CA2234173A1 - Polymer enhanced foam workover, completion, and kill fluids - Google Patents
Polymer enhanced foam workover, completion, and kill fluids Download PDFInfo
- Publication number
- CA2234173A1 CA2234173A1 CA002234173A CA2234173A CA2234173A1 CA 2234173 A1 CA2234173 A1 CA 2234173A1 CA 002234173 A CA002234173 A CA 002234173A CA 2234173 A CA2234173 A CA 2234173A CA 2234173 A1 CA2234173 A1 CA 2234173A1
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- Prior art keywords
- foam
- polymer
- ppm
- solution
- gas
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Classifications
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- 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
- C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
- C09K8/94—Foams
-
- 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
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10S507/00—Earth boring, well treating, and oil field chemistry
- Y10S507/925—Completion or workover fluid
Abstract
Polymer enhanced foam fluid is utilized for completion, workover, and kill operations in wells penetrating subterranean formations. The foam is formed by appropriately adding a gas to an aqueous solution of a substantially noncrosslinked water-soluble polymer and a surfactant. The solution and the foam are substantially free of crosslinking agents. The foam may be generated at the surface or in a wellbore.
Description
W O 97/21018 PCT~US96/17460 POLYMER ENHANCED FOAM WORKOVER, COMPLETION~ AND KILL
FLUIDS
BACKGROUND OF THF INVENTION
Technical Fie~
The ,ùr~ser.l invention relates to a, n~U ~od for workover, completion, and killOpeldtiOnS in wells ~en e~d~ SUb~ dneal l rc,.l~ O- ~s, and more particularly, to a ~ U .o~ wherein a polymer ~. .l ~anced foam is u tili~d as a wellbors fluid during 10 workovsr, completion, and kill operations in wells ~"elr~ti.,y suL,I~ndnean rc,"nalio. .s.
R~-.kground of the Invention:
Subten ~nea" well completion, workover, and kill oper~liGI .s ars normally cond~ .Pd while the well is filled with fluid. A completion, workover, or kill fluid is 15 c~ OI ,Iy placed in a wellbore prior to ths oper~lion and is often "~aintai, .ed in the wellbore for the duration of the operation. The completion, worlcover, or kill fluid applies a h)~ osldlic pressure against ths ror.,-dlion fluid which is ~,eater than the pressurs sxerted by the for.,-aliol~ fluid ~le...plil-g to intrude into the wellbore. This o~,erb~la,-ced h~,dloslalic pressure prevents the intrusion of 20 rO, . ..~liol, fluids into the wellbore during pe- ru. .. ~al ,ce of the given oil field wellbore operation which is necess~ry from an G,c,erdli~- ,al slal I 'r ~ t to prsvsnt irllelrerellce from ror..-dlion fluids and which is also ,.ecess~y from a safetysldrl 'r ~i~ ll to prevent blowouts and well kicks. In uncased wQlls, mainlai..;. ~~ an overbaianced hydro~lal;c pressure also helps prsvent the wellbore wall from 25 caving in or sloughing into the wellbore~ Other f~lnctions of completion, workover, and kill fluids are to ~,.i"i",i~e fluid loss from the wellbore into the surrounding formation, to help support casin~ and tubing strings, and to provide a medium through which completion and workover G~eralions can be pe, ror~le.l.
There are a number of well known con~,e. .liûnal completion, workover, and 30 kill fluids which comprise high-density dispersions of fine solids in an a-llJeous liquid or a h~dl uca, ~o., liquid. The solid cor"~onenl of such a dis~er~iu,, may be a '~eighting agent" added to increase the fluid density, theraby providing a .ealer h~drOSIdliC pressure in the wellbore. Wei Jhtil ~g agents are ~e. ,~, dlly inert i. .olS~anic solids in solution or suspension, to increase the density of the fluid. Ar i. .o, yan;c solids in solution or suspension, to increase the density of the fluid. An exemplary completion, workover, and kill fluid is a dispersion of clay and/or gypsum in water.
Although conventional completion, workover, and kill fluids "e, rO.."
5 sati~racl~rily in many suL,ter, ~nean applications, high~ensity completion, workover, and kill fluids are generally unsuit~hlQ where the hy.ll us~aL;c pressure gradient of the completion, workover, or kill fluid is greater than the fracture or parting pressure y-radient of the rock surroundin~ the w~ or~. Thus, conventional foams, consisting of a gas co..lai-le~l within an ~ql~o~s liquid 10 medium, have been employed as alla" ,~ e completion, workover, and kill fluids in rO, IlldliOI .s s~ 'SC9~ le to fracturing by conventional foams. The gas decr~ases the fluid density to a value sufficient to maintain an overbalanced condition in the well without hydr~ ic~ily fracturing the formation.
Advanla~Jeous con~pleliGI " workover, and kill fluids are those which prevent 15 ror,.,alion fluid intrusion into the wellbore while preventing a~.pr~ci-'~le well~or~
fluid leakoff into the for,.,alion. Leakoff is the miy~alio-~ of the completion,workover, or kill fluid from the wellbore across the wellbore face into the surrounding r~J""~lions, resulting in loss of the fluid. Fluid leakoff can undesitably result in fo""alion cla,..age, or permeability r~d~ction, which is manifested in20 redl Icerl h~l ucal bOI l recovery from the formation or re~ ced injectivity into the fiul l l l-dliol ~. R~d~ ~tion in the fluid flow ca~ r can arise from relative permeability effects when an ~rlueo~s fluid invades an oil- or gas-L,ea-",~~ for..,alio,~ or as a result of .;I ,e"~;cal rt:acliGI ,s with " ,;. ,er~ls, such as clays, present in ths formation.
Leakoff is also u"desi,~ble becA~ ~se it requires r~pl~~,-~ent of the lost completion, 25 workover, or kill fluid. Although it is possihle to maintain the hydl usld~ic pressure ove, bdld"ce in the face of severe fluid leakoff by replenishing the lost completion, workover, or kill fluid, this practice can be cost prohibitive. Thus, minimizingleakoff ~3e~ ~ases the cost of the completion, workover, or kill G,~,ers~liG~ ,. Leakoff can also result in a well blowout with serious sa~ety and env;, u, .,)~e"lal 30 consequences.
In ~ esp~l ,se to the problem of leakoff, it is cGr"r"o" to place a fluid in thewellbore containing additives termed, "lost circ~ tion n~alerials," that specifically W O 97/21018 PCTrUS96/17460 inhibit fluid communication between the wellbore and surrounding for",dlio,~s across the wellbore face. Lost circulation l"~lerials are frequently polymeric species as described in U.S. rdle,lls 4,740,319; 4,726,906; 4,675,119; and 4,282,928. A liquid medium having a lost circ~ tion ",~lerial dissolved or 5 dispersed therein is termed a lost circl ll~tion fluid. Despite the general effectiveness of many convenlional lost ciru l~tion fluids, certain subler,dne~"conditions remain problematic for such fluids. In particular, conve,.liollal lost circulation fluids o~en do not effectively inhibit lost circ~ t~on in rO~ liol ,s havin~
relatively high ~,er,lle~L,ility matrix or relatively high permeability voids.
10 Conventional lost circ~ tion fluids may also be inapplicsble in water-sel)sili~e ro",lalions, ron"alions s~sceptible to relative permeability effects, or ro""alions sl Isceptible to fracturing or parting.
Thickeners are often included in weighted completion, workover, and kill fluids known in the art for leakoff inhibition. See, for sxample, Hudson et al., SPE
Paper No. 10652, which ~ I;scloses a w ~i,Jl lLed brine containing a fluid loss control agent, or U.S. Patent No. 4,391,925 to Mintz et al., which ~n~clQses a mulli~ ,ase kill fluid co~ rising a number of cGI ~s~ Jents including a hydrGcal bGI l, asu. r~anl, a clay, and an organic polymer.
Under downhole conditions where the wellbore is in direct communication 20 with high permeability voids, it can be extremely difficult to prevent fluid leakoff.
Conventional completion, workover, and kill fluids ~e"erally do not exhi_it sufficient flow resistanc~ to prevent them from escaping the wellbore into the formation via the high permeability voids. Conventional foams may have increased flow resistance, _ut they often lack sufficient structure to ~derlu~ely 25 stop leakoff and tend to reduce the rate of fluid IQSS, rather than stopping leakoff altogether.
Conventional completion, workover, and kill fluids may also be unsuiPhle ~ in water-sensitive fur,--alions bec~use of the risk of ro-l-.dLiGn damage due to incompatibilities between the comptetion, workover, and kill fluid and the 30 ro.,.,aLiG", particularly when leakoff does occur. Further, conventional completion, workover, and kill fluids are often difficult to remove from the for",dli~, ~ after any leakoff that occurs.
Conventional foams may be more coi"~alibie with the rurlll~liG~ " but they exhibit relatively high i, .sla~ility under certain formation cc, Idilio, .s. For ~ ,ple, conventional foams tend to exhibit ir,slabilily in the pfesence of crude oil andcollapse rapidiy into sepa,ate ~as and liquid pl,ases. They also ~aen~lly lack 5 ~eÇl~ te structure and healing ~r~hilities to remain foams while tubulars and other well hardware are moved in the well. In a~ ,o, -, conve, llio. ,al foams often degrade when placed in ror..wLions having high downhole t~l"per;,lures or in ror.,.alions having brines exhibiting a high salt or i .a' Jl ,ass conlenl.
Crosslinked polymer gels as taught by U.S. Patent 4,989,673 have demonstrated pe,ru.-"a"ce adv~"lages over the above-recited conventional completion, workover, and kill fluids and lost circulation fluids, ~ec~ ~58 in many inslances the gels effectively inhibit fluid ioss in for,.,alions having high permeability matrix or high conductivity voids, while ~ei ,er~lly avoiding signiflcant damage to water-sensitive ro~ lio~s. The relatively high ~I,en~ical cost of crosslinked polymer gels, however, often limits their prac1ical utility from an economic standpoint. Crosslinked polymer gels also have a relatively high hydrostatic pressure gradient in the wellbore that is undesirabl2 for ror",alions susceplible to fracturing or parting by conventional fluids of normal density. GQIS
are also difficult to remove from the fo""alion when leakoff has occurred.
Foamed gels, such as a polyacr,vlamide gel formed with a Cr(lll~
crosslinker, have been used as workover, completion, and kill fluids. Foamed gels ~enerally have superior leakoff properties, stability, and structure relative topolymer er,~ ,anced foams. However, the greater structure tends to interfere with movement of hardwara in the wellbore, In addition, foamed gels do not rehaal readily when hardware is moved. Further, Cr(lll) is i"cfeasi.,~ subject to env;.un,,,e,,lal r~slriclions, particularlyforwell operaLiol-s nearthe surface, wher~
fluids could migrate from the well into aquifers which provide a domestic water supply. If foamed gels invade the suL,ler, anean formation significantly, they can be difficult to remove and generally require the use of a gel breaker.
Despite the existe"ce of numerous completion, workover, and kill fluids in the art, many have limited utility. Thus, a need exists for a co3~ 1etion~ workover, and kill fluid having utility in hydrocarbon recovery operalio"s over a broad range W O 97/21018 PCTnJS96/17460 of operating conditions which can be encounlered in situ. Specific~lly, a need exists for a low density completion, workover, and kill fluid which effectively maintains a sufficient hydlosLalit~- pressure in the wellbore under adverse ~u, ~.liliul ,s to prevent or minimize the intrusion of for,. ,~lio., fluids into the u,~ re without exhibiting significant leakoff into the ~or,.,aliGn. A need also sxists for a completion, workover, and kill fluid which does not da~laye ths h~d~oca~ n fo".,~lion significantly. A further need exists for a low density completion, workover, and kill fluid which does not induce hydraulic fractures in the ~dj~r~nt subterranean formation. The completion, workover, or kill fluid should be i- ,ex~,ensive and easily ~e~a, t:d at the wellsite ~rom readily available consliluents.
The fluid should be nonfla",ri,able, non-toxic, and chemically unreactive with surface and wellbore hardware. Further, the fluid should have a consistency which permits downhole operations through it. In ar~dition, the fluid should be easy to remove co" ",lelely from the wellbore after the completion, workover, or kill operation is finished.
Accol .li. Iyly, it is an object of the ~resenl invention to provide a cornpletion, workover, and kill fluid that effectively pe,r~-".s in a wellbore pene~lin~ a subterranean formation having a relatively low ~ractura or ~,a,li"y pressure gradient without s~bst~nLially fracturing or parting the for",alion.
It is another object of the p(esenl invention to provide a con~leliGn, workover, and kill fluid that effectively prevents leakoff under a broad range of subler, dnea" conditions.
It is still another object of the present invention to provide a completion, workover, and kill that effectively prevents leakoff in a su~ter,d"ean fo,-"dliG"
FLUIDS
BACKGROUND OF THF INVENTION
Technical Fie~
The ,ùr~ser.l invention relates to a, n~U ~od for workover, completion, and killOpeldtiOnS in wells ~en e~d~ SUb~ dneal l rc,.l~ O- ~s, and more particularly, to a ~ U .o~ wherein a polymer ~. .l ~anced foam is u tili~d as a wellbors fluid during 10 workovsr, completion, and kill operations in wells ~"elr~ti.,y suL,I~ndnean rc,"nalio. .s.
R~-.kground of the Invention:
Subten ~nea" well completion, workover, and kill oper~liGI .s ars normally cond~ .Pd while the well is filled with fluid. A completion, workover, or kill fluid is 15 c~ OI ,Iy placed in a wellbore prior to ths oper~lion and is often "~aintai, .ed in the wellbore for the duration of the operation. The completion, worlcover, or kill fluid applies a h)~ osldlic pressure against ths ror.,-dlion fluid which is ~,eater than the pressurs sxerted by the for.,-aliol~ fluid ~le...plil-g to intrude into the wellbore. This o~,erb~la,-ced h~,dloslalic pressure prevents the intrusion of 20 rO, . ..~liol, fluids into the wellbore during pe- ru. .. ~al ,ce of the given oil field wellbore operation which is necess~ry from an G,c,erdli~- ,al slal I 'r ~ t to prsvsnt irllelrerellce from ror..-dlion fluids and which is also ,.ecess~y from a safetysldrl 'r ~i~ ll to prevent blowouts and well kicks. In uncased wQlls, mainlai..;. ~~ an overbaianced hydro~lal;c pressure also helps prsvent the wellbore wall from 25 caving in or sloughing into the wellbore~ Other f~lnctions of completion, workover, and kill fluids are to ~,.i"i",i~e fluid loss from the wellbore into the surrounding formation, to help support casin~ and tubing strings, and to provide a medium through which completion and workover G~eralions can be pe, ror~le.l.
There are a number of well known con~,e. .liûnal completion, workover, and 30 kill fluids which comprise high-density dispersions of fine solids in an a-llJeous liquid or a h~dl uca, ~o., liquid. The solid cor"~onenl of such a dis~er~iu,, may be a '~eighting agent" added to increase the fluid density, theraby providing a .ealer h~drOSIdliC pressure in the wellbore. Wei Jhtil ~g agents are ~e. ,~, dlly inert i. .olS~anic solids in solution or suspension, to increase the density of the fluid. Ar i. .o, yan;c solids in solution or suspension, to increase the density of the fluid. An exemplary completion, workover, and kill fluid is a dispersion of clay and/or gypsum in water.
Although conventional completion, workover, and kill fluids "e, rO.."
