sand pack became completely plugged within 5 minutcs after injection of the hydrocarbon-diluted polymeric latex concentrate flnd subsequent opening of the common effluent line to simulate tho return of a gas-bearing formation, reprosentod by tho sand packs, to production. The permeability of the rosidllal oil-saturated gas ~ystem salld pack to gas decrcased.l.nl~ia].ly, but aftcr 4 hours ~he gas p~rmeabili.ty hfld incre,ased to ~bout 4.03 dar.los, or about 82 porcent of the inlt:Lnl gas permeability, and ~h~ wat~r syxtcm sand pnck remained plugged. These results Agaill indi.catc the unexpocted feasibility of i.njccting a hydrocarbon-dilutod polymeric :latox concentrate into gas-bearing formations penetrated by gas produc.ing wells to increase the gas-to-water ratio of the fluids produced therefrom. As can further be seen from the results shown in Table II, the permeability to gas actually returned to about 82 percent of the original gas permeability after 3 hours whereas the permeability to water was reduced to essentially zero ~5~j7
5 minutes after the injection of the hydrocarbon-diluted polymeric latex concentrate of the present invcnti.on.
EXAMPLE IV
This example illustrates the actual successful application of the process of *he present invention to a gas-producing well in the Garden City, Kansas area. This particular gas well had been shut down after being tested at about 70 barrels of water per day with relatively little gflS flow. The original gas potential of this well was 100,000 standard cubic feet of gas per day. ~fter treating the well in accordance with the process of the present invention, the well was flowing water-free gas.
From the foregoing detailed description and examples, it will be readily apparent that the process of the present invention achieves the previously stated objects and overcomes the problems described above with regard to excessive water flow from a gas-producing formation into the well bore,of a producing gas well.
It will be understood that the specification and examples are provided for the purposes of illustrating and explaining the invention and that suitable variations may be made within the scope of the appended claims without departing from the invention.
EXAMPLE IV
This example illustrates the actual successful application of the process of *he present invention to a gas-producing well in the Garden City, Kansas area. This particular gas well had been shut down after being tested at about 70 barrels of water per day with relatively little gflS flow. The original gas potential of this well was 100,000 standard cubic feet of gas per day. ~fter treating the well in accordance with the process of the present invention, the well was flowing water-free gas.
From the foregoing detailed description and examples, it will be readily apparent that the process of the present invention achieves the previously stated objects and overcomes the problems described above with regard to excessive water flow from a gas-producing formation into the well bore,of a producing gas well.
It will be understood that the specification and examples are provided for the purposes of illustrating and explaining the invention and that suitable variations may be made within the scope of the appended claims without departing from the invention.
Claims (16)
PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A process for reducing the flow of water from a gas producing subsurface formation into the well bore of a gas producing well penetrating said formation, comprising:
injecting a hydrocarbon-diluted polymeric latex concentrate into said formation via said well bore, said hydrocarbon-diluted polymeric latex concentrate comprising a quantity of viscosifying polymer, a quantity of hydrocarbon diluent and a quantity of water, said quantity of water being present in an amount in the range from about 0.01 to about 5.0 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and allowing said polymeric latex concentrate to be contacted with connate water in said subsurface formation so as to substantially reduce the water permeability of said subsurface formation proximate said well bore while maintaining the gas permeability of said subsurface formation substantially unrestricted.
injecting a hydrocarbon-diluted polymeric latex concentrate into said formation via said well bore, said hydrocarbon-diluted polymeric latex concentrate comprising a quantity of viscosifying polymer, a quantity of hydrocarbon diluent and a quantity of water, said quantity of water being present in an amount in the range from about 0.01 to about 5.0 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and allowing said polymeric latex concentrate to be contacted with connate water in said subsurface formation so as to substantially reduce the water permeability of said subsurface formation proximate said well bore while maintaining the gas permeability of said subsurface formation substantially unrestricted.
2. A process in accordance with claim 1 wherein said hydrocarbon diluent is present in an amount in the range from about 75 to about 99 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
3. A process in accordance with claim 2 wherein said viscosifying polymer is present in an amount in the range from about 1.0 to about 20 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
4. A process in accordance with claim 2 wherein said hydrocarbon-diluted polymeric latex with claim 3 wherein said water-in-oil emulsifying agent in an amount in the range from about 0.001 to about 30 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
5. A process in accordance with claim 1 wherein the step of injecting a hydrocarbon-diluted polymeric latex concentrate into said subsurface formation via said well bore is preceded by the step of:
injecting a quantity of alcohol into said gas producing well so as to substantially remove water from the well bore.
injecting a quantity of alcohol into said gas producing well so as to substantially remove water from the well bore.
6. A process in accordance with claim 1 wherein said polymeric latex concentrate is a water-in-oil emulsion comprising a viscosifying polymer diluted with a hydrocarbon.
