CA2062395A1 - Sand consolidation methods - Google Patents
Sand consolidation methodsInfo
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- CA2062395A1 CA2062395A1 CA002062395A CA2062395A CA2062395A1 CA 2062395 A1 CA2062395 A1 CA 2062395A1 CA 002062395 A CA002062395 A CA 002062395A CA 2062395 A CA2062395 A CA 2062395A CA 2062395 A1 CA2062395 A1 CA 2062395A1
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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
- C09K8/56—Compositions for consolidating loose sand or the like around wells without excessively decreasing the permeability thereof
- C09K8/57—Compositions based on water or polar solvents
- C09K8/575—Compositions based on water or polar solvents containing organic compounds
- C09K8/5751—Macromolecular compounds
- C09K8/5755—Macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
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Abstract
SAND CONSOLIDATION METHODS
(D#91,007-F) ABSTRACT OF THE DISCLOSURE
Disclosed are methods for consolidating unconsolidated mineral particles such as sand in a subterranean petroleum formation penetrated by a well.
A fluid containing a polymerizable resin such as furfuryl alcohol, a polar organic diluent such as butyl aldehyde and an oil soluble acid catalyst such as toluenesulfonic acid capable of causing polymerization of the resin at formation temperatures is prepared.
The acid should have a pK in the range of 0.50 to 1.30 and the acid concentration is carefully selected to cause the polymerization reaction to be essentially complete in from 0.75 to 4.0 hours and preferably 1.0 - 2.0 hours at the formation temperature. Usually the selected acid concentration will be in the range of from 0.2 to 5.0 percent. This fluid is injected into the formation to saturate at least a portion of the formation adjacent to the well. An aqueous fluid comprising water which is from 70 to 100 % saturated inorganic salts including sodium chloride is injected into the same portion of the formation contacted by the resin containing fluid.
The injected fluids are allowed to remain in the formations for at least four hours to accomplish at least partial polymerization of the resin, forming a permeable consolidated mass around the wellbore.
(D#91,007-F) ABSTRACT OF THE DISCLOSURE
Disclosed are methods for consolidating unconsolidated mineral particles such as sand in a subterranean petroleum formation penetrated by a well.
A fluid containing a polymerizable resin such as furfuryl alcohol, a polar organic diluent such as butyl aldehyde and an oil soluble acid catalyst such as toluenesulfonic acid capable of causing polymerization of the resin at formation temperatures is prepared.
The acid should have a pK in the range of 0.50 to 1.30 and the acid concentration is carefully selected to cause the polymerization reaction to be essentially complete in from 0.75 to 4.0 hours and preferably 1.0 - 2.0 hours at the formation temperature. Usually the selected acid concentration will be in the range of from 0.2 to 5.0 percent. This fluid is injected into the formation to saturate at least a portion of the formation adjacent to the well. An aqueous fluid comprising water which is from 70 to 100 % saturated inorganic salts including sodium chloride is injected into the same portion of the formation contacted by the resin containing fluid.
The injected fluids are allowed to remain in the formations for at least four hours to accomplish at least partial polymerization of the resin, forming a permeable consolidated mass around the wellbore.
Description
2~39~
S~ND CONSOLIDATION ME~HODS
~D#91,007-F) REFERENCE TO COPENDING APPhICATIONB
This application is related to Pendiny Application Serial No. 07/459,604 filed January 2, 1990 for SAND
CONSOLIDATION METHODS.
FIEL~ OF THE INVENTION
This invention concerns a method for treating wells completed in subterranean formations containing unconsolidated particulate matter, e.g. unconsolidated sand, in order to bind the unconsolidated sand grains together in the portions of the formation immediately adjacent to the perforations of the well, and thereby form a stable yet still fluid permeable barrier around the wellbore, in order to facilitate production of fluids from the formation while restraining the movement of sand into the wellbore during the fluid production phase. More particularly, this invention pertains to a method for accomplishing sand consolidation i.n producing oil wells utlliziny the sand naturally present .in the formation and a method which utilizes a substantially reduced number of procedural steps, which reduces the time and cost of treating wells. Still more particularly, this invention comprises a method for selectively consolidatiny sand grains together in the formation adjacent to the inlet of a producing wellbore by use of single fluid 2~23~
containing the polymerizable resins with the catalyst already mixed with the resin in order to achieve more uniform mixing and to reduce the necessity of first cleaning the sand grains, followed by contacting the sand with sufficient catalyst-containing fluid to deposit catalyst on the sand grain surface,followed by injecting the polymerizable resin as is taught in other prior art methods. In particular, preferred embodiments of this invention permit consolidating sand in wells completed in formations whose temperatures are below 350F (176.7C) with set times below 24 hours.
B~CRGROUND OF THE~ INVENTIt)N
Sand consolidation is a well known term applying to procedures routinely practiced in the commercial production of petroleum, whereby wells are treated in order to reduce a problem generally referred to as sand production. When wells are completed in petroleum-containing Pormations, which ~ormations also contain unconsolidated granular mineral material such as sand or gravel, production o~ flui.ds ~rom the ~ormation causes the flow o~ the particulate matter, e.y. sand, into the wellbore, which often leads to any of several difficult and expensive problems. Sometimes a well will "sand up", meaning the lower portion of the production well becomes filled with sand, after which further production of fluid from the forma-tion becomes 20~æ3~
difficult or impossible. In other instances, sand production along with the fluid results in passage o~ granular mineral material into the pump and associated hardware of the produciny well, which causes accelerated wear of the mechanical components of the producing oil well. Sustained production of sand sometimes forms a cavity in the formation which collapses and destroys the well. All of these problems are known to exist and many methods have been disclosed in the prior art and applied in oil fields in order to reduce or eliminate production of unconsolidated sand from a petroleum formation during the course of oil production.
The above-described problem and potential solutions to the problem have been the subject of extensive research by the petroleum industry in the hope of developing techniques which minimize or eliminate the production of sand particles into the producing well and associated equipment during the course o~
producing fluids from the ~ormation. One such general approach suggested in the prior art involves consolidating the porous but unconsolidated sand structure around the wellbore in oxder ~o cement the loose sand grains toyether, thereby ~orminy a permeable mass which will allow production of ~luids ~rom the ~ormation into the well but which will restrain the movement o~
sand particles into the wellbore. The objective o~ such procedures is to create a permeable barrier or sieve adjacent to %~23~
the perforations or other openings in the well casing which establish communication between the production formation and the production tubing, which restrains the flow of loose particulate mineral matter such as sand. Another approach involves removing a portion of the formation around the well and packing specially prepared granular material into the formation around the wellbore which is subsequently caused to be cemented together in a manner which maintains fluid permeability.
It is a primary objective of any operable sand consolidation method that a barrier be formed around the wellbore which restrains the movement of sand particles into the well while offering little or no restriction to the flow of fluids, particularly oil, from the formation into the wellbore where it can be pumped to the surface of the earth. Consolidation only needs to extend into the formation to a depth of 6 to 12 inches around the periphery of the perforations or other openings in the outer casing of the production well.
Another very importank quality of a satisfactory sand consolidation method is durability o~ the permeable barrier ~ormed around the wellbore. Once the barrier is ~ormed and the well is placed on proAuction, there will be a substantial continuing flow of fluids through the flow channels within the permeable barrier, and it is important that the barrier last for a significant period of time, e.g. several months and preferably ;
2~23~
years, without excessive abrasive wear or other deterioration of the consolidation matrix which would cause the partlculate matter to flow once again into the wellbore.
It is also important that the sand consolidating material injected into the formation should be essentially unreactive during the period it is inside the wellbore, i.e.
while it is being pumped down the well and positioned where it is desired adjacent to the perforations of the production casing.
It is this desire to delay the consolidation reaction that has lead to multi-step procedures in which first a catalyst is injected into the formation, after which the polymerizable resin containing fluid is injected. While this reduces the propensity for the fluid to polymerize in the wellbore, it does give rise to several problems which constitute inherent weaknesses in many prior art methods for accomplishing sand consolidation. First, each separate injection step increases the time and cost associated with the well treatment by which sancl consolidation is accomplished. Second, injection of catalyst into the formation in advance of the polymerizable fluid does not accomplish uniform mixing o~ catalyst with all of the polymerizable fluid which is needed to ensure optimum polymerization of the resin, which is essential for strength and durability of the consolidated mass.
Use of aqueous fluids to inject catalyst often gives rise to the need for yet additional steps to clean the sand to remove 3 ~ ~
formation petroleum so the catalyst will be absorbed by the sand and later mix with the subsequently injected resin containing fluid.