5 sati~racl~rily in many suL,ter, ~nean applications, high~ensity completion, workover, and kill fluids are generally unsuit~hlQ where the hy.ll us~aL;c pressure gradient of the completion, workover, or kill fluid is greater than the fracture or parting pressure y-radient of the rock surroundin~ the w~ or~. Thus, conventional foams, consisting of a gas co..lai-le~l within an ~ql~o~s liquid 10 medium, have been employed as alla" ,~ e completion, workover, and kill fluids in rO, IlldliOI .s s~ 'SC9~ le to fracturing by conventional foams. The gas decr~ases the fluid density to a value sufficient to maintain an overbalanced condition in the well without hydr~ ic~ily fracturing the formation.
Advanla~Jeous con~pleliGI " workover, and kill fluids are those which prevent 15 ror,.,alion fluid intrusion into the wellbore while preventing a~.pr~ci-'~le well~or~
fluid leakoff into the for,.,alion. Leakoff is the miy~alio-~ of the completion,workover, or kill fluid from the wellbore across the wellbore face into the surrounding r~J""~lions, resulting in loss of the fluid. Fluid leakoff can undesitably result in fo""alion cla,..age, or permeability r~d~ction, which is manifested in20 redl Icerl h~l ucal bOI l recovery from the formation or re~ ced injectivity into the fiul l l l-dliol ~. R~d~ ~tion in the fluid flow ca~ r can arise from relative permeability effects when an ~rlueo~s fluid invades an oil- or gas-L,ea-",~~ for..,alio,~ or as a result of .;I ,e"~;cal rt:acliGI ,s with " ,;. ,er~ls, such as clays, present in ths formation.
Leakoff is also u"desi,~ble becA~ ~se it requires r~pl~~,-~ent of the lost completion, 25 workover, or kill fluid. Although it is possihle to maintain the hydl usld~ic pressure ove, bdld"ce in the face of severe fluid leakoff by replenishing the lost completion, workover, or kill fluid, this practice can be cost prohibitive. Thus, minimizingleakoff ~3e~ ~ases the cost of the completion, workover, or kill G,~,ers~liG~ ,. Leakoff can also result in a well blowout with serious sa~ety and env;, u, .,)~e"lal 30 consequences.
In ~ esp~l ,se to the problem of leakoff, it is cGr"r"o" to place a fluid in thewellbore containing additives termed, "lost circ~ tion n~alerials," that specifically W O 97/21018 PCTrUS96/17460 inhibit fluid communication between the wellbore and surrounding for",dlio,~s across the wellbore face. Lost circulation l"~lerials are frequently polymeric species as described in U.S. rdle,lls 4,740,319; 4,726,906; 4,675,119; and 4,282,928. A liquid medium having a lost circ~ tion ",~lerial dissolved or 5 dispersed therein is termed a lost circl ll~tion fluid. Despite the general effectiveness of many convenlional lost ciru l~tion fluids, certain subler,dne~"conditions remain problematic for such fluids. In particular, conve,.liollal lost circulation fluids o~en do not effectively inhibit lost circ~ t~on in rO~ liol ,s havin~
relatively high ~,er,lle~L,ility matrix or relatively high permeability voids.
10 Conventional lost circ~ tion fluids may also be inapplicsble in water-sel)sili~e ro",lalions, ron"alions s~sceptible to relative permeability effects, or ro""alions sl Isceptible to fracturing or parting.
Thickeners are often included in weighted completion, workover, and kill fluids known in the art for leakoff inhibition. See, for sxample, Hudson et al., SPE
Paper No. 10652, which ~ I;scloses a w ~i,Jl lLed brine containing a fluid loss control agent, or U.S. Patent No. 4,391,925 to Mintz et al., which ~n~clQses a mulli~ ,ase kill fluid co~ rising a number of cGI ~s~ Jents including a hydrGcal bGI l, asu. r~anl, a clay, and an organic polymer.
Under downhole conditions where the wellbore is in direct communication 20 with high permeability voids, it can be extremely difficult to prevent fluid leakoff.
Conventional completion, workover, and kill fluids ~e"erally do not exhi_it sufficient flow resistanc~ to prevent them from escaping the wellbore into the formation via the high permeability voids. Conventional foams may have increased flow resistance, _ut they often lack sufficient structure to ~derlu~ely 25 stop leakoff and tend to reduce the rate of fluid IQSS, rather than stopping leakoff altogether.
Conventional completion, workover, and kill fluids may also be unsuiPhle ~ in water-sensitive fur,--alions bec~use of the risk of ro-l-.dLiGn damage due to incompatibilities between the comptetion, workover, and kill fluid and the 30 ro.,.,aLiG", particularly when leakoff does occur. Further, conventional completion, workover, and kill fluids are often difficult to remove from the for",dli~, ~ after any leakoff that occurs.
Conventional foams may be more coi"~alibie with the rurlll~liG~ " but they exhibit relatively high i, .sla~ility under certain formation cc, Idilio, .s. For ~ ,ple, conventional foams tend to exhibit ir,slabilily in the pfesence of crude oil andcollapse rapidiy into sepa,ate ~as and liquid pl,ases. They also ~aen~lly lack 5 ~eÇl~ te structure and healing ~r~hilities to remain foams while tubulars and other well hardware are moved in the well. In a~ ,o, -, conve, llio. ,al foams often degrade when placed in ror..wLions having high downhole t~l"per;,lures or in ror.,.alions having brines exhibiting a high salt or i .a' Jl ,ass conlenl.
Crosslinked polymer gels as taught by U.S. Patent 4,989,673 have demonstrated pe,ru.-"a"ce adv~"lages over the above-recited conventional completion, workover, and kill fluids and lost circulation fluids, ~ec~ ~58 in many inslances the gels effectively inhibit fluid ioss in for,.,alions having high permeability matrix or high conductivity voids, while ~ei ,er~lly avoiding signiflcant damage to water-sensitive ro~ lio~s. The relatively high ~I,en~ical cost of crosslinked polymer gels, however, often limits their prac1ical utility from an economic standpoint. Crosslinked polymer gels also have a relatively high hydrostatic pressure gradient in the wellbore that is undesirabl2 for ror",alions susceplible to fracturing or parting by conventional fluids of normal density. GQIS
are also difficult to remove from the fo""alion when leakoff has occurred.
Foamed gels, such as a polyacr,vlamide gel formed with a Cr(lll~
crosslinker, have been used as workover, completion, and kill fluids. Foamed gels ~enerally have superior leakoff properties, stability, and structure relative topolymer er,~ ,anced foams. However, the greater structure tends to interfere with movement of hardwara in the wellbore, In addition, foamed gels do not rehaal readily when hardware is moved. Further, Cr(lll) is i"cfeasi.,~ subject to env;.un,,,e,,lal r~slriclions, particularlyforwell operaLiol-s nearthe surface, wher~
fluids could migrate from the well into aquifers which provide a domestic water supply. If foamed gels invade the suL,ler, anean formation significantly, they can be difficult to remove and generally require the use of a gel breaker.
Despite the existe"ce of numerous completion, workover, and kill fluids in the art, many have limited utility. Thus, a need exists for a co3~ 1etion~ workover, and kill fluid having utility in hydrocarbon recovery operalio"s over a broad range W O 97/21018 PCTnJS96/17460 of operating conditions which can be encounlered in situ. Specific~lly, a need exists for a low density completion, workover, and kill fluid which effectively maintains a sufficient hydlosLalit~- pressure in the wellbore under adverse ~u, ~.liliul ,s to prevent or minimize the intrusion of for,. ,~lio., fluids into the u,~ re without exhibiting significant leakoff into the ~or,.,aliGn. A need also sxists for a completion, workover, and kill fluid which does not da~laye ths h~d~oca~ n fo".,~lion significantly. A further need exists for a low density completion, workover, and kill fluid which does not induce hydraulic fractures in the ~dj~r~nt subterranean formation. The completion, workover, or kill fluid should be i- ,ex~,ensive and easily ~e~a, t:d at the wellsite ~rom readily available consliluents.
The fluid should be nonfla",ri,able, non-toxic, and chemically unreactive with surface and wellbore hardware. Further, the fluid should have a consistency which permits downhole operations through it. In ar~dition, the fluid should be easy to remove co" ",lelely from the wellbore after the completion, workover, or kill operation is finished.
Accol .li. Iyly, it is an object of the ~resenl invention to provide a cornpletion, workover, and kill fluid that effectively pe,r~-".s in a wellbore pene~lin~ a subterranean formation having a relatively low ~ractura or ~,a,li"y pressure gradient without s~bst~nLially fracturing or parting the for",alion.
It is another object of the p(esenl invention to provide a con~leliGn, workover, and kill fluid that effectively prevents leakoff under a broad range of subler, dnea" conditions.
It is still another object of the present invention to provide a completion, workover, and kill that effectively prevents leakoff in a su~ter,d"ean fo,-"dliG"
2~ exhibiting relatively high pel",eability or high conduc~ivity voids.
It is yet another object of the present invention to provide a completion, workover, and kill fluid that is relatively stable under harsh ror"l~l,o.. conditions including the l~r~se"ce of high le",,~erdlures, crude oil, high salinity brines, or high hardness brines.
It is a further object of the present invention to provide a completion, workover, and completion, workover, and kill fluid that is cost effective and practical to use in the field.
W O 97/21018 PCT~US96/17460 It is a still further ob~ect of the ~.rese, .l invention to provide a completion, workover, and kill fluid which is self healing and has a collsislel,oy that ~er.downhole operations to be pe,-formed through it.
It is yet a further object of the prese.~l invention to provide a completion, workover, and kill fluid which is easy to remove from the wellbore snd ths for.,,dliun after the completion, workover, or kill operdlion is finished.
These objects and others are achieved in accor.l~r,ce with the invention described hereafter.
SUMMARY OF THF INVF~TION
To achieve the foregoing and other oi ~je-As, and in ac~rdal .ce with the purposes of the p,-~se. ,l invention, as e. ~ O~ ~ ~d and broadly des~ il-ed hsrein, the present invention is a process for use during hyJIoc ILGI~ well co,~,leliG,., workover, and kill operations. An ~ eous soll ~tion of a water-soluble, sl ~ ~sl~ Itially . ,o. I~ussl;r~ked polymer and a water-sol~ 'hlQ sur~actant is prepar~d.
The soll ~tion is sn~ ~sl~nlially free of agents ~p~le of crosslinkin3 the polymer.
A ~as is added to the ~ eo! ~s solution so as to form a polymer el Iha~ .ced foam which is placed in a well ,~enel.dliny a su~ter.~nean for.l.dlion RRIEF DFSCRIPTION OF THF DRAWINt~S
The accol"~anying drawings, which are incorpo,dled in and form a part of the specification, illustrate the embodi,.,el lls of the pr~se, ll invention and, tGyell .er with the des~ is~ion, serve to explain the principles of the invention.
In the drawings:
FIG. 1A is a graph showing the wsight per cent of water drained from polymer-e. Ihal ,ced and conventional foam samples as a function of foam agin~
time in a gr~du~ted cylinder;
FIG. 1B is a grsph showing the pe~c~,.laye of original foam height as a function of aging time for the foam sa~ Jles of FIG. 1A and an ad~itional conver,Liûnal foam sample;
FIG. 2 is a graph of the ~,c,par e nl viscosily of a bulk sample of a polymer enhanced foam of the present in~ention as a function of the shear rate;
FIG. 3 is a graph of the average apparent effective viscosil~r in a sand pack as a function of foam quality for conventional and polymer ~. Ii ,a--ced foams;
FIG. 4 is a graph of ~e average ~ppdr~"l effective viscosil~ in a sand pack as a function of the appal ~nl frontal advance rate for a polymer-sul racléa"l sol~ ~tion and for a polymer enhanced foam ~en~rdted from the same sol~ ~fiQn;
FIG. 5 is a graph showing the average apparent e~fective viscosity as a function of the appa~ frontal advance rate for the same polymer ~"l ,a. .ce~ foam i, Ije.Aed into a sand pack at al" ,ospl ,eric backpressure and at 3,450 kPa in ction pressure;
FIG. 6 is graph showing the average apparent effective visoosities as a function of ~3p~-ar~"l frontal advance rate in a sand pack for a series of polymer enhanced foams having different polymer co, IC6llll alions;
FIG. 7 is a graph showing the average appa, enl effective viscosil;~qs as a func~ion of apparent frontal advance rate in a sand pack for a series of polymer15 enhanced foams having dirrerel.l su,raclanl cGl,c~.,l,~lions;
FIG. 8 is a graph showing the average a~,are, .l effective viscosil;es as a function of apparent frontal advance rate in a sand pack for a series of polymere, ll ,al ,ced foams generated with cJirrere, ll gases and having similar foam rlu~lities;
FIG. 9 is a graph showing the average ap~Jara~l effective viscosities as a 20 function of apparent frontal advance rate in a sand pack for a series of polymer enhanced foams having fresh water and brine solvents and polyacrylamide polymers with dirrare, ll degrees of hydrolysis;
FIG. 10 is a graph showing the average a~parent effective viscosi~;es as a function of ap~ nl frontal advance rate in a sand pack for a series of polymer25 enhanced foams containing polyacrylamide polymers of ~Jirre,i"~ molec~
weights; and FIG. 11 is a graph showing the average a~,pare, ll effective viscosities as - a function of a~parer,l frontal advance rate in a sand pack for polymer enhanced foams having :1~ ueo~ls phase pH values of 7.5 and 10, respectively.
WO 97nlO18 PCTAJS96/17460 nFscRlpTloN OF THF p~FFFF~RFn EMBODIMFNTS
A number of specific terms are used throu~hout the specification to ~esc,ibe the pnJcess of the present invention and are defined as follows. A
sul,le~ ,ean hydlucalL,on-bearing rO, lllaliGn is a ~eolo~ structure com~.isi"5~5 a suhsl~nlially continuous geological material. The term '~vellbore" is defi--ed herein as a bore hole exte"~i"~ from the earth surface to a suL,le"ar-ean hy~l~ucar~on-bearing forrnation. Thus a wellbore is a conduit providin~ fluid comm~nics~lio" between the surface and the ~or",ation ~el~ dled II.er~y. A
prodl ~tion wellbore enables the removal of fluids f~om the ful l l IdliOI I to the surface 10 and an i njection wellbore enables the ,clacer"e, ll of fluid into the rwllldlion from the surface. It is noted that a given wellbora can function i..ler~l,an~eably as a pro~ ction wellbore or an injection wellbors de~e. Idin~ on whether a fluid is bein~
removed from or placed in the wellbore. The term '~ell" is synonymous with the term '~ellbore."
A "foam" is a stabilized gas dispersion ,.)dil-lai,.a~f within a liquid phase wherein a plurality of gas b~ ~hbles are separ~led from one a, IOU .er by i. ,t~. r~cially stabilized liquid films. The dispersed gas phase constit~ ~tes at least 20 per cent of the total volume of the foam. Conve,-lio"al oilfield foams co-)sisl of a ~as dispersed in a surFactant sol~ Ition made up of a su, rd.:lar.l and a solvent. The s~, raclal ,t acts as a foamin3 agent to facililaLe and stabilize the gas .lisper-~ion within the liquid phase. A "polymer enhanced foam" is a specific typ~ of oilfield foam comprising a gas dispersed in an ~ eo~ ~s su, ra.;td"t sol- ~ion wherein the a~ll IPoI Is surfactant solution further includes a polymer dissolved therein. Other terms used herein have the same definitions as ascribed to them in U.S. Patent No. 5,129,457 incorporated herein by , t:G~rt;nce or have definitions in accorda.,ce with the conventional usage of a skilled artisan, unless otherwise defined hereafter.