7. A process in accordance with claim 6 wherein said viscosifying polymer is polyacrylamide.
8. A process in accordance with claim 6 wherein said viscosifying polymer is polyacrylamide and said hydrocarbon is diesel oil.
9. A process in accordance with claim 1 characterized further to include:
allowing said gas producing subsurface formation to produce gas and portions of said previously injected hydrocarbon-diluted polymeric latex concentrate back into the well bore of said gas producing well.
allowing said gas producing subsurface formation to produce gas and portions of said previously injected hydrocarbon-diluted polymeric latex concentrate back into the well bore of said gas producing well.
10. A process in accordance with claim 6 wherein said viscosifying polymer hydrates upon contact with connate water in said subsurface formation so as to swell in said formation to selectively substantially reduce the water permeability of said subsurface formation where contacted by said connate water.
11. A process for reducing the flow of water from a gas producing subsurface formation into the well bore of a gas producing well penetrating said formation, comprising:
injecting a quantity of alcohol into said gas producing well so as to substantially remove water from the well bore;
thereafter injecting n hydrocarbon-diluted polymeric latex concentrate into said formation via said well bore, said hydrocarbon-diluted polymeric latex concentrate comprising:
water in an amount in the range from about 0.01 to about 5.0 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate;
a hydrocarbon diluent in an amount in the range from about 75 to about 99 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and a viscosifying polymer in an amount in the range from about 1.0 to about 20 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and subsequently allowing said gas producing subsurface formation to produce gas and portions of said previously injected hydrocarbon-diluted polymeric latex concentrate back into the well bore of said gas producing well.
injecting a quantity of alcohol into said gas producing well so as to substantially remove water from the well bore;
thereafter injecting n hydrocarbon-diluted polymeric latex concentrate into said formation via said well bore, said hydrocarbon-diluted polymeric latex concentrate comprising:
water in an amount in the range from about 0.01 to about 5.0 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate;
a hydrocarbon diluent in an amount in the range from about 75 to about 99 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and a viscosifying polymer in an amount in the range from about 1.0 to about 20 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate; and subsequently allowing said gas producing subsurface formation to produce gas and portions of said previously injected hydrocarbon-diluted polymeric latex concentrate back into the well bore of said gas producing well.
12. A process in accordance with claim 11 wherein said hydrocarbon-diluted polymeric latex concentrate further comprises a water in-oil emulsifying agent in an amount in the range from about 0.001 to about 30 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
13. A process in accordance with claim 11 wherein said water in said hydrocarbon-diluted polymeric latex concentrate is present in an amount in the range from about 0.01 to about 3.0 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
14. A process in accordance with claim 13 wherein said hydrocarbon diluent is present in an amount in the range from about 85 to about 95 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
15. A process in accordance with claim 14 wherein said viscosifying polymer is present in an amount in the range from about 5 to about 15 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
16. A process in accordance with claim 15 wherein said hydrocarbon-diluted polymeric latex concentrate further comprises a water-in-oil emulsifying agent in an amount in the range from about 0.1 to about 10 percent by weight based on the weight of said hydrocarbon-diluted polymeric latex concentrate.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US089,421 | 1979-10-30 | ||
| US06/089,421 US4276935A (en) | 1979-10-30 | 1979-10-30 | Treatment of subsurface gas-bearing formations to reduce water production therefrom |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1145667A true CA1145667A (en) | 1983-05-03 |
Family
ID=22217538
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000361673A Expired CA1145667A (en) | 1979-10-30 | 1980-10-07 | Treatment of subsuraface gas-bearing formations to reduce water production therefrom |