PRIOR ART
Many materials have been utilized for consolidating sand in the formation adjacent to production of wellbores. One of the more successful agents utilized for this purpose is furfuryl alcohol resin which can be polymerized to form a solid matrix which binds the sand grains together, while at the same time offering superior resistance to high temperatures and to caustic substances which may be encountered in steam flood operations. One of the problems in utilizing fuxfuryl alcohol resin to polymerize in the formation ~or the purpose of consolidating sand grains is in accomplishing uniform catalysis of the polymerization. Many catalysts that are effective for polymerizing furfuryl alcohol resins cannot be admlxed with the furfuryl alcohol to permit a single ~luid containiny both kherein and the catalyst to be injected into the formation, because the time oE polymeriæation is so short or unpredictable that there is excessive danger that the resin will polymerize in the injection wellbore. In my U.S. 4,427,069 there is disclosed a procedure - for consolidating sand in a formation adjacent to a wellbore ~ using an oligomer of furfuryl alcohol, in which the catalyst used 20S239a is a water soluble acidic salt, pre~erably zirconyl chloride, which is injected in an aqueous solution into the formation prior to the resin containing fluid injection. The salt absorbs on the sand grains, and sufficient acidic salt remains adsorbed on the sand grain during the subsequent resin fluid injection stage that adequate polymerization occurs. Although this has been very effective in most difficult situations where sand consolidation procedures are utilized, specifically in connection with thermal flooding such as steam înjection procedures, the procedure nevertheless requires a multi-fluid injection procedure which requires more time and is more expensive than is desired.
Usually a preliminary sand cleaning step is required before injectinq the aqueous-catalyst solution in order to remove khe naturally-occurring oil film from the sand grains to ensure good catalyst adsorption on the sand. Also, although catalyst mixes with the subsequently injected poly~er to a limited degree, usually sufficient to cause some polymerization, it is believed that improved performance would result if the catalyst resin mixture can be made more homogenous prior to polymeriæation, in order to achieve a dense strong durable consolidation mass.
In U.S. Patent 4,842,072 for "SAND CONSOLIDATION" we disclosed a particularly effective method for consolidating sand utilizing a mixture of a polymerizable resin such as an oligomer of furfuryl alcohol and a diluent such as butyl acetate and an c~2~
oil soluble, slightly water soluble acid catalyst such as orthonitrobenzoic acid is injecked ~ollowed by injection o~ salt water to reestablish permeability.
In U.S. Patent 4,903,770 for "SAND CONSOLIDATION" we disclosed a preferred process which is more easily removed after a period of use and which is quite inexpensive. The process employs a fluid comprising a polymerizable monomer such as furfuryl alcohol and as a diluent, a polar organic solvent such ; as methanol and a strong, non-volatile acid catalyst such as sulfuric acid, mixed with steam to form a multiphase or aerosol treating fluid, and injected into the formation to be consolidated. An ester such as ethyl or butyl acetate is incorporated in the fluid when the steam quality .is less than 80 percent.
In U.S. 4,669,543 which issued June 2, 1987, there is described a method for consolidating sand using an acid curable resin and utilizing as a catalyst, the reaction product of an acid, and an alkyl metal or ammonia molybdate. In that instance, the catalyst is incorporated in an aqueous carrier flul~ which comprises the continuous phase of an emulsion ln which the polymerizable resin is the dispersed or discontinuous phase.
Thus this process requires that the emulsion be resolved or broken after it is located in the portion of the formation where the permeable consolidating mass is desired, which is difficult ' 2~23~S
to achieve to the degree of completion necessary to accomplish the desired strong durable consolidating matrix necessary for a long lasting sand consolidation process.
U.S. 5,010~953 which issued April 30, 1991 teaches a sand consolidating process using a polymerizable compound such as furfuryl alcohol, a diluent such as a low molecular weight alcohol, an acid catalyst and an ester and as an additive to reduce shrinkage, a copolymer o~ starch and a synthetic polymer such as acrylamide or acrylate.
U.S. 5,005,647 which issued April 9, 1991, discloses a process for shutting off permeable zones in wellbores to reduce excess water flow using fluids similar to that described in U.SY
5,010,953 discussed above.
U.S. 5,005,648 which issued April 5, 1991 describes a method of treating permeable zones in a formation to reduce water flow into a well completed therein by injecting a fluid-containing polymerizable compound, an ester, an alcohol diluent, an acid catalyst such as orthonitrobenzoic acid or toluenesulfonic acid.
U.S. 4,938,287 which issued July 3, 1990 describes an oil recovery process in which a preflush such as ethyL or butyl acetate is injected into the sand to be consolidated to remove oily residue, followed by injectiny the treating fluid containiny _g _ 2~2~
the polymerizable resin, diluent, ester and acid catalyst to accomplish sand consolidation.
U.S. 4,892,072 which issued June 27, 1989 describes a sand co~solidation process using a single treating fluid comprising a polymerizable compound such as furfuryl alcohol, a diluent such as butylacetate, and an acid catalyst, preferably orthonitrobenzoic acid injected into a zone followed by injecting salt water. This process has been extremely successful in treating wells in many formations, especially in formations where the temperature exceeds 350F. This is highly advantageous since many formations being steam stimulated and which cannot be treated by other processes, can be treated by this process with a high success ratio. When the temperature is much below 350F, however, the set time or time required for polymerization of the furfuryl alcohol often runs several days to one week or more.
This often causes poor adhesion of the polymerized furfuryl alcohol to the sand grains, resulting in a weak consolidation job. Thus there i5 still an unful~illed need for a sand consolidation process applicable to formations whvse temperatures are below 350~F which will result in a set time less than 24 hours, preferably from 1-2 hours.
2~239~
8UM~ARY OF T~E INYEN'rION
We have discovered methods ~or consolidatiny sand in formations whose temperature is less than 350F while still providing a set time less than 24 hours, e.g. from 0.75 to 4.0 hours and preferably in the range of 1.0 - 2.0 hours. A fluid comprising a polymerizable resin, preferably a derivative of furfuryl alcohol, a diluent such as ethyl or butyl acetate and an oil soluble internal catalyst which can safely be mixed with the resin on the surface, is injected into the unconsolidated sand.
The catalyst action is the key to the success of our process, since this process is applied to formations whose temperature is ; less than 350F. The pK and concentration of the acid catalyst must be chosen carefully to produce a set time in the range of 0.75 to 4 hours and preferably from 1-2 hours. If the set time is below one hour, especially if it is below 0.75 hours, there is danger thak the fluid which contains both the polymerizable compound and the acid catalyst, will polymerize in the surface mixing equipment or in the injection striny. .Cf the set tlme exceeds four hours there is danger that the polymerizable compound will be washed off the sand yrains before polymerization occurs, resulting in a poor bond between the polymerized compound and the sand grains and a poor consolidation job. Ideally the oil soluble-acid chosen should have a p~ in a fairly narrow range, from 0.7 to 1.3. The preferred acid for our invention is 2~23~
toluenesulfonic acid. The concentration of the acid in the treating fluid must be selected carefully to ensure the set time of 0.75 to 4.0 and preferably from 1.0 to 2.0 hours. Usually a concentration of toluenesulfonic acid in the range of from 0.2 to 5.0 and preferably from 0.4 to 4.0 will result in a set time in the desired range of ~rom 0.75 to 4.0 and preferably 1 to 2 hours. The precise concentration of the preferred acid which produces the desired set time in a particular application in a formation whose temperature is known or determinable is defined by the formation temperature. The preferred embodiment involves preparation of a mixture of from 0.2 to 5.0 and preferably from 0.4 to 4.0 toluenesulfonic acid, the preferred catalyst for this reaction, and from 40 to 70%, and ideally around 59% of a polar organic diluent. our preferred organic diluent is butyl acetate.
To this mixture of butyl acetate and toluenesulfonic acid is added from 20 to 60 and preEerably about 40~ resin, e.g. the furfuryl alcohol oligomer. This homoyenous organic fluid can then be injected via the injection striny lnto the ~ormation without danger O:e premature polymerization. The lnjecte~ mixture of resin, butyl acetate and toluenesulfonic acld, beiny oil soluble, simultaneously removes and displaces undesired oil and other oil soluble material coating the sand grains, and ensures a thorough contact between the sand grains and the resin catalyst mixture. Next, an aqueous saline solution which is from 70% to 2~2~
100% saturated with inorganic salt, preferably sodium chloride, is injected into the resin saturated zone of the ~ormation. This injection step accomplishes an opening of flow channels within the void spaces in the formation into which the resin catalyst mixture had been injected without removing the polymerizable resin, an event which would occur with <70% salt solution, which is important to ensure that the resulting polymerized resin bonded sand matrix is sufficiently permeable to permit flow of formation fluids from the formation after the sand consolidation process is completed. The salt water also modifies the resin coating on the sand, removing water therefrom, which increases the strength and durability of the polymerized resin matrix. The well is then shut in for a period of from 0.7~ to 4.0 hours and preferably from 1-2 hours. This two-step procedure results in the formation of a permeable, durable, consolidated sand mass around the perforations of the wellbore which restrains the movement of sand into the wellbore during production operations, while permitting relatively free flow o~ ~ormati.on ~'luicls, particularly ~ormation petroleum, into the wellbore.