The process of the present invention is ~e.ro.,..ed by generating and placing a polymer enhanced foam within a wellbore in the specific manner 30 described hereafter. The polymer enhanced foam is generated from a ~uhst~rltially noncrosslinked water sol~hle polymer an ~ eoll-s solvent, a surfactant and a gas. It is important to note that the foam co,.",osilion is sl~hstantially free of any polymer crosslinking agent which could otherwise crosslink the polymer and convert the liquid phase of the foam to a crosslinked polymer gel at some point in the process.
The polymer cor",~.onent of the foam is sl ~nsl~nlially any water-soluble, 5 viscosity-enhancing polymer that is s~ sl~nlially l.o,.c~osslinked. Either a biopolymer or a synthetic polymer has utility herein. Biopolymers having utilityherein include polysaccharides and modified poly~au~l ,arides, such as xanthan gum, guar gum, succinoglycan, scleroglycan, polyvinylsa~;l~a,ides, carboxymethylcellulose, o-carboxychilosa"s, hydroxyethylcellulose, 10 hydroxypropyloell~'cse,andmodifiedstarches. Syntheticpolymershavin~utility herein include polyvinyl alcohol, polyethylene oxide, polyvinyl pyrrolidone, andacrylamide polymers. Exemplary acrylamide polymers are polyacrylamide;
partially hydrolyzed polyacrylamide; acrylamide copolymers; acrylar..ide terpolymers containing acrylamide, a second s,uec.es, and a third speci~s; and acrylamide tetrapolymers co~lainin3 acrylamide, acrylate, a third sp~cies, and afourth species. Polyacrylamide (PA) is defined as an auylamide homopolymer having s~ nlially less than about 1% of its acrylamide groups converted to ca.Lo,cylate groups. rd, lially hydrolyzed polyacryla,nide (PHPA3 is an acrylamide hGI I ~opolymer having more than about 1%, but not 100%, of its acrylamide groups converted to carboxylate ~roups. Useful acryla",icle polymers are ~Jrepar~d acco, ~i"g to any conv~, hiol ,al meU lod, but pr~rerably have the specific properties of an acrylamide polymer ~re,u~re~J accor l;~y to the ~ lhod ~isclose~ in U.S.
Patent No. Re. 32,114, incorporated herein by r~fer~nce.
The average molecular weight of an acrylamids polymer having utility herein is ~enerally in a range between about 10,0û0 and about 50,000,000, prefer~bly between about 250,000 and about 20,000,000, and most ~Jr~ferably between about 1,000,000 and about 18,000,000. The polymer co. .ce. .ll alion in the liquid phase of the foam is generally at least about 500 ppm, prsfera~ly at least about 2,000 ppm, and most pl-ererably within a range between about 3,000 ppm and about 10,000 ppm.
The ~ql ~eous solvent of the presel h polymer e~ Iha~ ~ced foam is s~ llially any ~ql ~eo~ Is liquid capable of forming a sol~ ~tion with the sele~ied polymer. The W O 97/21018 PCT~US96/17460 term " - '- ~tion" as used herein, in Adr~ition to true solutions, is ir,l~, .ded to broadly encompass clis,uersions, emulsions, or any other homogeneous mixture of the polymer in the ~ eouC solvent. The solvent is pre~er;~bly either a fresh watsr or a brine, such as a pro~ ced water from the suL,~er, d"ean ro",-alion. Proclucqcl5 water can be advant~Dso~Js hec~lse of its low~ost av~ hility and be~ ~se it enables the practitioner to return the pro~ water to the follllalio", thereby eliminating dispos~l thereof.
The su, r~utant of the polymer el Ihanced foam is s~ sl~nlially any water-soluble rc.a",illg agent suitable for oilfield use that is co,l~ with the 10 specific polymer selected as will be evident to the skilled artisan. As such, the su~ rac1anL can be a"ion- ~, caliol .ic, or nonionic. A ~,rere" ed s~,, ra~;ia, ll is selected from the group consisting of ethoxylated alcohols, ethoxylated s~l~tes, refined sLJlrol ,ales, ~ue~oleum sulrOI ,dles, and alpha olefin sulfonates. The CGI .~utt~liol, of su, raclanl in the liquid phase of the foam is in a range between about 20 ppm and about 50,000 ppm, ~lcreld~ly between about 50 ppm and about 20,000 ppm, and most 5~r~,~bly at least about 1000 ppm. In ~eneral, the pe~rurllla~ce of thepolymer enhanced foam in the method of the present invention is relatively insensiLive to the particular species and COI .cet.lralio" of the SUI raClanl si;ele~;te~, subject to the above-recited criteria, particularly when the sele-,ted polymer is an 20 acrylamide polymer.
Virtually any gas can be employed in the presel ll polymer eul .~nced ~oam to the extent the gas is sl Ihst~ntially che~ y inert with respect to the other foam components and with respect to wellbore production or i";~ion equipme5 .L. A
preferred ~as is one which is readily available in the field. Such gases include25 nitrogen, air, carbon dioxide, flue gas, prod~ ~cer~ gas, and natural gas. The quality of the polymer enhanced foam product, j.Q., the volume perce"la~e of ~as in the foam, is typically between about 2û% and about 99%, more ~referdL,ly between about 60~~ and about 98%, and most prefer~bly between about 70% and about 97%. As is appar~nl to one skilled in the art, foam density de~eases with 30 increasing foam quality.
It should be noted that some gases, particularly CO2, may becor"e liquids or super~i~ical fluids under te""~er~l.JrQ and pressure conditions likely to be CA 02234l73 l998-04-07 W O 97/21018 PCT~US96/17460 encou"Lered in a well. In either case, the foam may become a high visoosily emulsion. C02 emulsions have significantly lower densities than water. An emulsion can be used in many sit~ l~tions where it is desi~dble to use a low density workover, coll~r le';ca, or kill fluid. CO2 emulsions containing polymers ex~dl .-1 with 5 decreasing pressure and are eneryi~ed fluids. As used herain, the term "polymer enhanced foam" incl~ Ides emulsions.
Foam generation requires mixing the liquid phase and the gas either at a high velocity or through a small orifice as can be provided by any conventional artificial foarn generator. The liquid phase is ~,rt7rer~bly prefo, ~-,ulated by1Q dissolving the surfactant and polymer in the ~ eo~s solvent prior to foam SJel le~liGI 1. The foam is then generated, for exa- "ple, at the surface by passing the liquid phase and gas through a foam generator, and the resulting foam is delivered to the wellbore for injection therein. Aller, .dli~/ely, the foam is ~e,~er~led at the surface by c- nje~ing the gas and liquid phase into the wellbore across an 15 injection tee acting as a foam generator. In another allar"dli~e, the foam isyel ,t:rdLed downhole by ~ g the gas and liquid ,c I .ases via a CGI ~ .,no, . tubing string or se,.,ardle tubing strings into the wellbore and passing tha two sl. eams through a downhole foam generator. A foam breaker and/or other materials known to those skilled in the art may be added to the foam or to the ~ 90115 20 sol~ ~tion.
The pH of the liquid phase in the polymer enhanced foam is generally within a range of about 4 to about 10. In most cases, the pH of the liquid phasei. ll .erenLl~r falls within the above-recited range without any pH adjustment thereof.
However, the pH of the liquid phase can be ~dj~ ~ste~ in any r..ar" .er known to the 25 skilled artisan in accorda~ .ce with conve, ILio. ,al oilfieid procedures to achieve a desired pH range. Nevertheless, it has been found that tha present prucess is relatively insensitive to the pH of the liquid phase.
In the practice of the present invention, the polymer enl .anced foam may be placed in a wellbore as either a co" ,~lelio, ~ fluid, a workover fluid, or a kill fluid.
30 Placeme, .~ of the foam is further facilitated by the relatively highly shear thinning properties of the polymer enhanced foam. The polymar en h t,nced foam exhibits relatively high effective viscosities under low shear co, I-JiliGl ,s at the surface and W O 97121018 PCT~US96/17460 in the relatively low shear regions within the wellbore where the foam is pl~ce~l The polymer e, Ihal ,ced foam, however, exhibits relatively low effective viscosil;es under the high flow rate and liigh shear rate conditions encol,nle,ed as it is pumped into the w~lluo~ due to the ability of the foam to highly shear thin. Thus, 6 the high shear thinning ability and the low friction loss qualities of the foam allow the foam to be pumped easily. Nevertheless, once the polymer e. ~l .a, Iced foamis successfully placed in the wellbore, it beneficially shear thickens, ll.er.~l~y achieving a s~rldenl degree of structure and a sufFicient critical pressure gradient for flow to limit invasion of the polymer enhanced foam into tha sul.ter-dnean 10 formation a~j~cent the wellbore.
Relative to convenlional polymer-free foams, the polymar e, ~ nced foam is highly stable over a wide range of temperatures, pressures, water salinities, and water hardnesses. The polymer enhanced foam also resists collarse and fluid ~JI din age in the presence of many envil Ul 111 lel .lal cc I ,la, . .i. Icll .ls. In particular, the 15 polymer enhanced foam is stable in the presence o~ liquid hyJI uca- 6GI IS, unlike most conventional foams. The foam can be self healing so that if foarn degradation occurs as equipment is moved through the foam, the foam is c~p~hl~
of re~l l l l;l lg itself. The polymer e, Ihance~l foam resists flow from the wellbore and does not sl Ihst~ntially invade the ~dj~cent rc,rl..~lio, .. If the for..-~tion is invaded, 20 the energized nature of the foam aids in its removal. If the pressure is red~ ~cerl the gas ~ ~hbles in the foam expand and push a s~ IhstP~ntial portion of the foam out of the rul..~ OI ~. When the foam eventually breal<s down, the 3as, su, ractal ,1, and polymer resulting from foam breakdown may ellhance fluid flow between the formation and the well. The gases, su-r~;la-~ls, and polymers of polymer enhanced foams are commonly used as elll,d"ce-~ or improved oil recovery agents. Nevertheless, if desired, a conventional breaker can be i. .,~ ~ed into the ~ ~t" ,e, It region of the wellbore and/or any invaded near-wellbore portion of the formation to degrade the foam or polymer in situ and reslu,e the wellbore and near-wellbore region of the for".~Lio-, to their original condition.
Polymer enhancement of the foam also advant~eo~sly increases the structural strength and critical pressure gradient for flow of the foam relative to conver~lio"al polymer-free foams. The term "strength" refers to the resisla"ce of W O 97/21018 PCT~US96/17460 a foam to deformation when pressure or force is ~pplie~ to the foam, and the ~ ilical pressure gradient for flow" is defined herein as the maximum pressure that can be arplie~l to the foam without foam flow.
In general the polymer e"l,~"ced foam of the p~set,l invention should 5 have a 5iyl~ir~cald~ degree of structure. The viscosi~y and degree of structure of the polymer enhanced foam formulated in the ma""er of the present invention are primarily functions of the polymer properties and the polymer co"ce, ~ liol 1. In general the viscosity and degree of structure of a polymer enl,a"eed foam containing an acrylamide polymer are increased by incr~as;.,g the polymer 10 concentration of the liquid phase. However a more cost-effective and often preferred means for achieving the same effect is to employ a higher molec~ r weight polymer or in some cases a polymer having a higher degree of hydrolysis at a relatively fixed polymer conce, Ill dli~l 1. Conversely a re~ Iction in viscosily and the degree of structure is achieved by using a lower mcle~ weight 15 polymer a lower polymer CGI ,ce"lralion or in some cases a polymer having a lower degree of hydrolysis. Thus the skilled practitioner can modify the viscosily and the degree of structure of the preser,l polymer e,ll,a"ced foam in the above~esu iL,ecl ~anner to correspond with the leakoff pole,llial of the region of the rO" ll~liol ~ adjace, It the wellbore in which the completion workover or kill fluid 20 is used.
As is a~ afenl from above the low leakoK ~,aracleri-;lics of the polymer enhat,cecl foam are a function of its critical pressure gradient for flowl which can alternatively be termed yield pressure. The critical pressure gradient for flow is defined herein as the maximum pressure under specified conditions that can be 25 ~pplied to the foam without foam flow. ~he foam should exhibit a critical pressure gradient for foam flow higher than the pressure gradient across the wellbore face or existing in the near-wellbore region. By satisfying this criterion the ~oam will not flow into or through the rOI " ~alion adjace, ll the wellbore. Be~ Ise the polymer enhanced foam of the present invention has a relatively high critical pressure 30 gradient for foam flow particularly in co"~,va,iso" to conventional foams the polymer enl ,anced foam also perForms well as a low leakoff fluid.
,.,),bodi,.,enls of the ~u, esenl process have been cJes~ iL ed above wherein the polymer enl ,a"ced foam is ~ ,erdled prior to or durin~ placer, lenl of the foam in the wellbore. It is &ppalbl ,l to the skilled artisan from the instant ~isclQs~ ~re that there are numerous other related ap~licaliul~s within the scope of th~ ,~Jr~s~
5 invention.
The following examples demonstrate the p--actice and utility of the pres~"l invention, but are not to be construed as limiting the scope lhereor. In all of tlle ~xamples, foams are ge, lel ~led by co;. ,jecting a foam-formin~ s c ' ~fion and a ~as into a high permeability foam ~enerdlii,y sand pack. All e~eri,..ents are 10 cond~ ~ted at room te""~e, dlure unless otherwise noted. The foam forrns within about the first 2.5 cm of the sand pack and then advances through the rest of the sand pack. Thus, the foam generating sand pack may function as a foam ~ t,eraling device, as a model of a porous medium, or both simulla"eously. In each of the following examples, if a single sand pack is ! ~tili7ed, it ~,~, ru""s both 15 functions, and if two sand packs are ~Jti~ the first sand pack is for foam ~eneration and the seco"d is a test sand pack serving as a model of a porous medium. Foam properties, such as averagea~ are"tviscosity, are determined from data obtained for the foam in the sand pack, based on the entire length of the sand pac~ r, upel lies of bulk foam sa,) ,ples are similar to those observed in sand 20 packs.
Polymer enhanced foam stability in ylassware Conve, .licll ,al and polymer enhanced foams are ~repareJ to c~r,.~ar~ their 2~ stability and, in particular, their resistance to physical foam collars~ and water drainago under the influence of ~ravity. One of the convenli~l .al foams and thepolymer enhanced foam are s~ Ihst~ntially identical in composition except for the presence of an unhydrolyzed polyacrylamide at a COI ,cenll aliul, of 7,000 ppm in the ~ql leO! IS phase of the polymer enhanced foam. The molec~ weight of the 30 polymer is 11,000,000. The liquid phase of both foams is made up of a fresh water solvent containing 1,000 ppm of an ethoxylated sulfate SUI r~ctal ,l marketed co""~erc;ally as Enordet 121 5-3S by Shell Che, nic ~' Co., El ,I I~, Iced OR Recovery W O 97/21018 PCTrUS96/17460 Chemicals P. O. Box 2463 Houston Texas 77001. The su,racla.,l has the formula C12 ~EO3-SO4Na. A secon~ con~ e nlio- ,al foam is ~re~arecl with the same solvent and 5 000 ppm of Enordet 1215-3S su,r~ t in the ~ eo~l-s phase.