Country Status (6)
| Country | Link |
|---|---|
| US (1) | US4276935A (en) |
| CA (1) | CA1145667A (en) |
| GB (1) | GB2062070B (en) |
| MX (1) | MX155271A (en) |
| MY (1) | MY8500398A (en) |
| NO (1) | NO163340C (en) |
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| US4572295A (en) * | 1984-08-13 | 1986-02-25 | Exotek, Inc. | Method of selective reduction of the water permeability of subterranean formations |
| US4635726A (en) * | 1985-05-28 | 1987-01-13 | Texaco Inc. | Method for controlling lost circulation of drilling fluids with water absorbent polymers |
| US5161615A (en) * | 1991-06-27 | 1992-11-10 | Union Oil Company Of California | Method for reducing water production from wells |
| GB2262117B (en) * | 1991-12-05 | 1995-05-03 | British Petroleum Co Plc | Method for the production of oil |
| US5927404A (en) * | 1997-05-23 | 1999-07-27 | Exxon Production Research Company | Oil recovery method using an emulsion |
| US5904209A (en) | 1998-10-26 | 1999-05-18 | Technology Commercialization Corp. | Method and device for removal of production inhibiting liquid from a gas well |
| US7186673B2 (en) * | 2000-04-25 | 2007-03-06 | Exxonmobil Upstream Research Company | Stability enhanced water-in-oil emulsion and method for using same |
| US6550542B2 (en) | 2001-07-17 | 2003-04-22 | Conocophillips Company | Fluid profile control in enhanced oil recovery |
| AU2002347160A1 (en) | 2001-12-07 | 2003-06-17 | Aqueolic Canada Ltd. | Method for terminating or reducing water flow in a subterranean formation |
| CA2470440A1 (en) * | 2001-12-17 | 2003-07-17 | Exxonmobil Upstream Research Company | Solids-stabilized oil-in-water emulsion and a method for preparing same |
| US7338924B2 (en) | 2002-05-02 | 2008-03-04 | Exxonmobil Upstream Research Company | Oil-in-water-in-oil emulsion |
| US7866394B2 (en) * | 2003-02-27 | 2011-01-11 | Halliburton Energy Services Inc. | Compositions and methods of cementing in subterranean formations using a swelling agent to inhibit the influx of water into a cement slurry |
| US7642223B2 (en) | 2004-10-18 | 2010-01-05 | Halliburton Energy Services, Inc. | Methods of generating a gas in a plugging composition to improve its sealing ability in a downhole permeable zone |
| US7690429B2 (en) * | 2004-10-21 | 2010-04-06 | Halliburton Energy Services, Inc. | Methods of using a swelling agent in a wellbore |
| US7891424B2 (en) * | 2005-03-25 | 2011-02-22 | Halliburton Energy Services Inc. | Methods of delivering material downhole |
| US7870903B2 (en) * | 2005-07-13 | 2011-01-18 | Halliburton Energy Services Inc. | Inverse emulsion polymers as lost circulation material |
| CA2632526C (en) | 2005-12-22 | 2014-03-11 | Exxonmobil Upstream Research Company | Method of oil recovery using a foamy oil-external emulsion |
| CA2573503C (en) * | 2007-01-09 | 2013-04-23 | Aqueolic Canada Ltd. | Method for terminating or reducing water flow in a subterranean formation |
| US9222013B1 (en) | 2008-11-13 | 2015-12-29 | Cesi Chemical, Inc. | Water-in-oil microemulsions for oilfield applications |
| US20130292121A1 (en) | 2012-04-15 | 2013-11-07 | Cesi Chemical, Inc. | Surfactant formulations for foam flooding |
| US11407930B2 (en) | 2012-05-08 | 2022-08-09 | Flotek Chemistry, Llc | Compositions and methods for enhancement of production of liquid and gaseous hydrocarbons |
| US9200192B2 (en) | 2012-05-08 | 2015-12-01 | Cesi Chemical, Inc. | Compositions and methods for enhancement of production of liquid and gaseous hydrocarbons |
| US11180690B2 (en) | 2013-03-14 | 2021-11-23 | Flotek Chemistry, Llc | Diluted microemulsions with low surface tensions |
| US9464223B2 (en) | 2013-03-14 | 2016-10-11 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US9428683B2 (en) | 2013-03-14 | 2016-08-30 | Flotek Chemistry, Llc | Methods and compositions for stimulating the production of hydrocarbons from subterranean formations |
| US10717919B2 (en) | 2013-03-14 | 2020-07-21 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US9321955B2 (en) | 2013-06-14 | 2016-04-26 | Flotek Chemistry, Llc | Methods and compositions for stimulating the production of hydrocarbons from subterranean formations |
| US10421707B2 (en) | 2013-03-14 | 2019-09-24 | Flotek Chemistry, Llc | Methods and compositions incorporating alkyl polyglycoside surfactant for use in oil and/or gas wells |
| US10053619B2 (en) | 2013-03-14 | 2018-08-21 | Flotek Chemistry, Llc | Siloxane surfactant additives for oil and gas applications |
| US10287483B2 (en) | 2013-03-14 | 2019-05-14 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells comprising a terpene alcohol |