DETAILED VE~CRIPTION O ~ PREFERRED FMBO~IMENTS
We have discovered, and this const.itutes our invention, that it is possible to accomplish an improved sand consolidation method utilizing the sand naturally occurring in the formation in .; , 6~ 3 a process employing a single treating fluid injection step plus a brine injection step in which a mixture of polymerizable resin, having dissolved or dispersed therein the catalyst for the polymerization step, and a organic polar diluent, is injected into the formation to saturate the void space in the portion of the formation adjacent to the production well. This accomplishes coating the formation granular material, e.g. the formation sand, with the mixture of polymerizable resin and catalyst. Since the fluid injected into the formation in this step is organic and contains a diluent, the minor amounts of formation petroleum and other oil-based materials coating and contaminating the surface of the sand grains is effectively removed or dissolved. It is a particular feature of this method that a separate preliminary wash step to remove materials coating the sand grains is not required. We have conducted laboratory tests, using formation sand containiny crude oil, to which additional oil was deliberately added, and we ~till obtained successful consolidation by this method without any preliminary wash step.
The resin which we have found to be especially preferable ~or use in our sand consolidation reaction is a furfuryl alcohol oligomer. Any resin which will polymeri~e upon exposure to heat and contact with an acid catalyst can be used in this process; however, furfuryl alcohol oligomer (C4H30CH0) n is the particularly preferred polymerizable resin. This resin has 2~23~
the advantage of being relatively inexpensive and having the characteristic of autopolymerizing on exposure to acid catalyst, forming a thermal-setting resin which cures to an insoluble mass that is highly resistant to chemical attack as well as to thermal degradation. The particularly preferred commercial form in which this resin is available is Quacorr 1300~ marketed by QO
Chemicals. This resin is ordinarily obtained commercially in a form containing 90 to 95 percent furfuryl alcohol oligomer.
The furfuryl alcohol oligomer emulsion utilized in our process is so viscous that it must be diluted with an appropriate solvent in order to permit it to be pumped into the formation, and to accomplish relatively complete filling of void spaces in the formation between the sand grains. Any solvent for the furfuryl alcohol oligomer would accomplish this objective. It is possible, however, to accomplish this and another more important objective by using as the diluent a hydrolyzable ester. The polymerization of the furfuryl alcohol oligomer produces water and the water produced by polymerization suppresses the polymerization reaation. If water produced duriny polymcriæation ~ 20 of furfuryl alcohol oligomer can be removed, it is possible to ; force the polymeriæat.ion reaction to proceed further toward completion and thereby produce longer polymer chains than would result if water were left in the polymer reaction mass. A
hydrolyzable ester will remove water as it is produced, leading ~2~
to the formation of longer chain polymers which result in a stronger, more durable polymer matrix which binds the sand grains together. Accordingly, our preferred diluent for the furfuryl ; alcohol oligomer is a hydrolyzable ester, and our especially preferred species is butyl acetate.
It is essential for this procedure that the acid catalyst utilized be oil soluble so that it may be incorporated in the resin solvent solution. This permits thorough mixing of the catalyst which is essential in or order to ensure that the polymerization reaction occurs uniformly throughout the entire mass of sand consolidation chemical placed in the formation.
Prior art methods which utilize a catalyst injected in a non-miscible fluid either before or after injection of the fluid containing the polymerizable resin, or present in a non-miscible phase of the polymer fluid, do not accomplish uniform reactions such as are possible by use of the present soluble catalyst. The catalyst for use in our invention must also be one which exhihits temperature sensitivity such that the catalytic polymcr,izat:l.on does not occur during the time that the Pluid is prepared and mixed on the surPac~ oP the earth or pumped into the formation.
It is equally important that once the fluid is placed in the formation and left in a quiescent state for a period of time sufficient to ensure temperature equalization with the formation, that the polymerization reaction occur rapidly in order to permit 2~23~
completion of the procedure in an relatively brie~ period oftime, so the well can be put on produckion as soon as possible.
Because of this dual re~uirement, the catalyst choice and concentration are both very critical to the proper function of our invention.
As stated above, the preferred catalyst for use in our process is one which is oil soluble and very slightly water soluble. While we have previously disclosed that the preferred organic acid catalyst is orthonitrobenzoic acid for processes being applied to relatively high temperature (e.g., greater than 350F) formations, we have found that at temperatures less than 350F and especially when the formation temperature is below 300F, orthonitrobenzoic acid is so weak and 50 insoluble that the time required for polymerization to proceed at least sufficiently far that no displacement of polymer from the sand grain occurs, is in the rarlge of several days to a week or more.
This long sek time causes several problems. The polymerizable compound, e.g. the furfuryl alcohol, may be washed off the sand grains before polymerization proceeds far enough to render the polymer i~mobile, which greatly weakens the strength of the polymerized, consolidated sand mass. Also, the kotal cost of a well treatment is greatly increased by the extended period which the well is shut in, which delays returning the well to production.
~23~
We have found that the desired set time of from O . 75 to 4.0 and preferably from 1-2 hours can be realized ~or any particular formation temperature in the range of 60F to 350F
and especially from 1O0 to 350~F i~ the pK of the acid catalyst and the concentration o~ the acid catalyst are carefully selected.
The pK. of an organic acid is defined as the negative of the ionization constant of the acid and is essentially an inverse scale measure of the strength of the acid, e.g. strong acids have lower pK values. The acid catalyst for this process must be an organic acid which is oil soluble and which has a pK
in the range of 0.5 to 2.0 and preferably from 0.7 to 1.3. The especially preferred acid for our process is toluenesulfonic acid, usually paratoluenesulfonic acid, although mixed isomers may also be used. The following organic acids may also be used:
chloroacetic acid, dichloroacetic acid, trichloroacetic acid and arylsulfonates. Mixtures oE tvluenesul~onic acid with the above may be used. For convenience, a mlxture comprlsing 95~
toluenesul~onic acid wikh 5% xylenesulfonic aci.d has been used in the ~ield because the mixture is liquid at ~ield conditions and therefore easier to mix with the okher fluids in preparing the treating ~luid. This is a commercial product available under the trade name WITCAT TX ACID~. Other mixtures may also be used, to ensure that the melting point is below ambient temperature.
~06~9~
Once the acid has been selected, the acid concentration should be determined. The concentration of acid to yield the desired 0.75 - 4.0 hour set time is solely determined by the formation temperature. It is essential in applying our process to a formation that the temperature of the formation be known or measured. The following table gives the relationship between toluenesulfonic acid catalyst and temperature to produce set time within the preferred 1-2 hour range.
FORMATION % TOLUENE-TEMPERATURE SULFONIC
F ACID
Up to 80F 5.0 - 3.8 80 - 120F 3.8 - 3.1 120 - 140F 3~1 - 2.4 140 - 200F 2.4 - 1.4 200 - 230F 1.4 - 0.8 230 - 260F 0.8 - 0.5 260 - 300F 0.50-0.3 Surprisinyly, we have found thak the above correlatlon holds for any mixture ratio ~f resin in the ester, e.y. butyl acetate, over the volume ratio 90 to 10 to 40 to 60.
One preferred method for forming a particularly effective fluid for us in practicing the process of our invention involves mixing an approximately 50-50 mixture of the resin in its commercial form, which is usually an emulsion, with butyl ~0~23~
acetate, after which the toluenesulfonic acid cakalyst is dissolved in this mixture o~ resin and ester.
Since the melting point of toluenesulfonic acid is 223F, it is sometimes necessary to incorporate the acid in a suitable diluent, usually a low carbon alcohol such as methanol, to facilitate mixing it with the resin emulsion. From 2 to 5 percent methanol is usually adequate for this purpose. This procedure may also be used when applying the fluids described above without the second step of injecting salt water to improve permeability, such as when the fluids are injected into a zone producing excessive quantities of water, to shut off this undesired water flow.
The quantity of the fluid comprising the resin, diluent and catalyst injected into the formation varies depending on the thickness and porosity of the formation to which the sand consolidation process is to be applied, as well as the diameter of the well and the desired thicknes~ of the permeable barrier in the formation. The thickness and porosity of the formation and the diameter oE the well will always be known, and it is ordinarily satisfactory if depth o~ the penetration is in the ranye of from 6 to 12 inches ~rom the well bore. As an example, if it is desired to treat a formation whose thickness is 18 feet and porosity is 35% to form a permeable barrier just outside the perforations of the wellbore which is 8 inches thick, and the .