The foam samples are ~~e"e~led by coinjecting the liquid phase and N2 gas 5 into a foam y~"era~i..g sand pack. The sand pack has a ~ermeabilily of 67 C~il~ 2S, a length of 30 cm and a diameter of 1.1 cm. All flooding is cond~ Ict~ at 170 kPa constant ~irr~rtu,lial pressure across the sand pack and ~..os~l,e-ic ~ach~lessure. The polymer e- ~ ,~"ce.:l foam propa~tPs at a frontal advance rateof 207 m/day and e~ iaS an average appare,)l effective viscosil~ within the sand10 pack of 89 cp while the first conventional foam ,~,rup~ les at a frontal advance rate of 8 23~ m/day and exhibits an average éi~ Jdl t~ effective viscosil~ of only 2 cp at the same dirrere~ ,lial pressure. Thus the polymer erll ,a. .ce~ foam has a sl ~I sl~- ,Lially larger effective viscosity than the co~"lerl.~, I convenlional foam.
A tO0 cm3 sample of each fine-textured foam is collec~ed as effluent from 15 the sand pack and placed in a slo,. ~Jered gr~d~ ~te" cylinder for aging at ambient ter"~ er~lure. The positions of the foamfwater and foamlair i"le,races in the ~r~ te~l cylinde,~ are measured as a function of time to .Jele"..ine th~ rates of water drainage and foam collapse respectively for each of the samples. ThQ
results are shown in Figures 1A and 1 B respectively. It is appare,.l therein that 20 the rates of water drainage and foam collapse are much ~"edler for the conventional polymer-free foam than the polymer ~,~I,al,ced foam. A 100 cm3 sample of the 5 000 ppm su,ra~Lant convel,lional foam is also obtained in the same manner. The results are highly co.~,par~ble to the conv~-lt-o"al foam sample with 1000 ppm s~lr~Lalll as shown in FIG. 1B. Thus this ~xample 25 shows that the polymer enhanced foam is more stable with respect to water drainage and foam collapse under the influence of gravity than the convei ,liGnal polymer-free foam.
Further inereasing the su, rccta"l conc~ ILI alion i~ ,~eases the :,lal,ilily ofthe conventional foam slightly but the effect is much smaller than the effect of30 adding polymer to the a~ eo~ ~c solution. This example demG"sl, ales that adding a relatively small amount of polymer to a conventional foam i"crbases the foam stability significantly more than adding zd~itional su~ ~tal ll. Thus significant cost W O 97~1018 PCT~US9611746Q
savin3s and improved p~lror",ance can be achieved by addin~ a polymer to a ham rather than il,c.easir,y the surfactant c~i3)celllldlio,l. The stability of a polymcr enhanced foam is often ~, ealer in a porous medium than in labor~lo~y glassware.
Rheometer viscosil~r A polymer en.l ,anced foam is prt:pare~J' in a foam y~"e, ~li"~ sand pack by combining N2 gas with a solution of a prod~ ~r~d reservoir brine cor~laining 7,000 ppm PHPA and 2,000 ppm of Stepa,)llo 20, a C,~,8 alpha olefin slJlfo~al~
surfactant marketed by Stepan Chemical Co., 22 Fr~n~ya Road, Northfield, Illinois 60093. The brine contains 5,800 ppm total dissolved solids and has principle co"~liluents in the following concenlralio.ls; 560 ppm Ca~, 160 ppm Mg~, 1,500 ppm Na~, 200 ppm ~, 2,200 ppm SOi2, and 1,400 Cl . The PHPA is 30 per cent hydrolyzed and has a molea ~l~r weight of 11,000,000, and the foam quality is 88 per cent as prorl~ ~ce~ The foam is aged for five minutes, and viscosily measu,~"e"ls are then made on the bulk foam in a Rl,eG.I,e~,ics RFS
,heo."eter using the steady shear-rate mode. Shear rates from 0.15 to 700 sec~' are st~ e~' The polymer enl ,anceJ foam is a shear-ll ,i", .i. ,9 fluid over the antir~
range of shear rates. The minimum measured viscosity is 250 cp, and the maximum viscosity is over 40,000 cp. The power-law viscosity values (r-,) are determined to be N = 0.24 and K = 13,000 cp over the linear range of data obtained, where rl = K(y~' and y is the shear rate in units of sec~'. The rssults are shown in FIG. 2, with the power law curve fit shown as a solid line. The polymer e, ll lal~C6~.l foam e,d ~ ils s~ ~l .S~A. ,lial shear-ll ~i, u lil "J ~riscOsil~ behavior, indicating that the foam would be relatively easy to pump into and through wellbore tubulars.
A conventional foam is also prepared without the su, ractanl, and it is so unstabie that is not readily feasible to obtain similar meas-~l eme. ~
This example shows that the bulk polymer e, Ih~ .ced foam is highly shear thinning and that very large effective viscssilies can bo attained at low shsar rates. The rheological behavior of the bulk polymer enhanced foam is similar to that observed for the foam in porous media.
W O 97t21018 PCTrUS96/17460 Critical pressure ~ra.lie.1l for flow Polymer ~,II.ance~J and convenl;Gnal foams are ,~r~pal~ using Denver, Colorado, U.S.A., tap water, N2, 2,000 ppm in the ~ueo~ ~s phase of Bio-Ter~s 5 AS40, a C14-1G alpha olefin sulrO~ ,dLe SUI r~c~a. II obtained from Stepan Chemical CGr.,~,a"y, 22 FlunLage Road, Northfield, Illinois 60093 The polymer e(l~,a"c~d foam also contains 7,000 ppm in the ~q~ ~eous phase of 30 per c.ent hydrolyzed PHPA with a r~olec~ wei~ht of 11,000,000. The tap water co. .lai. .s 30 ppm ofC as C o;2, 78 ppm of Ca~, 18 ppm of Mg~, 130 ppm of Na~, 25 ppm of Cl, and 10 250 ppm of total dissolved solids. The critical pressure gradient for foam flow is det~.-"ined for the polymer enhanced foam in a sand pack having a ~J~I"~eabililyof 14Q darcies and a length of 30 cm. The sand pack is used in this case as a model of a porous medium. Flooding e~eri...e. .ls are cond~ lctP~ at ~IIG~I .eric l~ack,~r~ssure and at 3100 kPa backpressure for foam ~ ities L el~ on 57 and 15 93 per cent. The critical pressure gradient for foam flow of the polymer e. ~ ced foam is in the range of 452 to 678 kPa/m. The c.ritic.al pressure ~radient for foam nOwr for a conve- I~io. .al foam having the same com~ ioi - but without the polymer is 136 to 158 kPafm. The higher critical pressure ~ddi~lll of the polymer e. 11 .ance-J foam indicates that the polymer enhanced foam has signir,ca, .lly more 2û structure and less leakoff tendency than the conventional foam.
The critical pressure gradient for foam flow is also ~ete,.,li"ed for the polymer e nha~ d foam flowing through a 1.45 mm ID tube. The tube is used as a model of narrow tubing. The critical pressure gradient for flow is less than 2kPa/m, i. .~ that the foam has a l~e~ligiL,le yield ~ n~JU I and yield pressure 25 as it p~ses through the tube. Thus, the foam should flow readily through wsllbore tubulars and be easy to pump through well tubulars.
This example illustrates that the polymer enhanced foam of the present invention has a greater critical dirrerel ,lial pressure ~radient for foam flow, yield pressure, yield strength, and structure than its cou.~l6r,~.a~l conv~,~l;G"al foam.
30 ~hus, the polymer el Ihanced ~oam has better leakoff ~ro~,el lies than convef ~liGnal foams. Moreover, the polymer enhanced foam has a ne~ ihle yield s~ ~n~tt, and yield pressure as it flows through pipes and tubulars.
W O 97/21018 PCTrUS96/17460 Viscosity as function of foam quality A sample of a polymer e, II,a.lced foam and a sample of a conve. IliG-~I
polymer-free foam that is s~hstPrltially id~l.Lioal in coi-,posi(io,. to the polymer 5 1~1 Ihdl ~ced foam except for the absel .ce of a polymer CO-"~JO~ .e, .L are 5,r~par~J to cor."Jal-~ the effective viscoQities of the two foams as a function of foam quality.
Both foams are formulated from N2 and a brine solvent having a C,4 ~8 alpha olefin sulro, .~le sL-, rac~, .~ dissolved therein at a ~ncenlraliG- ~ of 2,000 ppm. Th~ brine contains 5,800 ppm total dissolved solids and has p.i-,oiple co..:,lil.Jents in ~e following oGI~ce"~lio"s. 560 ppm Ca~, 160 ppm Mg~, 1,500 ppm Na~, 2Q0 ppm ~~, 2,200 ppm SOj2, and 1,400 ppm Cl~. The ~ eo~s phase of the polymer enhanced foam ~d~;tionally con~ai"s a partially hydrolyzed polyacryla,l.id~ at aconcentration of 7,000 ppm. The partially hydrolyzed polyacrylamide has a molea ~ r wei~ht of 11,000,000 and is 30% hydrolyzed.
A sand pack s~ sl~.nlially the same as that of Example 2 is noo-J~d with each foam over a range of foam t~ ties A first polymer enl ,anced foam sample is flooded at a backpressure of 1,725 kPa and a dirr~re"lial pressure o~ 345 kPa.
The first sa, nple pl ~ g~le5 at an ~,u~ ent frontal advance rate of between about 158-198 m/day. A second polymer elll,anced foam ssmple is flooded at a backpressure of 3,100 kPa and a differential pressure of 345 kPa, and the a~ucrel ~l frontal advance rate is between 146 and 213 m/day. The conve, .I,~,lal foam sample is floo~e~l at ~llllospl ,eric backpressure and a ~lirrere"lial pressure of 138 kPa and pru~u~g~lPs at a frontal advance rats between about 335 and 1,463 m/day.
The results are set forth in FIG. 3 and indicate that the sensitivity of the average appar~nl viscosi~ of the polymer e nl~a~ ,ced foam to foam quality is much less than that for the counterpart conventional foam. Ful ll ,e,-nore, the effective viscosily of the polymer enl ~ance~J foam at any ~iven foam quality is much 5,~ ~ater than that of the conve~ Gl ,al foam. In FIG. 3, UPEF refers to polymer ~ Iced foam, and UBP~ refers to backpressure.
W O 97/21018 PCTrUS96/17460 EXAMPLE ~
Frontal advance rate of polymer ~ u hance~l foam and polymer solution A polymer enh al Iced solutTon is prepare-l, also using a reservoir brine and the same su.ra~ant and polymer as in Exd---~les 3 and 4. The s~' ltion CGllt~;i.lS
5 2,000 ppm sl~ r~l ll and 7,000 ppm of PHP~ A p~ n of the sol~ Ition and then . IoU ,er portion of the solution and N2 ~as are i- ~,e_~e~ into a 170 darcy sand pack at atmospheric back~ressure and ~o C, with a c~ nl pressure drop between 138 and 1,380 kPa. The sand pack is 30 cm long and has an inner dia...etdr of 1.1 cm. The resulting foam qualities range from 77 to 89 per cent.
FIG. 4 shows the appdl el l~ average effective viscosity (AAE) of the ~ eol ~s polymer solution and polymer en~, nced ~oams as a function of the a,u~are,lt frontal advance rate. The polymer enhanced foam is a shear U ,inn;.~ fluid, and the viscosily behavlor ~. Irurll~s to the power-law model over the range o~ frontal advance rates and shear rates st~ ied The viscosity and shear thinnin 15 ~Jru~uel lies of the polymer enhanced foam mirror the viscosily and shear thinnin~
,uropel lies of the polymer solution. Further, the viscosity of the polymer e(ll ,anced foam is very similar to the viscosil~r of the polymer ssl~ ~tion. Thus, the quantity of polymer can be siyniricanlly rerl~ced by usin~ a foam rather than a polymer sol ~tion, resulting in similar rheological pe, ron~.ance with a si5;~. .irlcanl Jecf~ase 20 in the cost of the polymer and polymer SO~ ion used in a completion, workover, or kill operation.
Effects of pressure on frontal advance rate and effective viscosity Polymer e.ll,anced foams are p.e,uared using a sol~tion of 2,00û ppm 25 s~u r;a~ nl and 7,000 ppm of Pl IPA with a moleu -l~r weight of 11 ,û00,000 in a reservoir brine and using N2 as the ~as phase. The brine, s~ ractar,l, and polymer sre the same as those used in Example 4. The foam ~ lities range from 81 to 89 per cent. One set of foams is formed by injecting the polymerlsl"r~,tanl solution and the gas directly into a 120 darcy test sand pack at 22~ C and 30 atmospheric backpressure. The sand pack is 30 cm long and has an inner dia" ,eter of 1.0 cm. The sand pack functions as a foam ~e- ~er;dlin~ device and a model of a porous medium. The second flood is pl~rorl"ed in a 120 darcy foam W O 97/21018 PCT~US96/17460 ~ene.~lin~ sand pack and then i" e~ted into a 120 darcy test sand pack at 3 450 kPa injection pressure and 22~ C.
FIG. 5 shows the average apparent effective viscosil~ as a function of the a~",are, ll frontal advance rate for the in-situ~el ,eraled foarn and ~e ~,r~fu. ..-ed foam. The high pressure data shown in FIG. 5 are co"",aral~le to the atn~ospl .e~ic pressure data of E~a---tule 5 which ars FLtte~ as trian~les. These data and the data shown in FIG. 4 (Example 5) in~icale that the appar~,-l visc~si~;es of the polymar enl~a~.ced foams are nearly inde~uer,- e,~t of pressure. Ah-iiti~"ally it is shown that ve~ iar~e effective visc~;lies can be allai- .eJ at low shear rates, anci the rheological ~,r~.pelLies of preror",ed and in-situ~el-er~ed foams are nearlyide- ~lical.
Effect o~ te."~er~lure on foam sldl,ili4 A polymer en h a"ced foam is p.~par~d usin~ the reservoir brine containin~
2,000 ppm of s~Oracta.lt 7 000 ppm of PHPA with a moleo~ w~ight of 11 000 000 and N2. The sl~l rdclanl~ polymer and brine are the same as those used in Example 4. The polymer enhanced foam is ~e"e-~led in a 170 darcy foam yel ,er~ sand pack at an ap~.arenl frontal advance rat~ of about 1 524 m/day.
The sand pack has a length of 30 cm and a dia."eter of t.1 cm and the experiment is cond~cte~l at 22~C and ~r~e~le~ at 51~ C. 100 ml of each foam e~uent is colle~J in a sl,J~,pered gr~d~ e~ cylinder and aged at 22~ C and 51~
C respectiYely. The foam volumes are observed durin~ the next 24 hours and the results are shown in Table 1. I~ asi"g th~ temperature from 22 to 51~ C has no significant effect on the stability of the polymer ~-ll Idl ~c~3d foam for the first seven hours of aging. In ~d~lition the polymer e ul ,a, .ced foam shows superiorstability to that of a convenl;o"al foam at 51~ C.
As noted during the noodi"g e~e~ e~ the e~ective Yi300-';ity of the foam decreases as the temperature i"creases. At each temperaturo the effective viscosity of the polymer enl ,anced foam is proportional to the effectivQ viscosil~
of the poly T er sol~ Ition alone which is inversely ~ro,uo, lio- Ial to the te."~er~l~re.
Table I
Aging Time (hr) Foam Volume (cm3) Foam Volume (cm3) 22~ C 51~C
0.25 100. 100.
1.0 100. 100.
2.0 97. 98.
It is yet another object of the present invention to provide a completion, workover, and kill fluid that is relatively stable under harsh ror"l~l,o.. conditions including the l~r~se"ce of high le",,~erdlures, crude oil, high salinity brines, or high hardness brines.
It is a further object of the present invention to provide a completion, workover, and completion, workover, and kill fluid that is cost effective and practical to use in the field.