| US11254856B2 (en) | 2013-03-14 | 2022-02-22 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US9884988B2 (en) | 2013-03-14 | 2018-02-06 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US10590332B2 (en) | 2013-03-14 | 2020-03-17 | Flotek Chemistry, Llc | Siloxane surfactant additives for oil and gas applications |
| US10577531B2 (en) | 2013-03-14 | 2020-03-03 | Flotek Chemistry, Llc | Polymers and emulsions for use in oil and/or gas wells |
| US10000693B2 (en) | 2013-03-14 | 2018-06-19 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US10941106B2 (en) | 2013-03-14 | 2021-03-09 | Flotek Chemistry, Llc | Methods and compositions incorporating alkyl polyglycoside surfactant for use in oil and/or gas wells |
| US9868893B2 (en) | 2013-03-14 | 2018-01-16 | Flotek Chemistry, Llc | Methods and compositions for use in oil and/or gas wells |
| US9068108B2 (en) | 2013-03-14 | 2015-06-30 | Cesi Chemical, Inc. | Methods and compositions for stimulating the production of hydrocarbons from subterranean formations |
| US9890625B2 (en) | 2014-02-28 | 2018-02-13 | Eclipse Ior Services, Llc | Systems and methods for the treatment of oil and/or gas wells with an obstruction material |
| US9890624B2 (en) | 2014-02-28 | 2018-02-13 | Eclipse Ior Services, Llc | Systems and methods for the treatment of oil and/or gas wells with a polymeric material |
| CA2891278C (en) | 2014-05-14 | 2018-11-06 | Cesi Chemical, Inc. | Methods and compositions for use in oil and / or gas wells |
| CA3042567C (en) | 2014-07-28 | 2021-12-14 | Flotek Chemistry, Llc | Methods and compositions related to gelled layers in oil and/or gas wells |
| US10934472B2 (en) | 2017-08-18 | 2021-03-02 | Flotek Chemistry, Llc | Compositions comprising non-halogenated solvents for use in oil and/or gas wells and related methods |
| US11053433B2 (en) | 2017-12-01 | 2021-07-06 | Flotek Chemistry, Llc | Methods and compositions for stimulating the production of hydrocarbons from subterranean formations |
| US11104843B2 (en) | 2019-10-10 | 2021-08-31 | Flotek Chemistry, Llc | Well treatment compositions and methods comprising certain microemulsions and certain clay control additives exhibiting synergistic effect of enhancing clay swelling protection and persistency |
| US11512243B2 (en) | 2020-10-23 | 2022-11-29 | Flotek Chemistry, Llc | Microemulsions comprising an alkyl propoxylated sulfate surfactant, and related methods |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3097692A (en) * | 1959-04-16 | 1963-07-16 | Jersey Prod Res Co | Sand consolidation method |
| US3284393A (en) * | 1959-11-04 | 1966-11-08 | Dow Chemical Co | Water-in-oil emulsion polymerization process for polymerizing watersoluble monomers |
| US3087543A (en) * | 1960-01-27 | 1963-04-30 | Jersey Prod Res Co | Method for improving oil-water ratios of oil and gas wells |
| US3343599A (en) * | 1965-05-10 | 1967-09-26 | Petrolite Corp | Method of reducing the porosity of subterranean porous formations |
| US3308885A (en) * | 1965-12-28 | 1967-03-14 | Union Oil Co | Treatment of subsurface hydrocarbon fluid-bearing formations to reduce water production therefrom |
| US3734873A (en) * | 1970-12-15 | 1973-05-22 | Nalco Chemical Co | Rapid dissolving water-soluble polymers |
| US3624019A (en) * | 1970-12-15 | 1971-11-30 | Nalco Chemical Co | Process for rapidly dissolving water-soluble polymers |
| US3721295A (en) * | 1971-11-23 | 1973-03-20 | Nalco Chemical Co | Secondary recovery of petroleum |
| US3724547A (en) * | 1972-01-31 | 1973-04-03 | Nalco Chemical Co | Inverted latex water flooding method |
| US3780806A (en) * | 1972-01-31 | 1973-12-25 | Nalco Chemical Co | Inverted mixed latex for water flooding |
| US3893510A (en) * | 1974-08-12 | 1975-07-08 | Halliburton Co | Emulsion method of introducing polymers into a subterranean formation |
| US4034809A (en) * | 1976-03-17 | 1977-07-12 | Nalco Chemical Company | Hydrolyzed polyacrylamide latices for secondary oil recovery |
| CA1051340A (en) * | 1977-01-17 | 1979-03-27 | Clarence R. Fast | Selectively plugging water zones |
-
1979
- 1979-10-30 US US06/089,421 patent/US4276935A/en not_active Expired - Lifetime
-
1980
- 1980-10-07 CA CA000361673A patent/CA1145667A/en not_active Expired
- 1980-10-07 MX MX184221A patent/MX155271A/en unknown
- 1980-10-29 NO NO803236A patent/NO163340C/en unknown
- 1980-10-30 GB GB8034911A patent/GB2062070B/en not_active Expired
-
1985
- 1985-12-30 MY MY398/85A patent/MY8500398A/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| NO803236L (en) | 1981-05-04 |
| GB2062070B (en) | 1983-08-24 |
| MX155271A (en) | 1988-02-12 |
| NO163340B (en) | 1990-01-29 |
| US4276935A (en) | 1981-07-07 |
| GB2062070A (en) | 1981-05-20 |
| MY8500398A (en) | 1985-12-31 |
| NO163340C (en) | 1990-05-09 |
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