2~23~
well being treated is 10 inches in diameter, then the volume o~
fluid necessary is calculated according to the example below.
Volume in cubic feet equal ~ (lo + 8)2 ~ ~ (10)2 X H X Porosity = 3.14tl3)2 - 3.14t5)2 X 18 X (.35) 14~
19.79 cubic feet = 148 gallons of the fluid comprising resin, catalyst and diluent.
After the above described quantity of fluid comprising resin, catalyst and diluent are injected into the formation, a second step is needed to accomplish several objectives. The polymerizable resin must be displaced from the injection string to avoid the possibility that the resin might polymerize in the wellbore. Second, the fluid injected into the formation occupies essentially all of the void space of the formation, e.g. the volume other than the sand grains themselves in the portion of the formation contacted by the Eluid. If this injected ~luid polymerized without in~ect.ing any second fluid to displace a portion of the resin material from the void spaces of the formation, the resultant barrier would be strong and resistant to chemical attack but it would not be sufficiently 2~3~
permeable to permit flow o~ fluid through the formation into the ; wellbore.
The polymerizable resin used to prepare the sand consolidation matrix is normally available commercially as a mixture containing about 5 percent water. The strength of the sand consolidating polymer matrix will be increased if at least a portion of this water is removed before the resin polymerizes. We have found that the desired objective of displacing resin from the injection string and developing permeability within the sand consolidated mass and dewatering the polymer-containing fluid is best accomplished by injecting brine or water containing an inorganic salt, preferably sodium chloride, into the string to displace the residual amount of resin fluid from the injection string, and also to pass through the portion of the of the formation occupied by the resin fluid.
Injection of the brine develops permeability within the treated portion o~ the formation which ensures that after the resin has polymerized, the resultant barrier will be permeable to the ~low o~
fluids. The salinity o~ water utilized in this procedure is ~uite important. The sur~ace o~ the resin coated sand grains should be dewatered in order to aid in the polymerization reaction and also in order to produce a Aenser stronger matrix cementiny the sand grains together. Fresh water or water containiny up to 70 percent salt does not accomplish the drying action necessary to produce the desired strength in the permeable barrier. The desired results will only be ~0~23g~
achieved if the second fluid injected into the formation is at lea~t 70% saturated with respect to the inorganic salt and pre~erably 80 saturated. Our particular preferred embodiment uses essentially saturated brine, s~ecifically water saturated with sodium chloride at the conditions of injection. By using at least 70% saturated brine, the desired development of permeability is achieved without displacing any of the resin from the sand grains and dehydration o~
the resin necessary for the polymerization reaction to occur in the time and to the extent desired for optimum polymerization is also realized.
As a practical matter, the brine utilized will probably be water containing mainly sodium chloride because of the cost and availability of sodium chloride in the field. This is a particularly preferred brine for our purpose. We have discovered that potassium chloride does not work well in this application, and so the fluid injected into the formation after the polymerization fluid has been injected should not contain appreciable quantities of potassium chloride. The quantity of brine injected into the formatlon should be sufficient to displace all of the residual resin fluid from the injection string, and also sueflcient to pass through the resin saturated portion of the formation. It is generally sufficient if about the same volume of brine as the polymerization fluid is utilized, and the rate at which it is injected is not particularly critical for our purposes.
239~
After the above steps of injecting ~he polymerization fluid and the sodium chloride solution or brine are completed, the w~11 should be shut in and left to stand for a period of from 1 to 4 and preferably from 1 to 2 hours. The time required for the polymerization reaction to proceed to completion is predetermined by the procedure discussed above and should be in the range of 1-2 hours.
There are situations different from these described above when it is desirable to form a strong, impermeable barrier around a wellbore, such as when excessive water flow is mixing with oil produced from an adjacent layer, or when steam override at the producing well in a steam drive project is encountered. These problems can be corrected by forminy a barrier similar to that described above, except that the barrier has no permeability or very - 15 low permeability to fluid flow. A skrong, durable impermeable barrier can be provided by use of the resin emulsion injection step described above, by omitting the step of injecting the brine into the resin which has been injected into the formation. A very small ; amount of brine or other fluid should be pumped down the well tubiny to ensure that the resin-containing fluid is removed therefrom, hut the volume of fluid should be carefully controlled to ensure that little or none of the salt water fluid enters the formation. The composition and quantity of the resin fluid is precisely the same as is described above for sand consolidation use. The well should be 3 ~ ~
shut in for from l to 2 hours to allow the resin time to polymerize completely prior to resumption of oil production.
In application of either the sand consolidation or water shut off embodiment of our invention, leaving the well shut in for more than 2 hours will have no adverse effect on the process, and indeed the strength of the polymerized resin may increase in this additional period. The set time as described herein only de~ines the time in which the resin will proceed to a minimum level to prevent washing the polymer from the sand grain.
EXPE}~IMENTAL SECTION
A series of experiments were performed under controlled laboratory conditions to determine the concentration of toluenesulfonic acid which produced a set time in the preferred 1.0 -2.0 hour range. The following Table II gives the observed results.
_AB~E II
DOWNHOLE % TOLUENE5ULFONIC
TEMPERATUR~ ACXD~ _ 60F 4.0 100F 3.6 140F 2.7 180F 1.8 220F 1.0 240F 0.6 280F 0.4 2~23~1~
Surprisingly, we have found that the above correlation holds ~or any mixture ratio of resin in the esker, e.g. butyl acetate, over the volume ratio so to 10 to 40 to 60.
FIELD EXAMPLE
For the purpose of complete disclosure, including what is now believed to be as the best mode for applying the process of our invention, the following pilot field example is supplied.
A producing well is completed in a subterranean petroleum lo containing formation, the formation being from 8540 to 8588 feet.
Considerable sand production has been experienced in other wells completed in this formation in the past, and so it is contemplated that some treatment must be applied in order to permit oil production from this formation without experiencing the various problems of unconsolidated sand production. This particular well has nok been used for oil production, and so little sand has been produced from the formation. It is known that the sand is coated with formation crude, but is otherwise of a reasonable partlc:Le size to accommodate sand consolidation process using the natural sand present ln the ~ormation. It is decided khere~ore to inject sand control fluid into the ~ormation immediately adjacent to the perforation o~ the producing well in order to bind the naturally occurring sand grains together and form a stable mass which forms a permeable barrier to restrain the flow of formation sand into the well while still ~o~23~
permitting the free flow of ~ormation fluids including petroleum through the barrier. It is determined that it is sufficient to treat approximately 12 inches into the formation. Based on experience in this field, it is expected that the porosity of the formation to be treated is approximately 40%. The outside casing diameter o~ the well being treated is ten inches. The volume of f luid necessary to treat this portion of formation is determined as follows:
3.14(l + 12)2 - 3.14 (10)2 X (0.4~)(48) = 3.1~(17)_2 - 3.14(5)2 X (.40) (48) = 110.58 Cu.Ft. or 827.3 gallons In order to accomplish adequate saturation of the portion of the unconsolidated sand formation adjacent to the production well, a total of 827 gallons of resin treating fluid is required. The resin employed in this procedure is ~0-1300~ obtained ~rom Q0 Chemicals, which is an oligomer of ~ur~uryl alcohol. The ~27 gallons of sand consolidation treating fluid i~ formulated by mixiny 330 gallons of khe above-described resin with ~87 gallons of butylacetate. Since the formation temperature is known to be 200F, the desired concentration of toluenesulfonic acid is 1.0%. This requires 8.3 gallons of toluenesulfonic acid. In order to facilitate use of toluenesulfonic acid in this application, since the surface ~2~
ambient temperature is 85F, a mixture comprising 69.1 pounds toluene sulfonic acid and 8.3 gallons of methanol is prepared and then added to the resin-ester mixture~ This fluid i5 injected into the ~ormation at a rate of about 900 gallons per hour. After all of the treating fluid has been injected into the formation, 827 gallons of saturated sodium chloride brine is formulated and injected into the well at the same rate to displace the treating fluid out of the injection string and to force brine through the portion of the formation into which the treating fluid has been injected, displacing a portion of the treating fluid from the void spaces in the formation thereby forming flow channels in the resin zone. This ensures that the residual permeable barrier will exhibit sufficient permeability to permit production of fluids from the well. The well i5 shut in and is left for a period of 2 hours, which is adequate for this particular formation temperature. At the conclusion of this shut-in soak period, the well is placed on production and essentially sand-free oil production is obkained.