W O 97/21018 PCT~US96/17460 It is a still further ob~ect of the ~.rese, .l invention to provide a completion, workover, and kill fluid which is self healing and has a collsislel,oy that ~er.downhole operations to be pe,-formed through it.
It is yet a further object of the prese.~l invention to provide a completion, workover, and kill fluid which is easy to remove from the wellbore snd ths for.,,dliun after the completion, workover, or kill operdlion is finished.
These objects and others are achieved in accor.l~r,ce with the invention described hereafter.
SUMMARY OF THF INVF~TION
To achieve the foregoing and other oi ~je-As, and in ac~rdal .ce with the purposes of the p,-~se. ,l invention, as e. ~ O~ ~ ~d and broadly des~ il-ed hsrein, the present invention is a process for use during hyJIoc ILGI~ well co,~,leliG,., workover, and kill operations. An ~ eous soll ~tion of a water-soluble, sl ~ ~sl~ Itially . ,o. I~ussl;r~ked polymer and a water-sol~ 'hlQ sur~actant is prepar~d.
The soll ~tion is sn~ ~sl~nlially free of agents ~p~le of crosslinkin3 the polymer.
A ~as is added to the ~ eo! ~s solution so as to form a polymer el Iha~ .ced foam which is placed in a well ,~enel.dliny a su~ter.~nean for.l.dlion RRIEF DFSCRIPTION OF THF DRAWINt~S
The accol"~anying drawings, which are incorpo,dled in and form a part of the specification, illustrate the embodi,.,el lls of the pr~se, ll invention and, tGyell .er with the des~ is~ion, serve to explain the principles of the invention.
In the drawings:
FIG. 1A is a graph showing the wsight per cent of water drained from polymer-e. Ihal ,ced and conventional foam samples as a function of foam agin~
time in a gr~du~ted cylinder;
FIG. 1B is a grsph showing the pe~c~,.laye of original foam height as a function of aging time for the foam sa~ Jles of FIG. 1A and an ad~itional conver,Liûnal foam sample;
FIG. 2 is a graph of the ~,c,par e nl viscosily of a bulk sample of a polymer enhanced foam of the present in~ention as a function of the shear rate;
FIG. 3 is a graph of the average apparent effective viscosil~r in a sand pack as a function of foam quality for conventional and polymer ~. Ii ,a--ced foams;
FIG. 4 is a graph of ~e average ~ppdr~"l effective viscosil~ in a sand pack as a function of the appal ~nl frontal advance rate for a polymer-sul racléa"l sol~ ~tion and for a polymer enhanced foam ~en~rdted from the same sol~ ~fiQn;
FIG. 5 is a graph showing the average apparent e~fective viscosity as a function of the appa~ frontal advance rate for the same polymer ~"l ,a. .ce~ foam i, Ije.Aed into a sand pack at al" ,ospl ,eric backpressure and at 3,450 kPa in ction pressure;
FIG. 6 is graph showing the average apparent effective visoosities as a function of ~3p~-ar~"l frontal advance rate in a sand pack for a series of polymer enhanced foams having different polymer co, IC6llll alions;
FIG. 7 is a graph showing the average appa, enl effective viscosil;~qs as a func~ion of apparent frontal advance rate in a sand pack for a series of polymer15 enhanced foams having dirrerel.l su,raclanl cGl,c~.,l,~lions;
FIG. 8 is a graph showing the average a~,are, .l effective viscosil;es as a function of apparent frontal advance rate in a sand pack for a series of polymere, ll ,al ,ced foams generated with cJirrere, ll gases and having similar foam rlu~lities;
FIG. 9 is a graph showing the average ap~Jara~l effective viscosities as a 20 function of apparent frontal advance rate in a sand pack for a series of polymer enhanced foams having fresh water and brine solvents and polyacrylamide polymers with dirrare, ll degrees of hydrolysis;
FIG. 10 is a graph showing the average a~parent effective viscosi~;es as a function of ap~ nl frontal advance rate in a sand pack for a series of polymer25 enhanced foams containing polyacrylamide polymers of ~Jirre,i"~ molec~
weights; and FIG. 11 is a graph showing the average a~,pare, ll effective viscosities as - a function of a~parer,l frontal advance rate in a sand pack for polymer enhanced foams having :1~ ueo~ls phase pH values of 7.5 and 10, respectively.
WO 97nlO18 PCTAJS96/17460 nFscRlpTloN OF THF p~FFFF~RFn EMBODIMFNTS
A number of specific terms are used throu~hout the specification to ~esc,ibe the pnJcess of the present invention and are defined as follows. A
sul,le~ ,ean hydlucalL,on-bearing rO, lllaliGn is a ~eolo~ structure com~.isi"5~5 a suhsl~nlially continuous geological material. The term '~vellbore" is defi--ed herein as a bore hole exte"~i"~ from the earth surface to a suL,le"ar-ean hy~l~ucar~on-bearing forrnation. Thus a wellbore is a conduit providin~ fluid comm~nics~lio" between the surface and the ~or",ation ~el~ dled II.er~y. A
prodl ~tion wellbore enables the removal of fluids f~om the ful l l IdliOI I to the surface 10 and an i njection wellbore enables the ,clacer"e, ll of fluid into the rwllldlion from the surface. It is noted that a given wellbora can function i..ler~l,an~eably as a pro~ ction wellbore or an injection wellbors de~e. Idin~ on whether a fluid is bein~
removed from or placed in the wellbore. The term '~ell" is synonymous with the term '~ellbore."
A "foam" is a stabilized gas dispersion ,.)dil-lai,.a~f within a liquid phase wherein a plurality of gas b~ ~hbles are separ~led from one a, IOU .er by i. ,t~. r~cially stabilized liquid films. The dispersed gas phase constit~ ~tes at least 20 per cent of the total volume of the foam. Conve,-lio"al oilfield foams co-)sisl of a ~as dispersed in a surFactant sol~ Ition made up of a su, rd.:lar.l and a solvent. The s~, raclal ,t acts as a foamin3 agent to facililaLe and stabilize the gas .lisper-~ion within the liquid phase. A "polymer enhanced foam" is a specific typ~ of oilfield foam comprising a gas dispersed in an ~ eo~ ~s su, ra.;td"t sol- ~ion wherein the a~ll IPoI Is surfactant solution further includes a polymer dissolved therein. Other terms used herein have the same definitions as ascribed to them in U.S. Patent No. 5,129,457 incorporated herein by , t:G~rt;nce or have definitions in accorda.,ce with the conventional usage of a skilled artisan, unless otherwise defined hereafter.
The process of the present invention is ~e.ro.,..ed by generating and placing a polymer enhanced foam within a wellbore in the specific manner 30 described hereafter. The polymer enhanced foam is generated from a ~uhst~rltially noncrosslinked water sol~hle polymer an ~ eoll-s solvent, a surfactant and a gas. It is important to note that the foam co,.",osilion is sl~hstantially free of any polymer crosslinking agent which could otherwise crosslink the polymer and convert the liquid phase of the foam to a crosslinked polymer gel at some point in the process.
The polymer cor",~.onent of the foam is sl ~nsl~nlially any water-soluble, 5 viscosity-enhancing polymer that is s~ sl~nlially l.o,.c~osslinked. Either a biopolymer or a synthetic polymer has utility herein. Biopolymers having utilityherein include polysaccharides and modified poly~au~l ,arides, such as xanthan gum, guar gum, succinoglycan, scleroglycan, polyvinylsa~;l~a,ides, carboxymethylcellulose, o-carboxychilosa"s, hydroxyethylcellulose, 10 hydroxypropyloell~'cse,andmodifiedstarches. Syntheticpolymershavin~utility herein include polyvinyl alcohol, polyethylene oxide, polyvinyl pyrrolidone, andacrylamide polymers. Exemplary acrylamide polymers are polyacrylamide;
partially hydrolyzed polyacrylamide; acrylamide copolymers; acrylar..ide terpolymers containing acrylamide, a second s,uec.es, and a third speci~s; and acrylamide tetrapolymers co~lainin3 acrylamide, acrylate, a third sp~cies, and afourth species. Polyacrylamide (PA) is defined as an auylamide homopolymer having s~ nlially less than about 1% of its acrylamide groups converted to ca.Lo,cylate groups. rd, lially hydrolyzed polyacryla,nide (PHPA3 is an acrylamide hGI I ~opolymer having more than about 1%, but not 100%, of its acrylamide groups converted to carboxylate ~roups. Useful acryla",icle polymers are ~Jrepar~d acco, ~i"g to any conv~, hiol ,al meU lod, but pr~rerably have the specific properties of an acrylamide polymer ~re,u~re~J accor l;~y to the ~ lhod ~isclose~ in U.S.
Patent No. Re. 32,114, incorporated herein by r~fer~nce.
The average molecular weight of an acrylamids polymer having utility herein is ~enerally in a range between about 10,0û0 and about 50,000,000, prefer~bly between about 250,000 and about 20,000,000, and most ~Jr~ferably between about 1,000,000 and about 18,000,000. The polymer co. .ce. .ll alion in the liquid phase of the foam is generally at least about 500 ppm, prsfera~ly at least about 2,000 ppm, and most pl-ererably within a range between about 3,000 ppm and about 10,000 ppm.
The ~ql ~eous solvent of the presel h polymer e~ Iha~ ~ced foam is s~ llially any ~ql ~eo~ Is liquid capable of forming a sol~ ~tion with the sele~ied polymer. The W O 97/21018 PCT~US96/17460 term " - '- ~tion" as used herein, in Adr~ition to true solutions, is ir,l~, .ded to broadly encompass clis,uersions, emulsions, or any other homogeneous mixture of the polymer in the ~ eouC solvent. The solvent is pre~er;~bly either a fresh watsr or a brine, such as a pro~ ced water from the suL,~er, d"ean ro",-alion. Proclucqcl5 water can be advant~Dso~Js hec~lse of its low~ost av~ hility and be~ ~se it enables the practitioner to return the pro~ water to the follllalio", thereby eliminating dispos~l thereof.
The su, r~utant of the polymer el Ihanced foam is s~ sl~nlially any water-soluble rc.a",illg agent suitable for oilfield use that is co,l~ with the 10 specific polymer selected as will be evident to the skilled artisan. As such, the su~ rac1anL can be a"ion- ~, caliol .ic, or nonionic. A ~,rere" ed s~,, ra~;ia, ll is selected from the group consisting of ethoxylated alcohols, ethoxylated s~l~tes, refined sLJlrol ,ales, ~ue~oleum sulrOI ,dles, and alpha olefin sulfonates. The CGI .~utt~liol, of su, raclanl in the liquid phase of the foam is in a range between about 20 ppm and about 50,000 ppm, ~lcreld~ly between about 50 ppm and about 20,000 ppm, and most 5~r~,~bly at least about 1000 ppm. In ~eneral, the pe~rurllla~ce of thepolymer enhanced foam in the method of the present invention is relatively insensiLive to the particular species and COI .cet.lralio" of the SUI raClanl si;ele~;te~, subject to the above-recited criteria, particularly when the sele-,ted polymer is an 20 acrylamide polymer.
Virtually any gas can be employed in the presel ll polymer eul .~nced ~oam to the extent the gas is sl Ihst~ntially che~ y inert with respect to the other foam components and with respect to wellbore production or i";~ion equipme5 .L. A
preferred ~as is one which is readily available in the field. Such gases include25 nitrogen, air, carbon dioxide, flue gas, prod~ ~cer~ gas, and natural gas. The quality of the polymer enhanced foam product, j.Q., the volume perce"la~e of ~as in the foam, is typically between about 2û% and about 99%, more ~referdL,ly between about 60~~ and about 98%, and most prefer~bly between about 70% and about 97%. As is appar~nl to one skilled in the art, foam density de~eases with 30 increasing foam quality.
It should be noted that some gases, particularly CO2, may becor"e liquids or super~i~ical fluids under te""~er~l.JrQ and pressure conditions likely to be CA 02234l73 l998-04-07 W O 97/21018 PCT~US96/17460 encou"Lered in a well. In either case, the foam may become a high visoosily emulsion. C02 emulsions have significantly lower densities than water. An emulsion can be used in many sit~ l~tions where it is desi~dble to use a low density workover, coll~r le';ca, or kill fluid. CO2 emulsions containing polymers ex~dl .-1 with 5 decreasing pressure and are eneryi~ed fluids. As used herain, the term "polymer enhanced foam" incl~ Ides emulsions.
Foam generation requires mixing the liquid phase and the gas either at a high velocity or through a small orifice as can be provided by any conventional artificial foarn generator. The liquid phase is ~,rt7rer~bly prefo, ~-,ulated by1Q dissolving the surfactant and polymer in the ~ eo~s solvent prior to foam SJel le~liGI 1. The foam is then generated, for exa- "ple, at the surface by passing the liquid phase and gas through a foam generator, and the resulting foam is delivered to the wellbore for injection therein. Aller, .dli~/ely, the foam is ~e,~er~led at the surface by c- nje~ing the gas and liquid phase into the wellbore across an 15 injection tee acting as a foam generator. In another allar"dli~e, the foam isyel ,t:rdLed downhole by ~ g the gas and liquid ,c I .ases via a CGI ~ .,no, . tubing string or se,.,ardle tubing strings into the wellbore and passing tha two sl. eams through a downhole foam generator. A foam breaker and/or other materials known to those skilled in the art may be added to the foam or to the ~ 90115 20 sol~ ~tion.
The pH of the liquid phase in the polymer enhanced foam is generally within a range of about 4 to about 10. In most cases, the pH of the liquid phasei. ll .erenLl~r falls within the above-recited range without any pH adjustment thereof.
However, the pH of the liquid phase can be ~dj~ ~ste~ in any r..ar" .er known to the 25 skilled artisan in accorda~ .ce with conve, ILio. ,al oilfieid procedures to achieve a desired pH range. Nevertheless, it has been found that tha present prucess is relatively insensitive to the pH of the liquid phase.
In the practice of the present invention, the polymer enl .anced foam may be placed in a wellbore as either a co" ,~lelio, ~ fluid, a workover fluid, or a kill fluid.
30 Placeme, .~ of the foam is further facilitated by the relatively highly shear thinning properties of the polymer enhanced foam. The polymar en h t,nced foam exhibits relatively high effective viscosities under low shear co, I-JiliGl ,s at the surface and W O 97121018 PCT~US96/17460 in the relatively low shear regions within the wellbore where the foam is pl~ce~l The polymer e, Ihal ,ced foam, however, exhibits relatively low effective viscosil;es under the high flow rate and liigh shear rate conditions encol,nle,ed as it is pumped into the w~lluo~ due to the ability of the foam to highly shear thin. Thus, 6 the high shear thinning ability and the low friction loss qualities of the foam allow the foam to be pumped easily. Nevertheless, once the polymer e. ~l .a, Iced foamis successfully placed in the wellbore, it beneficially shear thickens, ll.er.~l~y achieving a s~rldenl degree of structure and a sufFicient critical pressure gradient for flow to limit invasion of the polymer enhanced foam into tha sul.ter-dnean 10 formation a~j~cent the wellbore.
Relative to convenlional polymer-free foams, the polymar e, ~ nced foam is highly stable over a wide range of temperatures, pressures, water salinities, and water hardnesses. The polymer enhanced foam also resists collarse and fluid ~JI din age in the presence of many envil Ul 111 lel .lal cc I ,la, . .i. Icll .ls. In particular, the 15 polymer enhanced foam is stable in the presence o~ liquid hyJI uca- 6GI IS, unlike most conventional foams. The foam can be self healing so that if foarn degradation occurs as equipment is moved through the foam, the foam is c~p~hl~
of re~l l l l;l lg itself. The polymer e, Ihance~l foam resists flow from the wellbore and does not sl Ihst~ntially invade the ~dj~cent rc,rl..~lio, .. If the for..-~tion is invaded, 20 the energized nature of the foam aids in its removal. If the pressure is red~ ~cerl the gas ~ ~hbles in the foam expand and push a s~ IhstP~ntial portion of the foam out of the rul..~ OI ~. When the foam eventually breal<s down, the 3as, su, ractal ,1, and polymer resulting from foam breakdown may ellhance fluid flow between the formation and the well. The gases, su-r~;la-~ls, and polymers of polymer enhanced foams are commonly used as elll,d"ce-~ or improved oil recovery agents. Nevertheless, if desired, a conventional breaker can be i. .,~ ~ed into the ~ ~t" ,e, It region of the wellbore and/or any invaded near-wellbore portion of the formation to degrade the foam or polymer in situ and reslu,e the wellbore and near-wellbore region of the for".~Lio-, to their original condition.
Polymer enhancement of the foam also advant~eo~sly increases the structural strength and critical pressure gradient for flow of the foam relative to conver~lio"al polymer-free foams. The term "strength" refers to the resisla"ce of W O 97/21018 PCT~US96/17460 a foam to deformation when pressure or force is ~pplie~ to the foam, and the ~ ilical pressure gradient for flow" is defined herein as the maximum pressure that can be arplie~l to the foam without foam flow.
In general the polymer e"l,~"ced foam of the p~set,l invention should 5 have a 5iyl~ir~cald~ degree of structure. The viscosi~y and degree of structure of the polymer enhanced foam formulated in the ma""er of the present invention are primarily functions of the polymer properties and the polymer co"ce, ~ liol 1. In general the viscosity and degree of structure of a polymer enl,a"eed foam containing an acrylamide polymer are increased by incr~as;.,g the polymer 10 concentration of the liquid phase. However a more cost-effective and often preferred means for achieving the same effect is to employ a higher molec~ r weight polymer or in some cases a polymer having a higher degree of hydrolysis at a relatively fixed polymer conce, Ill dli~l 1. Conversely a re~ Iction in viscosily and the degree of structure is achieved by using a lower mcle~ weight 15 polymer a lower polymer CGI ,ce"lralion or in some cases a polymer having a lower degree of hydrolysis. Thus the skilled practitioner can modify the viscosily and the degree of structure of the preser,l polymer e,ll,a"ced foam in the above~esu iL,ecl ~anner to correspond with the leakoff pole,llial of the region of the rO" ll~liol ~ adjace, It the wellbore in which the completion workover or kill fluid 20 is used.
As is a~ afenl from above the low leakoK ~,aracleri-;lics of the polymer enhat,cecl foam are a function of its critical pressure gradient for flowl which can alternatively be termed yield pressure. The critical pressure gradient for flow is defined herein as the maximum pressure under specified conditions that can be 25 ~pplied to the foam without foam flow. ~he foam should exhibit a critical pressure gradient for foam flow higher than the pressure gradient across the wellbore face or existing in the near-wellbore region. By satisfying this criterion the ~oam will not flow into or through the rOI " ~alion adjace, ll the wellbore. Be~ Ise the polymer enhanced foam of the present invention has a relatively high critical pressure 30 gradient for foam flow particularly in co"~,va,iso" to conventional foams the polymer enl ,anced foam also perForms well as a low leakoff fluid.
,.,),bodi,.,enls of the ~u, esenl process have been cJes~ iL ed above wherein the polymer enl ,a"ced foam is ~ ,erdled prior to or durin~ placer, lenl of the foam in the wellbore. It is &ppalbl ,l to the skilled artisan from the instant ~isclQs~ ~re that there are numerous other related ap~licaliul~s within the scope of th~ ,~Jr~s~
5 invention.
The following examples demonstrate the p--actice and utility of the pres~"l invention, but are not to be construed as limiting the scope lhereor. In all of tlle ~xamples, foams are ge, lel ~led by co;. ,jecting a foam-formin~ s c ' ~fion and a ~as into a high permeability foam ~enerdlii,y sand pack. All e~eri,..ents are 10 cond~ ~ted at room te""~e, dlure unless otherwise noted. The foam forrns within about the first 2.5 cm of the sand pack and then advances through the rest of the sand pack. Thus, the foam generating sand pack may function as a foam ~ t,eraling device, as a model of a porous medium, or both simulla"eously. In each of the following examples, if a single sand pack is ! ~tili7ed, it ~,~, ru""s both 15 functions, and if two sand packs are ~Jti~ the first sand pack is for foam ~eneration and the seco"d is a test sand pack serving as a model of a porous medium. Foam properties, such as averagea~ are"tviscosity, are determined from data obtained for the foam in the sand pack, based on the entire length of the sand pac~ r, upel lies of bulk foam sa,) ,ples are similar to those observed in sand 20 packs.
Polymer enhanced foam stability in ylassware Conve, .licll ,al and polymer enhanced foams are ~repareJ to c~r,.~ar~ their 2~ stability and, in particular, their resistance to physical foam collars~ and water drainago under the influence of ~ravity. One of the convenli~l .al foams and thepolymer enhanced foam are s~ Ihst~ntially identical in composition except for the presence of an unhydrolyzed polyacrylamide at a COI ,cenll aliul, of 7,000 ppm in the ~ql leO! IS phase of the polymer enhanced foam. The molec~ weight of the 30 polymer is 11,000,000. The liquid phase of both foams is made up of a fresh water solvent containing 1,000 ppm of an ethoxylated sulfate SUI r~ctal ,l marketed co""~erc;ally as Enordet 121 5-3S by Shell Che, nic ~' Co., El ,I I~, Iced OR Recovery W O 97/21018 PCTrUS96/17460 Chemicals P. O. Box 2463 Houston Texas 77001. The su,racla.,l has the formula C12 ~EO3-SO4Na. A secon~ con~ e nlio- ,al foam is ~re~arecl with the same solvent and 5 000 ppm of Enordet 1215-3S su,r~ t in the ~ eo~l-s phase.
The foam samples are ~~e"e~led by coinjecting the liquid phase and N2 gas 5 into a foam y~"era~i..g sand pack. The sand pack has a ~ermeabilily of 67 C~il~ 2S, a length of 30 cm and a diameter of 1.1 cm. All flooding is cond~ Ict~ at 170 kPa constant ~irr~rtu,lial pressure across the sand pack and ~..os~l,e-ic ~ach~lessure. The polymer e- ~ ,~"ce.:l foam propa~tPs at a frontal advance rateof 207 m/day and e~ iaS an average appare,)l effective viscosil~ within the sand10 pack of 89 cp while the first conventional foam ,~,rup~ les at a frontal advance rate of 8 23~ m/day and exhibits an average éi~ Jdl t~ effective viscosil~ of only 2 cp at the same dirrere~ ,lial pressure. Thus the polymer erll ,a. .ce~ foam has a sl ~I sl~- ,Lially larger effective viscosity than the co~"lerl.~, I convenlional foam.
A tO0 cm3 sample of each fine-textured foam is collec~ed as effluent from 15 the sand pack and placed in a slo,. ~Jered gr~d~ ~te" cylinder for aging at ambient ter"~ er~lure. The positions of the foamfwater and foamlair i"le,races in the ~r~ te~l cylinde,~ are measured as a function of time to .Jele"..ine th~ rates of water drainage and foam collapse respectively for each of the samples. ThQ
results are shown in Figures 1A and 1 B respectively. It is appare,.l therein that 20 the rates of water drainage and foam collapse are much ~"edler for the conventional polymer-free foam than the polymer ~,~I,al,ced foam. A 100 cm3 sample of the 5 000 ppm su,ra~Lant convel,lional foam is also obtained in the same manner. The results are highly co.~,par~ble to the conv~-lt-o"al foam sample with 1000 ppm s~lr~Lalll as shown in FIG. 1B. Thus this ~xample 25 shows that the polymer enhanced foam is more stable with respect to water drainage and foam collapse under the influence of gravity than the convei ,liGnal polymer-free foam.
Further inereasing the su, rccta"l conc~ ILI alion i~ ,~eases the :,lal,ilily ofthe conventional foam slightly but the effect is much smaller than the effect of30 adding polymer to the a~ eo~ ~c solution. This example demG"sl, ales that adding a relatively small amount of polymer to a conventional foam i"crbases the foam stability significantly more than adding zd~itional su~ ~tal ll. Thus significant cost W O 97~1018 PCT~US9611746Q
savin3s and improved p~lror",ance can be achieved by addin~ a polymer to a ham rather than il,c.easir,y the surfactant c~i3)celllldlio,l. The stability of a polymcr enhanced foam is often ~, ealer in a porous medium than in labor~lo~y glassware.
Rheometer viscosil~r A polymer en.l ,anced foam is prt:pare~J' in a foam y~"e, ~li"~ sand pack by combining N2 gas with a solution of a prod~ ~r~d reservoir brine cor~laining 7,000 ppm PHPA and 2,000 ppm of Stepa,)llo 20, a C,~,8 alpha olefin slJlfo~al~
surfactant marketed by Stepan Chemical Co., 22 Fr~n~ya Road, Northfield, Illinois 60093. The brine contains 5,800 ppm total dissolved solids and has principle co"~liluents in the following concenlralio.ls; 560 ppm Ca~, 160 ppm Mg~, 1,500 ppm Na~, 200 ppm ~, 2,200 ppm SOi2, and 1,400 Cl . The PHPA is 30 per cent hydrolyzed and has a molea ~l~r weight of 11,000,000, and the foam quality is 88 per cent as prorl~ ~ce~ The foam is aged for five minutes, and viscosily measu,~"e"ls are then made on the bulk foam in a Rl,eG.I,e~,ics RFS
,heo."eter using the steady shear-rate mode. Shear rates from 0.15 to 700 sec~' are st~ e~' The polymer enl ,anceJ foam is a shear-ll ,i", .i. ,9 fluid over the antir~
range of shear rates. The minimum measured viscosity is 250 cp, and the maximum viscosity is over 40,000 cp. The power-law viscosity values (r-,) are determined to be N = 0.24 and K = 13,000 cp over the linear range of data obtained, where rl = K(y~' and y is the shear rate in units of sec~'. The rssults are shown in FIG. 2, with the power law curve fit shown as a solid line. The polymer e, ll lal~C6~.l foam e,d ~ ils s~ ~l .S~A. ,lial shear-ll ~i, u lil "J ~riscOsil~ behavior, indicating that the foam would be relatively easy to pump into and through wellbore tubulars.
A conventional foam is also prepared without the su, ractanl, and it is so unstabie that is not readily feasible to obtain similar meas-~l eme. ~
This example shows that the bulk polymer e, Ih~ .ced foam is highly shear thinning and that very large effective viscssilies can bo attained at low shsar rates. The rheological behavior of the bulk polymer enhanced foam is similar to that observed for the foam in porous media.
W O 97t21018 PCTrUS96/17460 Critical pressure ~ra.lie.1l for flow Polymer ~,II.ance~J and convenl;Gnal foams are ,~r~pal~ using Denver, Colorado, U.S.A., tap water, N2, 2,000 ppm in the ~ueo~ ~s phase of Bio-Ter~s 5 AS40, a C14-1G alpha olefin sulrO~ ,dLe SUI r~c~a. II obtained from Stepan Chemical CGr.,~,a"y, 22 FlunLage Road, Northfield, Illinois 60093 The polymer e(l~,a"c~d foam also contains 7,000 ppm in the ~q~ ~eous phase of 30 per c.ent hydrolyzed PHPA with a r~olec~ wei~ht of 11,000,000. The tap water co. .lai. .s 30 ppm ofC as C o;2, 78 ppm of Ca~, 18 ppm of Mg~, 130 ppm of Na~, 25 ppm of Cl, and 10 250 ppm of total dissolved solids. The critical pressure gradient for foam flow is det~.-"ined for the polymer enhanced foam in a sand pack having a ~J~I"~eabililyof 14Q darcies and a length of 30 cm. The sand pack is used in this case as a model of a porous medium. Flooding e~eri...e. .ls are cond~ lctP~ at ~IIG~I .eric l~ack,~r~ssure and at 3100 kPa backpressure for foam ~ ities L el~ on 57 and 15 93 per cent. The critical pressure gradient for foam flow of the polymer e. ~ ced foam is in the range of 452 to 678 kPa/m. The c.ritic.al pressure ~radient for foam nOwr for a conve- I~io. .al foam having the same com~ ioi - but without the polymer is 136 to 158 kPafm. The higher critical pressure ~ddi~lll of the polymer e. 11 .ance-J foam indicates that the polymer enhanced foam has signir,ca, .lly more 2û structure and less leakoff tendency than the conventional foam.
The critical pressure gradient for foam flow is also ~ete,.,li"ed for the polymer e nha~ d foam flowing through a 1.45 mm ID tube. The tube is used as a model of narrow tubing. The critical pressure gradient for flow is less than 2kPa/m, i. .~ that the foam has a l~e~ligiL,le yield ~ n~JU I and yield pressure 25 as it p~ses through the tube. Thus, the foam should flow readily through wsllbore tubulars and be easy to pump through well tubulars.
This example illustrates that the polymer enhanced foam of the present invention has a greater critical dirrerel ,lial pressure ~radient for foam flow, yield pressure, yield strength, and structure than its cou.~l6r,~.a~l conv~,~l;G"al foam.
30 ~hus, the polymer el Ihanced ~oam has better leakoff ~ro~,el lies than convef ~liGnal foams. Moreover, the polymer enhanced foam has a ne~ ihle yield s~ ~n~tt, and yield pressure as it flows through pipes and tubulars.
W O 97/21018 PCTrUS96/17460 Viscosity as function of foam quality A sample of a polymer e, II,a.lced foam and a sample of a conve. IliG-~I
polymer-free foam that is s~hstPrltially id~l.Lioal in coi-,posi(io,. to the polymer 5 1~1 Ihdl ~ced foam except for the absel .ce of a polymer CO-"~JO~ .e, .L are 5,r~par~J to cor."Jal-~ the effective viscoQities of the two foams as a function of foam quality.
Both foams are formulated from N2 and a brine solvent having a C,4 ~8 alpha olefin sulro, .~le sL-, rac~, .~ dissolved therein at a ~ncenlraliG- ~ of 2,000 ppm. Th~ brine contains 5,800 ppm total dissolved solids and has p.i-,oiple co..:,lil.Jents in ~e following oGI~ce"~lio"s. 560 ppm Ca~, 160 ppm Mg~, 1,500 ppm Na~, 2Q0 ppm ~~, 2,200 ppm SOj2, and 1,400 ppm Cl~. The ~ eo~s phase of the polymer enhanced foam ~d~;tionally con~ai"s a partially hydrolyzed polyacryla,l.id~ at aconcentration of 7,000 ppm. The partially hydrolyzed polyacrylamide has a molea ~ r wei~ht of 11,000,000 and is 30% hydrolyzed.
A sand pack s~ sl~.nlially the same as that of Example 2 is noo-J~d with each foam over a range of foam t~ ties A first polymer enl ,anced foam sample is flooded at a backpressure of 1,725 kPa and a dirr~re"lial pressure o~ 345 kPa.