Although our invention has been described in term~ o~' a series of specific preferred embodiments and lllustrative examples which applicants belleve to :Lnclude the best mode for applying their invention known to them at the time of this application, it will be recognized to those skilled in the art that various modifications may be made to the composition and methods described herein without ~6Z~9~
departing from the true spirit and scope of our invention which is def ined more precisely in the claims appended hereina~ter below.
S~ND CONSOLIDATION ME~HODS
~D#91,007-F) REFERENCE TO COPENDING APPhICATIONB
This application is related to Pendiny Application Serial No. 07/459,604 filed January 2, 1990 for SAND
CONSOLIDATION METHODS.
FIEL~ OF THE INVENTION
This invention concerns a method for treating wells completed in subterranean formations containing unconsolidated particulate matter, e.g. unconsolidated sand, in order to bind the unconsolidated sand grains together in the portions of the formation immediately adjacent to the perforations of the well, and thereby form a stable yet still fluid permeable barrier around the wellbore, in order to facilitate production of fluids from the formation while restraining the movement of sand into the wellbore during the fluid production phase. More particularly, this invention pertains to a method for accomplishing sand consolidation i.n producing oil wells utlliziny the sand naturally present .in the formation and a method which utilizes a substantially reduced number of procedural steps, which reduces the time and cost of treating wells. Still more particularly, this invention comprises a method for selectively consolidatiny sand grains together in the formation adjacent to the inlet of a producing wellbore by use of single fluid 2~23~
containing the polymerizable resins with the catalyst already mixed with the resin in order to achieve more uniform mixing and to reduce the necessity of first cleaning the sand grains, followed by contacting the sand with sufficient catalyst-containing fluid to deposit catalyst on the sand grain surface,followed by injecting the polymerizable resin as is taught in other prior art methods. In particular, preferred embodiments of this invention permit consolidating sand in wells completed in formations whose temperatures are below 350F (176.7C) with set times below 24 hours.
B~CRGROUND OF THE~ INVENTIt)N
Sand consolidation is a well known term applying to procedures routinely practiced in the commercial production of petroleum, whereby wells are treated in order to reduce a problem generally referred to as sand production. When wells are completed in petroleum-containing Pormations, which ~ormations also contain unconsolidated granular mineral material such as sand or gravel, production o~ flui.ds ~rom the ~ormation causes the flow o~ the particulate matter, e.y. sand, into the wellbore, which often leads to any of several difficult and expensive problems. Sometimes a well will "sand up", meaning the lower portion of the production well becomes filled with sand, after which further production of fluid from the forma-tion becomes 20~æ3~
difficult or impossible. In other instances, sand production along with the fluid results in passage o~ granular mineral material into the pump and associated hardware of the produciny well, which causes accelerated wear of the mechanical components of the producing oil well. Sustained production of sand sometimes forms a cavity in the formation which collapses and destroys the well. All of these problems are known to exist and many methods have been disclosed in the prior art and applied in oil fields in order to reduce or eliminate production of unconsolidated sand from a petroleum formation during the course of oil production.
The above-described problem and potential solutions to the problem have been the subject of extensive research by the petroleum industry in the hope of developing techniques which minimize or eliminate the production of sand particles into the producing well and associated equipment during the course o~
producing fluids from the ~ormation. One such general approach suggested in the prior art involves consolidating the porous but unconsolidated sand structure around the wellbore in oxder ~o cement the loose sand grains toyether, thereby ~orminy a permeable mass which will allow production of ~luids ~rom the ~ormation into the well but which will restrain the movement o~
sand particles into the wellbore. The objective o~ such procedures is to create a permeable barrier or sieve adjacent to %~23~
the perforations or other openings in the well casing which establish communication between the production formation and the production tubing, which restrains the flow of loose particulate mineral matter such as sand. Another approach involves removing a portion of the formation around the well and packing specially prepared granular material into the formation around the wellbore which is subsequently caused to be cemented together in a manner which maintains fluid permeability.
It is a primary objective of any operable sand consolidation method that a barrier be formed around the wellbore which restrains the movement of sand particles into the well while offering little or no restriction to the flow of fluids, particularly oil, from the formation into the wellbore where it can be pumped to the surface of the earth. Consolidation only needs to extend into the formation to a depth of 6 to 12 inches around the periphery of the perforations or other openings in the outer casing of the production well.
Another very importank quality of a satisfactory sand consolidation method is durability o~ the permeable barrier ~ormed around the wellbore. Once the barrier is ~ormed and the well is placed on proAuction, there will be a substantial continuing flow of fluids through the flow channels within the permeable barrier, and it is important that the barrier last for a significant period of time, e.g. several months and preferably ;
2~23~
years, without excessive abrasive wear or other deterioration of the consolidation matrix which would cause the partlculate matter to flow once again into the wellbore.
It is also important that the sand consolidating material injected into the formation should be essentially unreactive during the period it is inside the wellbore, i.e.
while it is being pumped down the well and positioned where it is desired adjacent to the perforations of the production casing.
It is this desire to delay the consolidation reaction that has lead to multi-step procedures in which first a catalyst is injected into the formation, after which the polymerizable resin containing fluid is injected. While this reduces the propensity for the fluid to polymerize in the wellbore, it does give rise to several problems which constitute inherent weaknesses in many prior art methods for accomplishing sand consolidation. First, each separate injection step increases the time and cost associated with the well treatment by which sancl consolidation is accomplished. Second, injection of catalyst into the formation in advance of the polymerizable fluid does not accomplish uniform mixing o~ catalyst with all of the polymerizable fluid which is needed to ensure optimum polymerization of the resin, which is essential for strength and durability of the consolidated mass.
Use of aqueous fluids to inject catalyst often gives rise to the need for yet additional steps to clean the sand to remove 3 ~ ~
formation petroleum so the catalyst will be absorbed by the sand and later mix with the subsequently injected resin containing fluid.
PRIOR ART
Many materials have been utilized for consolidating sand in the formation adjacent to production of wellbores. One of the more successful agents utilized for this purpose is furfuryl alcohol resin which can be polymerized to form a solid matrix which binds the sand grains together, while at the same time offering superior resistance to high temperatures and to caustic substances which may be encountered in steam flood operations. One of the problems in utilizing fuxfuryl alcohol resin to polymerize in the formation ~or the purpose of consolidating sand grains is in accomplishing uniform catalysis of the polymerization. Many catalysts that are effective for polymerizing furfuryl alcohol resins cannot be admlxed with the furfuryl alcohol to permit a single ~luid containiny both kherein and the catalyst to be injected into the formation, because the time oE polymeriæation is so short or unpredictable that there is excessive danger that the resin will polymerize in the injection wellbore. In my U.S. 4,427,069 there is disclosed a procedure - for consolidating sand in a formation adjacent to a wellbore ~ using an oligomer of furfuryl alcohol, in which the catalyst used 20S239a is a water soluble acidic salt, pre~erably zirconyl chloride, which is injected in an aqueous solution into the formation prior to the resin containing fluid injection. The salt absorbs on the sand grains, and sufficient acidic salt remains adsorbed on the sand grain during the subsequent resin fluid injection stage that adequate polymerization occurs. Although this has been very effective in most difficult situations where sand consolidation procedures are utilized, specifically in connection with thermal flooding such as steam înjection procedures, the procedure nevertheless requires a multi-fluid injection procedure which requires more time and is more expensive than is desired.
Usually a preliminary sand cleaning step is required before injectinq the aqueous-catalyst solution in order to remove khe naturally-occurring oil film from the sand grains to ensure good catalyst adsorption on the sand. Also, although catalyst mixes with the subsequently injected poly~er to a limited degree, usually sufficient to cause some polymerization, it is believed that improved performance would result if the catalyst resin mixture can be made more homogenous prior to polymeriæation, in order to achieve a dense strong durable consolidation mass.
In U.S. Patent 4,842,072 for "SAND CONSOLIDATION" we disclosed a particularly effective method for consolidating sand utilizing a mixture of a polymerizable resin such as an oligomer of furfuryl alcohol and a diluent such as butyl acetate and an c~2~
oil soluble, slightly water soluble acid catalyst such as orthonitrobenzoic acid is injecked ~ollowed by injection o~ salt water to reestablish permeability.
In U.S. Patent 4,903,770 for "SAND CONSOLIDATION" we disclosed a preferred process which is more easily removed after a period of use and which is quite inexpensive. The process employs a fluid comprising a polymerizable monomer such as furfuryl alcohol and as a diluent, a polar organic solvent such ; as methanol and a strong, non-volatile acid catalyst such as sulfuric acid, mixed with steam to form a multiphase or aerosol treating fluid, and injected into the formation to be consolidated. An ester such as ethyl or butyl acetate is incorporated in the fluid when the steam quality .is less than 80 percent.