The first sa, nple pl ~ g~le5 at an ~,u~ ent frontal advance rate of between about 158-198 m/day. A second polymer elll,anced foam ssmple is flooded at a backpressure of 3,100 kPa and a differential pressure of 345 kPa, and the a~ucrel ~l frontal advance rate is between 146 and 213 m/day. The conve, .I,~,lal foam sample is floo~e~l at ~llllospl ,eric backpressure and a ~lirrere"lial pressure of 138 kPa and pru~u~g~lPs at a frontal advance rats between about 335 and 1,463 m/day.
The results are set forth in FIG. 3 and indicate that the sensitivity of the average appar~nl viscosi~ of the polymer e nl~a~ ,ced foam to foam quality is much less than that for the counterpart conventional foam. Ful ll ,e,-nore, the effective viscosily of the polymer enl ~ance~J foam at any ~iven foam quality is much 5,~ ~ater than that of the conve~ Gl ,al foam. In FIG. 3, UPEF refers to polymer ~ Iced foam, and UBP~ refers to backpressure.
W O 97/21018 PCTrUS96/17460 EXAMPLE ~
Frontal advance rate of polymer ~ u hance~l foam and polymer solution A polymer enh al Iced solutTon is prepare-l, also using a reservoir brine and the same su.ra~ant and polymer as in Exd---~les 3 and 4. The s~' ltion CGllt~;i.lS
5 2,000 ppm sl~ r~l ll and 7,000 ppm of PHP~ A p~ n of the sol~ Ition and then . IoU ,er portion of the solution and N2 ~as are i- ~,e_~e~ into a 170 darcy sand pack at atmospheric back~ressure and ~o C, with a c~ nl pressure drop between 138 and 1,380 kPa. The sand pack is 30 cm long and has an inner dia...etdr of 1.1 cm. The resulting foam qualities range from 77 to 89 per cent.
FIG. 4 shows the appdl el l~ average effective viscosity (AAE) of the ~ eol ~s polymer solution and polymer en~, nced ~oams as a function of the a,u~are,lt frontal advance rate. The polymer enhanced foam is a shear U ,inn;.~ fluid, and the viscosily behavlor ~. Irurll~s to the power-law model over the range o~ frontal advance rates and shear rates st~ ied The viscosity and shear thinnin 15 ~Jru~uel lies of the polymer enhanced foam mirror the viscosily and shear thinnin~
,uropel lies of the polymer solution. Further, the viscosity of the polymer e(ll ,anced foam is very similar to the viscosil~r of the polymer ssl~ ~tion. Thus, the quantity of polymer can be siyniricanlly rerl~ced by usin~ a foam rather than a polymer sol ~tion, resulting in similar rheological pe, ron~.ance with a si5;~. .irlcanl Jecf~ase 20 in the cost of the polymer and polymer SO~ ion used in a completion, workover, or kill operation.
Effects of pressure on frontal advance rate and effective viscosity Polymer e.ll,anced foams are p.e,uared using a sol~tion of 2,00û ppm 25 s~u r;a~ nl and 7,000 ppm of Pl IPA with a moleu -l~r weight of 11 ,û00,000 in a reservoir brine and using N2 as the ~as phase. The brine, s~ ractar,l, and polymer sre the same as those used in Example 4. The foam ~ lities range from 81 to 89 per cent. One set of foams is formed by injecting the polymerlsl"r~,tanl solution and the gas directly into a 120 darcy test sand pack at 22~ C and 30 atmospheric backpressure. The sand pack is 30 cm long and has an inner dia" ,eter of 1.0 cm. The sand pack functions as a foam ~e- ~er;dlin~ device and a model of a porous medium. The second flood is pl~rorl"ed in a 120 darcy foam W O 97/21018 PCT~US96/17460 ~ene.~lin~ sand pack and then i" e~ted into a 120 darcy test sand pack at 3 450 kPa injection pressure and 22~ C.
FIG. 5 shows the average apparent effective viscosil~ as a function of the a~",are, ll frontal advance rate for the in-situ~el ,eraled foarn and ~e ~,r~fu. ..-ed foam. The high pressure data shown in FIG. 5 are co"",aral~le to the atn~ospl .e~ic pressure data of E~a---tule 5 which ars FLtte~ as trian~les. These data and the data shown in FIG. 4 (Example 5) in~icale that the appar~,-l visc~si~;es of the polymar enl~a~.ced foams are nearly inde~uer,- e,~t of pressure. Ah-iiti~"ally it is shown that ve~ iar~e effective visc~;lies can be allai- .eJ at low shear rates, anci the rheological ~,r~.pelLies of preror",ed and in-situ~el-er~ed foams are nearlyide- ~lical.
Effect o~ te."~er~lure on foam sldl,ili4 A polymer en h a"ced foam is p.~par~d usin~ the reservoir brine containin~
2,000 ppm of s~Oracta.lt 7 000 ppm of PHPA with a moleo~ w~ight of 11 000 000 and N2. The sl~l rdclanl~ polymer and brine are the same as those used in Example 4. The polymer enhanced foam is ~e"e-~led in a 170 darcy foam yel ,er~ sand pack at an ap~.arenl frontal advance rat~ of about 1 524 m/day.
The sand pack has a length of 30 cm and a dia."eter of t.1 cm and the experiment is cond~cte~l at 22~C and ~r~e~le~ at 51~ C. 100 ml of each foam e~uent is colle~J in a sl,J~,pered gr~d~ e~ cylinder and aged at 22~ C and 51~
C respectiYely. The foam volumes are observed durin~ the next 24 hours and the results are shown in Table 1. I~ asi"g th~ temperature from 22 to 51~ C has no significant effect on the stability of the polymer ~-ll Idl ~c~3d foam for the first seven hours of aging. In ~d~lition the polymer e ul ,a, .ced foam shows superiorstability to that of a convenl;o"al foam at 51~ C.
As noted during the noodi"g e~e~ e~ the e~ective Yi300-';ity of the foam decreases as the temperature i"creases. At each temperaturo the effective viscosity of the polymer enl ,anced foam is proportional to the effectivQ viscosil~
of the poly T er sol~ Ition alone which is inversely ~ro,uo, lio- Ial to the te."~er~l~re.
Table I
Aging Time (hr) Foam Volume (cm3) Foam Volume (cm3) 22~ C 51~C
0.25 100. 100.
1.0 100. 100.
2.0 97. 98.
3.0 94. 94.
4.0 92.~ 91.
5.0 89.~ 89.
7.0 87.~ 88.
24.0 85.~ 58.
Fragile and light foam ~ Extremely fragile and coarse foam Effect of polymer conca"~ dl;GI .
Polymer e~ Ih~ .ced foams are ~,repared with an ~ eo~ ~s phase CG~ Isistin~
of 2 000 ppm of an alpha olefin sulro, ~a~e surfactant a rsservoir brine, and PHPA
conce, ~llaliotls of 1,500; 2,500; 3,500; 5,000; and 7,000 ppm, and with N2 as the 20 gas phase. The brine s~"ac~a"l and PHPA are the sama as those of Example 4. The polymer sol~tion viscosilies are 50, 280, 800 3,300 and 4,800 cp, n3sre~i-/ely at a shear rate of 1.0 sec '. The foams are ~el ,erale~i in a 140 darcy sand pack with a pressure drop of 138-1,380 kPa and a frontal advance rate of 61-3,048 m/day. The sand pack serves both foam ye. ~erali"~ and test f~. IctiGns and 25 has a length of 30 cm and a clia",eler of 1.1 crn. The foam ~ ties ran~e between 85 and 89 per cent. As shown in FIG. 6 siy,~irica,lt viscosities ara observed for all polymer conce"l,alions sh~ied and the average efFective viscosil~ is propGI lional to the poiymer concentration.
W O 97~1018 PCT~JS96/17460 Effect of SL" raulanl co. ,c~ (dliol -Polymer e. Il ~a~ .ced foams sre ~re~ar~d usin3 a reservoir brine containing 7,000 ppm of 30 % hydrolyzed PHPA havin~ a mole~ ~'~~ weight of 11,000,000 5 and s~ raclal ll CGI Icel ll- d~iOI IS of 250 ppm; 500 ppm; 1,000 ppm; and 2,000 ppm.
The brine, Sl~ td~ (alpha olefin sulrGI ,~le, or AOS), and polymer are the same as those used in Exa",~.~le 4. The foams are ~e.-eraleJ with N2 in a 140 darc~r foam ~ .er~li"~ and test sand pack with a pressure drop of 138-1,380 kPa, and the foam t~ es are between 85 and 89 per cent. The sand pack is 30 crn lon~
10 and has an inner diar"eter of 1.1 cm. As shown in FIG. 7, the slJ-ra~at~l concentration has little or no effect on polymer ~ li ~a- ~ced foam vis~os;4 over a broad rango of su, r~clai ~l concei ~l dUons. Thus, by using a poiymer ~ .a.,c6dfoam completion, workover, or kill fluid, the co. ,ce. ~ lio- I of s~,. ~ola. ,l in thQ foam can be kept relatively low without d~ asi- ~y the viscosil~ or cha, .yil ~~ the foam's 15 I ho ~ properties, U .er~b~ reducing the cost of the completion, workover, or kill operalio~.
Effect of ~as CO..,pO5:'iol.
Polymer erll Idl ICed foams are prepared using 7,000 ppm PHPA and 2,000 ppm Bio-Terge AS40 su. rac~ t in a reservoir brine and with dirrere, .l ~ases. The brine, surfactant, and PHPA are the same as those used in EXdlllpi~ 4. The solution pH is 7.5. Foam qualities range between 85 and 90 per cent with Nz, 85 and 89 per cent with CH4, and 87 and 89 per cent with CO2. Frontal advance rates ar~ observed in a 150 darcy sand pack with a pressure drop betw~e. . 207 and 1,380 kPa. The polymer er,l .anced foam ~e. rGrl l~tillC85 are very similar with all three gases, as shown in FIG. 8. In particular, the acidity of the CO2 fosm had no si~, .ii,canl effect on the polymer enhanced foam viscosily ~.e, rO, illdl ICe. Thus, almost any available gas can be lltjii7Pd as a fOdlilillsJ agent in the completion, worl<over, or kili fluid, and the rheoiogical pe~ror-..dn~ of ths poiymer ~lhanced 30 foam appea(s to be insensitive to the gas c~..~l ~osil~on ~ ~t~
WO 97nlO18 PCTAJS96/17460 Effect of brine comrosition Four polymer e, Ih dl ICe'l foams are formulated with 30 per cent hydrolyzed PHPA and unhydrolyzed PA, both having molecular u~ei~hls of 11,000,000, and 5 with fresh water and brine. The brine contains 5,700 ppm total dissolved solids, with high conce, llraliol ,s of Ca2~, Mg2~, and so~2-. The polymer c~ncenl, dLil~l . in the a~ eo~s phase is 7,000 ppm, the s~"racta"l is Bio-Terge AS~0 at a co"cenl~lion of 2,000 ppm in the A~l l7~70l IS phase, and the gas is N2. Foams are rc~""ed in afoam ~~e"e,~li,)g sand pack as described above. As shown in FIG. 9, 10 for any given a~ 7~dl ~1 IL frontal advance rate, the effective viscosity of each polymer enhanced foam is propotional to the viscosity of the ~9~ ~eo~ ~s polymer solution from which it was fo,med. As P~rect,q~ for poiyacrylamides due to hydrolysis andsalinity interactions, the viscosities of polymer solutions with higher salinity are less than the visco~ilie~ of fresh water sol~ ~tions whlch contain the same polymer 15 cc"ce"Lra~ion. When the brine and fresh water polymer sol ~tions have approximately the same viscosity, the polymer el Ih~ ,ced foams yel ,eraled withthose solutions also have similar viscosities. The percent of hydrolysis of the polymer has the same effect on the rheology of the polymer solution and the polymer enhanced foam, with greater effective viscosities for otherwise identi, al 20 polymer solutions and polymer enhanced foams co, .taining polymers with higher levels of hydrolysis.
Effect of polymer molecular weight Polymer e, Ih a. Iced foams are ,~ par~d in a foam generating sand pack as 25 described above, using N2; 2,000 ppm of E3io-Terge AS40 sulrdctalll in the ~ql ~eo~ ~s phase (UAQ. SOLN.~); and unhydrolyzed polyac;ylamide conc~nll dlionsin the ~q~ ~eous phase and mol~ r V/ei~ S as shown in FIG. 10. Increasing the polymer 1ll07.2a ll~r weight increases the viscosity of the polymer solution and the polymer enhanced foam formed from the sol~ on. Further, the viscosily of the 30 aqueous phase from which the polymer enhanced foam is ror",ed controls the effective viscosity of the polymer enhanced foam. Thus, the same viscosity pe, rur",a~ ,ce can be achieved for a given polymer enhanced foam by increasing .
the polymer molea li~r weight and using less polymer in the ham resulting in siyl ,i~c~, .l cost savings.
Effect of pH
Two brine ssl-~tions are prepared havin~ 11000000 r.,-le~ wsi~ht PHPA co"cel,Ir~Iions of 7 000 ppm and Bio-Terge AS40 sL"rdc~nt concenlr;;lIions of 2 000 ppm. The brine is the same as that used in Example 11 and the PHPA is the same as that used in Exam~,le 4. The pH of one solution is adjusted to 7.5 and the pH of tha other is adjusted to 10. Polymer enl,a"ced foams are forrned with Nz in a 30 crn long combined foam y&l,~rc.liny and test sand pack having a permeability of 150 darcies. AI"los~l,erlc L,a~,uressure is maintained with a pressure drop across the sand pack of 138-1 380 kPa. As shown in F~G. 11 the average effective viscosity and rheological ~e, ru, ~-)an~3 of these polymer enh~nced foams are essentially i, ~de,t,endent of the pH ovsr the range stl~died While the foregoing ,~,rt:rel,ed e"~odi,-~ents of the invention havs been described and shown it is ul~.Jeral~od that alternatives and ",o~ ns such as those suggesIed and others may be made U ,er~to and fall within the scope of the present invention.
7.0 87.~ 88.
24.0 85.~ 58.
Fragile and light foam ~ Extremely fragile and coarse foam Effect of polymer conca"~ dl;GI .
Polymer e~ Ih~ .ced foams are ~,repared with an ~ eo~ ~s phase CG~ Isistin~
of 2 000 ppm of an alpha olefin sulro, ~a~e surfactant a rsservoir brine, and PHPA
conce, ~llaliotls of 1,500; 2,500; 3,500; 5,000; and 7,000 ppm, and with N2 as the 20 gas phase. The brine s~"ac~a"l and PHPA are the sama as those of Example 4. The polymer sol~tion viscosilies are 50, 280, 800 3,300 and 4,800 cp, n3sre~i-/ely at a shear rate of 1.0 sec '. The foams are ~el ,erale~i in a 140 darcy sand pack with a pressure drop of 138-1,380 kPa and a frontal advance rate of 61-3,048 m/day. The sand pack serves both foam ye. ~erali"~ and test f~. IctiGns and 25 has a length of 30 cm and a clia",eler of 1.1 crn. The foam ~ ties ran~e between 85 and 89 per cent. As shown in FIG. 6 siy,~irica,lt viscosities ara observed for all polymer conce"l,alions sh~ied and the average efFective viscosil~ is propGI lional to the poiymer concentration.
W O 97~1018 PCT~JS96/17460 Effect of SL" raulanl co. ,c~ (dliol -Polymer e. Il ~a~ .ced foams sre ~re~ar~d usin3 a reservoir brine containing 7,000 ppm of 30 % hydrolyzed PHPA havin~ a mole~ ~'~~ weight of 11,000,000 5 and s~ raclal ll CGI Icel ll- d~iOI IS of 250 ppm; 500 ppm; 1,000 ppm; and 2,000 ppm.