In U.S. 4,669,543 which issued June 2, 1987, there is described a method for consolidating sand using an acid curable resin and utilizing as a catalyst, the reaction product of an acid, and an alkyl metal or ammonia molybdate. In that instance, the catalyst is incorporated in an aqueous carrier flul~ which comprises the continuous phase of an emulsion ln which the polymerizable resin is the dispersed or discontinuous phase.
Thus this process requires that the emulsion be resolved or broken after it is located in the portion of the formation where the permeable consolidating mass is desired, which is difficult ' 2~23~S
to achieve to the degree of completion necessary to accomplish the desired strong durable consolidating matrix necessary for a long lasting sand consolidation process.
U.S. 5,010~953 which issued April 30, 1991 teaches a sand consolidating process using a polymerizable compound such as furfuryl alcohol, a diluent such as a low molecular weight alcohol, an acid catalyst and an ester and as an additive to reduce shrinkage, a copolymer o~ starch and a synthetic polymer such as acrylamide or acrylate.
U.S. 5,005,647 which issued April 9, 1991, discloses a process for shutting off permeable zones in wellbores to reduce excess water flow using fluids similar to that described in U.SY
5,010,953 discussed above.
U.S. 5,005,648 which issued April 5, 1991 describes a method of treating permeable zones in a formation to reduce water flow into a well completed therein by injecting a fluid-containing polymerizable compound, an ester, an alcohol diluent, an acid catalyst such as orthonitrobenzoic acid or toluenesulfonic acid.
U.S. 4,938,287 which issued July 3, 1990 describes an oil recovery process in which a preflush such as ethyL or butyl acetate is injected into the sand to be consolidated to remove oily residue, followed by injectiny the treating fluid containiny _g _ 2~2~
the polymerizable resin, diluent, ester and acid catalyst to accomplish sand consolidation.
U.S. 4,892,072 which issued June 27, 1989 describes a sand co~solidation process using a single treating fluid comprising a polymerizable compound such as furfuryl alcohol, a diluent such as butylacetate, and an acid catalyst, preferably orthonitrobenzoic acid injected into a zone followed by injecting salt water. This process has been extremely successful in treating wells in many formations, especially in formations where the temperature exceeds 350F. This is highly advantageous since many formations being steam stimulated and which cannot be treated by other processes, can be treated by this process with a high success ratio. When the temperature is much below 350F, however, the set time or time required for polymerization of the furfuryl alcohol often runs several days to one week or more.
This often causes poor adhesion of the polymerized furfuryl alcohol to the sand grains, resulting in a weak consolidation job. Thus there i5 still an unful~illed need for a sand consolidation process applicable to formations whvse temperatures are below 350~F which will result in a set time less than 24 hours, preferably from 1-2 hours.
2~239~
8UM~ARY OF T~E INYEN'rION
We have discovered methods ~or consolidatiny sand in formations whose temperature is less than 350F while still providing a set time less than 24 hours, e.g. from 0.75 to 4.0 hours and preferably in the range of 1.0 - 2.0 hours. A fluid comprising a polymerizable resin, preferably a derivative of furfuryl alcohol, a diluent such as ethyl or butyl acetate and an oil soluble internal catalyst which can safely be mixed with the resin on the surface, is injected into the unconsolidated sand.
The catalyst action is the key to the success of our process, since this process is applied to formations whose temperature is ; less than 350F. The pK and concentration of the acid catalyst must be chosen carefully to produce a set time in the range of 0.75 to 4 hours and preferably from 1-2 hours. If the set time is below one hour, especially if it is below 0.75 hours, there is danger thak the fluid which contains both the polymerizable compound and the acid catalyst, will polymerize in the surface mixing equipment or in the injection striny. .Cf the set tlme exceeds four hours there is danger that the polymerizable compound will be washed off the sand yrains before polymerization occurs, resulting in a poor bond between the polymerized compound and the sand grains and a poor consolidation job. Ideally the oil soluble-acid chosen should have a p~ in a fairly narrow range, from 0.7 to 1.3. The preferred acid for our invention is 2~23~
toluenesulfonic acid. The concentration of the acid in the treating fluid must be selected carefully to ensure the set time of 0.75 to 4.0 and preferably from 1.0 to 2.0 hours. Usually a concentration of toluenesulfonic acid in the range of from 0.2 to 5.0 and preferably from 0.4 to 4.0 will result in a set time in the desired range of ~rom 0.75 to 4.0 and preferably 1 to 2 hours. The precise concentration of the preferred acid which produces the desired set time in a particular application in a formation whose temperature is known or determinable is defined by the formation temperature. The preferred embodiment involves preparation of a mixture of from 0.2 to 5.0 and preferably from 0.4 to 4.0 toluenesulfonic acid, the preferred catalyst for this reaction, and from 40 to 70%, and ideally around 59% of a polar organic diluent. our preferred organic diluent is butyl acetate.
To this mixture of butyl acetate and toluenesulfonic acid is added from 20 to 60 and preEerably about 40~ resin, e.g. the furfuryl alcohol oligomer. This homoyenous organic fluid can then be injected via the injection striny lnto the ~ormation without danger O:e premature polymerization. The lnjecte~ mixture of resin, butyl acetate and toluenesulfonic acld, beiny oil soluble, simultaneously removes and displaces undesired oil and other oil soluble material coating the sand grains, and ensures a thorough contact between the sand grains and the resin catalyst mixture. Next, an aqueous saline solution which is from 70% to 2~2~
100% saturated with inorganic salt, preferably sodium chloride, is injected into the resin saturated zone of the ~ormation. This injection step accomplishes an opening of flow channels within the void spaces in the formation into which the resin catalyst mixture had been injected without removing the polymerizable resin, an event which would occur with <70% salt solution, which is important to ensure that the resulting polymerized resin bonded sand matrix is sufficiently permeable to permit flow of formation fluids from the formation after the sand consolidation process is completed. The salt water also modifies the resin coating on the sand, removing water therefrom, which increases the strength and durability of the polymerized resin matrix. The well is then shut in for a period of from 0.7~ to 4.0 hours and preferably from 1-2 hours. This two-step procedure results in the formation of a permeable, durable, consolidated sand mass around the perforations of the wellbore which restrains the movement of sand into the wellbore during production operations, while permitting relatively free flow o~ ~ormati.on ~'luicls, particularly ~ormation petroleum, into the wellbore.
DETAILED VE~CRIPTION O ~ PREFERRED FMBO~IMENTS
We have discovered, and this const.itutes our invention, that it is possible to accomplish an improved sand consolidation method utilizing the sand naturally occurring in the formation in .; , 6~ 3 a process employing a single treating fluid injection step plus a brine injection step in which a mixture of polymerizable resin, having dissolved or dispersed therein the catalyst for the polymerization step, and a organic polar diluent, is injected into the formation to saturate the void space in the portion of the formation adjacent to the production well. This accomplishes coating the formation granular material, e.g. the formation sand, with the mixture of polymerizable resin and catalyst. Since the fluid injected into the formation in this step is organic and contains a diluent, the minor amounts of formation petroleum and other oil-based materials coating and contaminating the surface of the sand grains is effectively removed or dissolved. It is a particular feature of this method that a separate preliminary wash step to remove materials coating the sand grains is not required. We have conducted laboratory tests, using formation sand containiny crude oil, to which additional oil was deliberately added, and we ~till obtained successful consolidation by this method without any preliminary wash step.
The resin which we have found to be especially preferable ~or use in our sand consolidation reaction is a furfuryl alcohol oligomer. Any resin which will polymeri~e upon exposure to heat and contact with an acid catalyst can be used in this process; however, furfuryl alcohol oligomer (C4H30CH0) n is the particularly preferred polymerizable resin. This resin has 2~23~
the advantage of being relatively inexpensive and having the characteristic of autopolymerizing on exposure to acid catalyst, forming a thermal-setting resin which cures to an insoluble mass that is highly resistant to chemical attack as well as to thermal degradation. The particularly preferred commercial form in which this resin is available is Quacorr 1300~ marketed by QO
Chemicals. This resin is ordinarily obtained commercially in a form containing 90 to 95 percent furfuryl alcohol oligomer.