The brine, Sl~ td~ (alpha olefin sulrGI ,~le, or AOS), and polymer are the same as those used in Exa",~.~le 4. The foams are ~e.-eraleJ with N2 in a 140 darc~r foam ~ .er~li"~ and test sand pack with a pressure drop of 138-1,380 kPa, and the foam t~ es are between 85 and 89 per cent. The sand pack is 30 crn lon~
10 and has an inner diar"eter of 1.1 cm. As shown in FIG. 7, the slJ-ra~at~l concentration has little or no effect on polymer ~ li ~a- ~ced foam vis~os;4 over a broad rango of su, r~clai ~l concei ~l dUons. Thus, by using a poiymer ~ .a.,c6dfoam completion, workover, or kill fluid, the co. ,ce. ~ lio- I of s~,. ~ola. ,l in thQ foam can be kept relatively low without d~ asi- ~y the viscosil~ or cha, .yil ~~ the foam's 15 I ho ~ properties, U .er~b~ reducing the cost of the completion, workover, or kill operalio~.
Effect of ~as CO..,pO5:'iol.
Polymer erll Idl ICed foams are prepared using 7,000 ppm PHPA and 2,000 ppm Bio-Terge AS40 su. rac~ t in a reservoir brine and with dirrere, .l ~ases. The brine, surfactant, and PHPA are the same as those used in EXdlllpi~ 4. The solution pH is 7.5. Foam qualities range between 85 and 90 per cent with Nz, 85 and 89 per cent with CH4, and 87 and 89 per cent with CO2. Frontal advance rates ar~ observed in a 150 darcy sand pack with a pressure drop betw~e. . 207 and 1,380 kPa. The polymer er,l .anced foam ~e. rGrl l~tillC85 are very similar with all three gases, as shown in FIG. 8. In particular, the acidity of the CO2 fosm had no si~, .ii,canl effect on the polymer enhanced foam viscosily ~.e, rO, illdl ICe. Thus, almost any available gas can be lltjii7Pd as a fOdlilillsJ agent in the completion, worl<over, or kili fluid, and the rheoiogical pe~ror-..dn~ of ths poiymer ~lhanced 30 foam appea(s to be insensitive to the gas c~..~l ~osil~on ~ ~t~
WO 97nlO18 PCTAJS96/17460 Effect of brine comrosition Four polymer e, Ih dl ICe'l foams are formulated with 30 per cent hydrolyzed PHPA and unhydrolyzed PA, both having molecular u~ei~hls of 11,000,000, and 5 with fresh water and brine. The brine contains 5,700 ppm total dissolved solids, with high conce, llraliol ,s of Ca2~, Mg2~, and so~2-. The polymer c~ncenl, dLil~l . in the a~ eo~s phase is 7,000 ppm, the s~"racta"l is Bio-Terge AS~0 at a co"cenl~lion of 2,000 ppm in the A~l l7~70l IS phase, and the gas is N2. Foams are rc~""ed in afoam ~~e"e,~li,)g sand pack as described above. As shown in FIG. 9, 10 for any given a~ 7~dl ~1 IL frontal advance rate, the effective viscosity of each polymer enhanced foam is propotional to the viscosity of the ~9~ ~eo~ ~s polymer solution from which it was fo,med. As P~rect,q~ for poiyacrylamides due to hydrolysis andsalinity interactions, the viscosities of polymer solutions with higher salinity are less than the visco~ilie~ of fresh water sol~ ~tions whlch contain the same polymer 15 cc"ce"Lra~ion. When the brine and fresh water polymer sol ~tions have approximately the same viscosity, the polymer el Ih~ ,ced foams yel ,eraled withthose solutions also have similar viscosities. The percent of hydrolysis of the polymer has the same effect on the rheology of the polymer solution and the polymer enhanced foam, with greater effective viscosities for otherwise identi, al 20 polymer solutions and polymer enhanced foams co, .taining polymers with higher levels of hydrolysis.
Effect of polymer molecular weight Polymer e, Ih a. Iced foams are ,~ par~d in a foam generating sand pack as 25 described above, using N2; 2,000 ppm of E3io-Terge AS40 sulrdctalll in the ~ql ~eo~ ~s phase (UAQ. SOLN.~); and unhydrolyzed polyac;ylamide conc~nll dlionsin the ~q~ ~eous phase and mol~ r V/ei~ S as shown in FIG. 10. Increasing the polymer 1ll07.2a ll~r weight increases the viscosity of the polymer solution and the polymer enhanced foam formed from the sol~ on. Further, the viscosily of the 30 aqueous phase from which the polymer enhanced foam is ror",ed controls the effective viscosity of the polymer enhanced foam. Thus, the same viscosity pe, rur",a~ ,ce can be achieved for a given polymer enhanced foam by increasing .
the polymer molea li~r weight and using less polymer in the ham resulting in siyl ,i~c~, .l cost savings.
Effect of pH
Two brine ssl-~tions are prepared havin~ 11000000 r.,-le~ wsi~ht PHPA co"cel,Ir~Iions of 7 000 ppm and Bio-Terge AS40 sL"rdc~nt concenlr;;lIions of 2 000 ppm. The brine is the same as that used in Example 11 and the PHPA is the same as that used in Exam~,le 4. The pH of one solution is adjusted to 7.5 and the pH of tha other is adjusted to 10. Polymer enl,a"ced foams are forrned with Nz in a 30 crn long combined foam y&l,~rc.liny and test sand pack having a permeability of 150 darcies. AI"los~l,erlc L,a~,uressure is maintained with a pressure drop across the sand pack of 138-1 380 kPa. As shown in F~G. 11 the average effective viscosity and rheological ~e, ru, ~-)an~3 of these polymer enh~nced foams are essentially i, ~de,t,endent of the pH ovsr the range stl~died While the foregoing ,~,rt:rel,ed e"~odi,-~ents of the invention havs been described and shown it is ul~.Jeral~od that alternatives and ",o~ ns such as those suggesIed and others may be made U ,er~to and fall within the scope of the present invention.
Claims (34)
1. A process for use during hydrocarbon well completion workover, and kill operations the process comprising the steps of:
(a) preparing an aqueous solution of a water-soluble substantially noncrosslinked polymer and a water-soluble surfactant the aqueous solution being substantially free of agents capable of crosslinking the polymer; and (b) adding a gas to said aqueous solution so as to form a polymer enhanced foam; and (c) placing said foam in a well penetrating a subterranean formation during a completion workover or kill operation.
(a) preparing an aqueous solution of a water-soluble substantially noncrosslinked polymer and a water-soluble surfactant the aqueous solution being substantially free of agents capable of crosslinking the polymer; and (b) adding a gas to said aqueous solution so as to form a polymer enhanced foam; and (c) placing said foam in a well penetrating a subterranean formation during a completion workover or kill operation.
2. The process of claim 1 wherein said gas is added to said solution prior to placing said solution in said well.
3. The process of claim 1 wherein said gas is added to said solution as said solution is placed in said well.
4. The process of claim 1 wherein said gas is added to said solution within said well.
5. The process of claim 1 wherein said foam is a well completion fluid.
6. The process of claim 1 wherein said foam is a workover fluid.
7. The process of claim 1 wherein said foam is a kill fluid.
8. The process of claim 1 wherein said process additionally comprises the step of adjusting the pH of said aqueous solution to a value between about 4and about 10.
9. The process of claim 1 additionally comprising the step of mixing a foam breaker with said foam.
10. The process of claim 1 wherein said formation is hydrocarbon bearing.
11. The process of claim 1 wherein said surfactant is selected from the group consisting of ethoxylated alcohols, ethoxylated sulfates refined sulfonates, petroleum sulfonates, alpha olefin sulfonates, and mixtures thereof.
12. The process of claim 1 wherein said surfactant is present in an amount between about 20 ppm and 50,000 ppm of said solution.
13. The process of claim 1 wherein said surfactant is present in and amount between about 50 ppm and 20,000 ppm of said solution.
14. The process of claim 1 wherein said surfactant is present in an amount between about 1,000 ppm and 20,000 ppm of said solution.
15. The process of claim 1 wherein said gas is selected from the group consisting of nitrogen, air, carbon dioxide, flue gas, produced gas, natural gas, and mixtures thereof.
16. The process of claim 1 wherein said gas is selected from the group consisting of nitrogen, carbon dioxide, and mixtures thereof.
17. The process of claim 1 wherein said foam has a gas content between about 20 per cent and about 99 per cent by volume.
18. The process of claim 1 wherein said foam has a gas content between about 60 per cent and about 98 per cent by volume.
19. The process of claim 1 wherein said foam has a gas content between about 70 per cent and about 97 per cent by volume.
20. The process of claim 1 wherein said polymer is selected from the group consisting of biopolymers, acrylamide polymers, and mixtures thereof.
21. The process of claim 20 wherein said biopolymers are selected from the group consisting of xanthan gum, guar gum, succinoglycan, scleroglycan, polyvinylsaccharides, carboxymethylcellulose, o-carboxychitosans, hydroxyethylcellulose, hydroxypropylcellulose, modified starches, and mixtures thereof.
22. The process of claim 20 wherein said acrylamide polymer is selected from the group consisting of polyacrylamide; partially hydrolyzed polyacrylamide;
acrylamide copolymers; acrylamide terpolymers containing acrylamide, a second species, and a third species; tetrapolymers containing acrylamide, acrylate, a third species and a fourth species; and mixtures thereof.
acrylamide copolymers; acrylamide terpolymers containing acrylamide, a second species, and a third species; tetrapolymers containing acrylamide, acrylate, a third species and a fourth species; and mixtures thereof.
23. The process of claim 22 wherein said acrylamide polymer has a molecular weight between about 10,000 and about 50,000,000.
24. The process of claim 22 wherein said acrylamide polymer has a molecular weight between about 250,000 and about 20,000,000.
25. The process of claim 22 wherein said acrylamide polymer has a molecular weight between about 1,000,000 and about 18,000,000.
26. The process of claim 22 wherein said acrylamide polymer is present in said solution in an amount between about 100 ppm and about 80,000 ppm.
27. The process of claim 22 wherein said acrylamide polymer is present in said solution in an amount between about 500 ppm and about 12,000 ppm.
28. The process of claim 22 wherein said acrylamide polymer is present in said solution in an amount between about 2,000 ppm and about 10,000 ppm.
29. The process of claim 1 wherein said aqueous solution comprises a solvent selected from the group of fresh water and brine.
30. The process of claim 1 wherein said foam is stable in glassware at atmospheric pressure for at least about 6 hours.
31. The process of claim 1 wherein said foam is a shear thinning fluid.
32. The process of claim 1 wherein said foam is rehealable.
33. The process of claim 1 wherein said polymer enhanced foam is an emulsion.
34. All inventions described herein.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US08/568,869 US5706895A (en) | 1995-12-07 | 1995-12-07 | Polymer enhanced foam workover, completion, and kill fluids |
| US568,869 | 1995-12-07 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2234173A1 true CA2234173A1 (en) | 1997-06-12 |
Family
ID=24273058
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002234173A Abandoned CA2234173A1 (en) | 1995-12-07 | 1996-10-28 | Polymer enhanced foam workover, completion, and kill fluids |
Country Status (7)
| Country | Link |
|---|---|
| US (1) | US5706895A (en) |
| AU (1) | AU7601096A (en) |
| CA (1) | CA2234173A1 (en) |
| GB (1) | GB2322892B (en) |
| MX (1) | MX9803724A (en) |
| NO (1) | NO982600D0 (en) |
| WO (1) | WO1997021018A1 (en) |
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| EP1180130A1 (en) | 1999-05-26 | 2002-02-20 | The Procter & Gamble Company | Liquid detergent compositions comprising polymeric suds enhancers |
| US7241729B2 (en) * | 1999-05-26 | 2007-07-10 | Rhodia Inc. | Compositions and methods for using polymeric suds enhancers |
| US6649571B1 (en) | 2000-04-04 | 2003-11-18 | Masi Technologies, L.L.C. | Method of generating gas bubbles in oleaginous liquids |
| US6376631B1 (en) | 2000-09-27 | 2002-04-23 | Rhodia, Inc. | Processes to control the residual monomer level of copolymers of tertiary amino monomer with a vinyl-functional monomer |
| US6800592B2 (en) * | 2001-08-28 | 2004-10-05 | Intevep, S.A. | Polymer-enhanced foamable drilling fluid |
| JP2003159026A (en) * | 2001-11-22 | 2003-06-03 | Ajinomoto Co Inc | Method for producing stable aspartame slurry and judging method |
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| US6739414B2 (en) | 2002-04-30 | 2004-05-25 | Masi Technologies, L.L.C. | Compositions and methods for sealing formations |
| US7199083B2 (en) * | 2002-12-06 | 2007-04-03 | Self Generating Foam Incoporated | Self-generating foamed drilling fluids |
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| US8065905B2 (en) | 2007-06-22 | 2011-11-29 | Clearwater International, Llc | Composition and method for pipeline conditioning and freezing point suppression |
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| US11447687B2 (en) * | 2020-09-29 | 2022-09-20 | Saudi Arabian Oil Company | Enhancing rheological properties of foam using aloe-barbadensis gel |
| CN112377164B (en) * | 2020-11-16 | 2022-06-28 | 东北石油大学 | Foaming mechanism, high-energy gas foam fracturing device and process |
| CN113004878A (en) * | 2021-03-23 | 2021-06-22 | 四川省贝特石油技术有限公司 | Leakage-proof leakage-stopping type micro-foam drilling and repairing liquid as well as preparation method and application thereof |
| US11673010B2 (en) | 2021-05-14 | 2023-06-13 | Tyco Fire Products Lp | Fire-fighting foam concentrate |
| US11673011B2 (en) | 2021-05-14 | 2023-06-13 | Tyco Fire Products Lp | Firefighting foam composition |
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| CA3218574A1 (en) | 2021-05-14 | 2022-11-17 | Joanna M. Monfils | Fire-fighting foam concentrate |
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| EP4337340A1 (en) | 2021-05-14 | 2024-03-20 | Tyco Fire Products LP | Fire-fighting foam concentrate |
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| US5358046A (en) * | 1993-01-07 | 1994-10-25 | Marathon Oil Company | Oil recovery process utilizing a supercritical carbon dioxide emulsion |
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-
1995
- 1995-12-07 US US08/568,869 patent/US5706895A/en not_active Expired - Fee Related
-
1996
- 1996-10-28 WO PCT/US1996/017460 patent/WO1997021018A1/en active Application Filing
- 1996-10-28 AU AU76010/96A patent/AU7601096A/en not_active Abandoned
- 1996-10-28 CA CA002234173A patent/CA2234173A1/en not_active Abandoned
- 1996-10-28 GB GB9811191A patent/GB2322892B/en not_active Expired - Fee Related
-
1998
- 1998-05-11 MX MX9803724A patent/MX9803724A/en unknown
- 1998-06-05 NO NO982600A patent/NO982600D0/en not_active Application Discontinuation
Also Published As
| Publication number | Publication date |
|---|---|
| MX9803724A (en) | 1998-09-30 |
| WO1997021018A1 (en) | 1997-06-12 |
| GB2322892B (en) | 1999-09-01 |
| AU7601096A (en) | 1997-06-27 |
| NO982600L (en) | 1998-06-05 |
| GB9811191D0 (en) | 1998-07-22 |
| GB2322892A (en) | 1998-09-09 |
| US5706895A (en) | 1998-01-13 |
| NO982600D0 (en) | 1998-06-05 |
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