The furfuryl alcohol oligomer emulsion utilized in our process is so viscous that it must be diluted with an appropriate solvent in order to permit it to be pumped into the formation, and to accomplish relatively complete filling of void spaces in the formation between the sand grains. Any solvent for the furfuryl alcohol oligomer would accomplish this objective. It is possible, however, to accomplish this and another more important objective by using as the diluent a hydrolyzable ester. The polymerization of the furfuryl alcohol oligomer produces water and the water produced by polymerization suppresses the polymerization reaation. If water produced duriny polymcriæation ~ 20 of furfuryl alcohol oligomer can be removed, it is possible to ; force the polymeriæat.ion reaction to proceed further toward completion and thereby produce longer polymer chains than would result if water were left in the polymer reaction mass. A
hydrolyzable ester will remove water as it is produced, leading ~2~
to the formation of longer chain polymers which result in a stronger, more durable polymer matrix which binds the sand grains together. Accordingly, our preferred diluent for the furfuryl ; alcohol oligomer is a hydrolyzable ester, and our especially preferred species is butyl acetate.
It is essential for this procedure that the acid catalyst utilized be oil soluble so that it may be incorporated in the resin solvent solution. This permits thorough mixing of the catalyst which is essential in or order to ensure that the polymerization reaction occurs uniformly throughout the entire mass of sand consolidation chemical placed in the formation.
Prior art methods which utilize a catalyst injected in a non-miscible fluid either before or after injection of the fluid containing the polymerizable resin, or present in a non-miscible phase of the polymer fluid, do not accomplish uniform reactions such as are possible by use of the present soluble catalyst. The catalyst for use in our invention must also be one which exhihits temperature sensitivity such that the catalytic polymcr,izat:l.on does not occur during the time that the Pluid is prepared and mixed on the surPac~ oP the earth or pumped into the formation.
It is equally important that once the fluid is placed in the formation and left in a quiescent state for a period of time sufficient to ensure temperature equalization with the formation, that the polymerization reaction occur rapidly in order to permit 2~23~
completion of the procedure in an relatively brie~ period oftime, so the well can be put on produckion as soon as possible.
Because of this dual re~uirement, the catalyst choice and concentration are both very critical to the proper function of our invention.
As stated above, the preferred catalyst for use in our process is one which is oil soluble and very slightly water soluble. While we have previously disclosed that the preferred organic acid catalyst is orthonitrobenzoic acid for processes being applied to relatively high temperature (e.g., greater than 350F) formations, we have found that at temperatures less than 350F and especially when the formation temperature is below 300F, orthonitrobenzoic acid is so weak and 50 insoluble that the time required for polymerization to proceed at least sufficiently far that no displacement of polymer from the sand grain occurs, is in the rarlge of several days to a week or more.
This long sek time causes several problems. The polymerizable compound, e.g. the furfuryl alcohol, may be washed off the sand grains before polymerization proceeds far enough to render the polymer i~mobile, which greatly weakens the strength of the polymerized, consolidated sand mass. Also, the kotal cost of a well treatment is greatly increased by the extended period which the well is shut in, which delays returning the well to production.
~23~
We have found that the desired set time of from O . 75 to 4.0 and preferably from 1-2 hours can be realized ~or any particular formation temperature in the range of 60F to 350F
and especially from 1O0 to 350~F i~ the pK of the acid catalyst and the concentration o~ the acid catalyst are carefully selected.
The pK. of an organic acid is defined as the negative of the ionization constant of the acid and is essentially an inverse scale measure of the strength of the acid, e.g. strong acids have lower pK values. The acid catalyst for this process must be an organic acid which is oil soluble and which has a pK
in the range of 0.5 to 2.0 and preferably from 0.7 to 1.3. The especially preferred acid for our process is toluenesulfonic acid, usually paratoluenesulfonic acid, although mixed isomers may also be used. The following organic acids may also be used:
chloroacetic acid, dichloroacetic acid, trichloroacetic acid and arylsulfonates. Mixtures oE tvluenesul~onic acid with the above may be used. For convenience, a mlxture comprlsing 95~
toluenesul~onic acid wikh 5% xylenesulfonic aci.d has been used in the ~ield because the mixture is liquid at ~ield conditions and therefore easier to mix with the okher fluids in preparing the treating ~luid. This is a commercial product available under the trade name WITCAT TX ACID~. Other mixtures may also be used, to ensure that the melting point is below ambient temperature.
~06~9~
Once the acid has been selected, the acid concentration should be determined. The concentration of acid to yield the desired 0.75 - 4.0 hour set time is solely determined by the formation temperature. It is essential in applying our process to a formation that the temperature of the formation be known or measured. The following table gives the relationship between toluenesulfonic acid catalyst and temperature to produce set time within the preferred 1-2 hour range.
FORMATION % TOLUENE-TEMPERATURE SULFONIC
F ACID
Up to 80F 5.0 - 3.8 80 - 120F 3.8 - 3.1 120 - 140F 3~1 - 2.4 140 - 200F 2.4 - 1.4 200 - 230F 1.4 - 0.8 230 - 260F 0.8 - 0.5 260 - 300F 0.50-0.3 Surprisinyly, we have found thak the above correlatlon holds for any mixture ratio ~f resin in the ester, e.y. butyl acetate, over the volume ratio 90 to 10 to 40 to 60.
One preferred method for forming a particularly effective fluid for us in practicing the process of our invention involves mixing an approximately 50-50 mixture of the resin in its commercial form, which is usually an emulsion, with butyl ~0~23~
acetate, after which the toluenesulfonic acid cakalyst is dissolved in this mixture o~ resin and ester.
Since the melting point of toluenesulfonic acid is 223F, it is sometimes necessary to incorporate the acid in a suitable diluent, usually a low carbon alcohol such as methanol, to facilitate mixing it with the resin emulsion. From 2 to 5 percent methanol is usually adequate for this purpose. This procedure may also be used when applying the fluids described above without the second step of injecting salt water to improve permeability, such as when the fluids are injected into a zone producing excessive quantities of water, to shut off this undesired water flow.
The quantity of the fluid comprising the resin, diluent and catalyst injected into the formation varies depending on the thickness and porosity of the formation to which the sand consolidation process is to be applied, as well as the diameter of the well and the desired thicknes~ of the permeable barrier in the formation. The thickness and porosity of the formation and the diameter oE the well will always be known, and it is ordinarily satisfactory if depth o~ the penetration is in the ranye of from 6 to 12 inches ~rom the well bore. As an example, if it is desired to treat a formation whose thickness is 18 feet and porosity is 35% to form a permeable barrier just outside the perforations of the wellbore which is 8 inches thick, and the .
2~23~
well being treated is 10 inches in diameter, then the volume o~
fluid necessary is calculated according to the example below.
Volume in cubic feet equal ~ (lo + 8)2 ~ ~ (10)2 X H X Porosity = 3.14tl3)2 - 3.14t5)2 X 18 X (.35) 14~
19.79 cubic feet = 148 gallons of the fluid comprising resin, catalyst and diluent.
After the above described quantity of fluid comprising resin, catalyst and diluent are injected into the formation, a second step is needed to accomplish several objectives. The polymerizable resin must be displaced from the injection string to avoid the possibility that the resin might polymerize in the wellbore. Second, the fluid injected into the formation occupies essentially all of the void space of the formation, e.g. the volume other than the sand grains themselves in the portion of the formation contacted by the Eluid. If this injected ~luid polymerized without in~ect.ing any second fluid to displace a portion of the resin material from the void spaces of the formation, the resultant barrier would be strong and resistant to chemical attack but it would not be sufficiently 2~3~
permeable to permit flow o~ fluid through the formation into the ; wellbore.
The polymerizable resin used to prepare the sand consolidation matrix is normally available commercially as a mixture containing about 5 percent water. The strength of the sand consolidating polymer matrix will be increased if at least a portion of this water is removed before the resin polymerizes. We have found that the desired objective of displacing resin from the injection string and developing permeability within the sand consolidated mass and dewatering the polymer-containing fluid is best accomplished by injecting brine or water containing an inorganic salt, preferably sodium chloride, into the string to displace the residual amount of resin fluid from the injection string, and also to pass through the portion of the of the formation occupied by the resin fluid.
Injection of the brine develops permeability within the treated portion o~ the formation which ensures that after the resin has polymerized, the resultant barrier will be permeable to the ~low o~
fluids. The salinity o~ water utilized in this procedure is ~uite important. The sur~ace o~ the resin coated sand grains should be dewatered in order to aid in the polymerization reaction and also in order to produce a Aenser stronger matrix cementiny the sand grains together. Fresh water or water containiny up to 70 percent salt does not accomplish the drying action necessary to produce the desired strength in the permeable barrier. The desired results will only be ~0~23g~
achieved if the second fluid injected into the formation is at lea~t 70% saturated with respect to the inorganic salt and pre~erably 80 saturated. Our particular preferred embodiment uses essentially saturated brine, s~ecifically water saturated with sodium chloride at the conditions of injection. By using at least 70% saturated brine, the desired development of permeability is achieved without displacing any of the resin from the sand grains and dehydration o~
the resin necessary for the polymerization reaction to occur in the time and to the extent desired for optimum polymerization is also realized.
As a practical matter, the brine utilized will probably be water containing mainly sodium chloride because of the cost and availability of sodium chloride in the field. This is a particularly preferred brine for our purpose. We have discovered that potassium chloride does not work well in this application, and so the fluid injected into the formation after the polymerization fluid has been injected should not contain appreciable quantities of potassium chloride. The quantity of brine injected into the formatlon should be sufficient to displace all of the residual resin fluid from the injection string, and also sueflcient to pass through the resin saturated portion of the formation. It is generally sufficient if about the same volume of brine as the polymerization fluid is utilized, and the rate at which it is injected is not particularly critical for our purposes.
239~
After the above steps of injecting ~he polymerization fluid and the sodium chloride solution or brine are completed, the w~11 should be shut in and left to stand for a period of from 1 to 4 and preferably from 1 to 2 hours. The time required for the polymerization reaction to proceed to completion is predetermined by the procedure discussed above and should be in the range of 1-2 hours.
There are situations different from these described above when it is desirable to form a strong, impermeable barrier around a wellbore, such as when excessive water flow is mixing with oil produced from an adjacent layer, or when steam override at the producing well in a steam drive project is encountered. These problems can be corrected by forminy a barrier similar to that described above, except that the barrier has no permeability or very - 15 low permeability to fluid flow. A skrong, durable impermeable barrier can be provided by use of the resin emulsion injection step described above, by omitting the step of injecting the brine into the resin which has been injected into the formation. A very small ; amount of brine or other fluid should be pumped down the well tubiny to ensure that the resin-containing fluid is removed therefrom, hut the volume of fluid should be carefully controlled to ensure that little or none of the salt water fluid enters the formation. The composition and quantity of the resin fluid is precisely the same as is described above for sand consolidation use. The well should be 3 ~ ~
shut in for from l to 2 hours to allow the resin time to polymerize completely prior to resumption of oil production.
In application of either the sand consolidation or water shut off embodiment of our invention, leaving the well shut in for more than 2 hours will have no adverse effect on the process, and indeed the strength of the polymerized resin may increase in this additional period. The set time as described herein only de~ines the time in which the resin will proceed to a minimum level to prevent washing the polymer from the sand grain.
EXPE}~IMENTAL SECTION
A series of experiments were performed under controlled laboratory conditions to determine the concentration of toluenesulfonic acid which produced a set time in the preferred 1.0 -2.0 hour range. The following Table II gives the observed results.
_AB~E II
DOWNHOLE % TOLUENE5ULFONIC
TEMPERATUR~ ACXD~ _ 60F 4.0 100F 3.6 140F 2.7 180F 1.8 220F 1.0 240F 0.6 280F 0.4 2~23~1~
Surprisingly, we have found that the above correlation holds ~or any mixture ratio of resin in the esker, e.g. butyl acetate, over the volume ratio so to 10 to 40 to 60.
FIELD EXAMPLE
For the purpose of complete disclosure, including what is now believed to be as the best mode for applying the process of our invention, the following pilot field example is supplied.
A producing well is completed in a subterranean petroleum lo containing formation, the formation being from 8540 to 8588 feet.
Considerable sand production has been experienced in other wells completed in this formation in the past, and so it is contemplated that some treatment must be applied in order to permit oil production from this formation without experiencing the various problems of unconsolidated sand production. This particular well has nok been used for oil production, and so little sand has been produced from the formation. It is known that the sand is coated with formation crude, but is otherwise of a reasonable partlc:Le size to accommodate sand consolidation process using the natural sand present ln the ~ormation. It is decided khere~ore to inject sand control fluid into the ~ormation immediately adjacent to the perforation o~ the producing well in order to bind the naturally occurring sand grains together and form a stable mass which forms a permeable barrier to restrain the flow of formation sand into the well while still ~o~23~
permitting the free flow of ~ormation fluids including petroleum through the barrier. It is determined that it is sufficient to treat approximately 12 inches into the formation. Based on experience in this field, it is expected that the porosity of the formation to be treated is approximately 40%. The outside casing diameter o~ the well being treated is ten inches. The volume of f luid necessary to treat this portion of formation is determined as follows:
3.14(l + 12)2 - 3.14 (10)2 X (0.4~)(48) = 3.1~(17)_2 - 3.14(5)2 X (.40) (48) = 110.58 Cu.Ft. or 827.3 gallons In order to accomplish adequate saturation of the portion of the unconsolidated sand formation adjacent to the production well, a total of 827 gallons of resin treating fluid is required. The resin employed in this procedure is ~0-1300~ obtained ~rom Q0 Chemicals, which is an oligomer of ~ur~uryl alcohol. The ~27 gallons of sand consolidation treating fluid i~ formulated by mixiny 330 gallons of khe above-described resin with ~87 gallons of butylacetate. Since the formation temperature is known to be 200F, the desired concentration of toluenesulfonic acid is 1.0%. This requires 8.3 gallons of toluenesulfonic acid. In order to facilitate use of toluenesulfonic acid in this application, since the surface ~2~
ambient temperature is 85F, a mixture comprising 69.1 pounds toluene sulfonic acid and 8.3 gallons of methanol is prepared and then added to the resin-ester mixture~ This fluid i5 injected into the ~ormation at a rate of about 900 gallons per hour. After all of the treating fluid has been injected into the formation, 827 gallons of saturated sodium chloride brine is formulated and injected into the well at the same rate to displace the treating fluid out of the injection string and to force brine through the portion of the formation into which the treating fluid has been injected, displacing a portion of the treating fluid from the void spaces in the formation thereby forming flow channels in the resin zone. This ensures that the residual permeable barrier will exhibit sufficient permeability to permit production of fluids from the well. The well i5 shut in and is left for a period of 2 hours, which is adequate for this particular formation temperature. At the conclusion of this shut-in soak period, the well is placed on production and essentially sand-free oil production is obkained.
Although our invention has been described in term~ o~' a series of specific preferred embodiments and lllustrative examples which applicants belleve to :Lnclude the best mode for applying their invention known to them at the time of this application, it will be recognized to those skilled in the art that various modifications may be made to the composition and methods described herein without ~6Z~9~
departing from the true spirit and scope of our invention which is def ined more precisely in the claims appended hereina~ter below.
Claims (35)
1. A method for consolidating unconsolidated mineral particles including sand in a subterranean petroleum formation whose temperature is known or determinable, said formation being penetrated by a well in fluid communication with at least a portion of the formation, comprising:
(a) providing a fluid comprising a polymerizable resin, a polar organic diluent for the resin, and a predetermined concentration of an oil soluble acid catalyst capable of causing polymerization of the resin at formation temperatures, said acid having a pK in the range of 0.50 to 2.0;
(b) injecting said fluid into the formation to saturate at least a portion of the formation adjacent to the well;
(c) providing an aqueous fluid comprising water containing selected inorganic salts including sodium chloride in a concentration at least 70% of saturation of said inorganic salts at surface ambient temperature;
(d) injecting the salt-containing aqueous solution into the same portion of the formation contacted by the resin containing fluid; and (e) allowing the injected fluids to remain in the formations for at least four hours to accomplish at least partial polymerization of the resin, forming a permeable consolidated mass around the wellbore.
(a) providing a fluid comprising a polymerizable resin, a polar organic diluent for the resin, and a predetermined concentration of an oil soluble acid catalyst capable of causing polymerization of the resin at formation temperatures, said acid having a pK in the range of 0.50 to 2.0;
(b) injecting said fluid into the formation to saturate at least a portion of the formation adjacent to the well;
(c) providing an aqueous fluid comprising water containing selected inorganic salts including sodium chloride in a concentration at least 70% of saturation of said inorganic salts at surface ambient temperature;
(d) injecting the salt-containing aqueous solution into the same portion of the formation contacted by the resin containing fluid; and (e) allowing the injected fluids to remain in the formations for at least four hours to accomplish at least partial polymerization of the resin, forming a permeable consolidated mass around the wellbore.
2. A method recited in Claim 1 wherein the resin is oligomer of furfuryl alcohol.
3. A method as recited in Claim 2 wherein the concentration of the furfuryl alcohol oligomer is from 40% to 80% by volume based on the total volume of the fluid.
4. A method as recited in Claim 2 wherein the concentration of furfuryl alcohol oligomer is from 50% to 60% by volume based on the total volume of the fluid.
5. A method as recited in Claim 1 wherein the polar organic diluent is a hydrolyzable ester.
6. A method as recited in Claim 5 wherein the polar organic diluent is butyl acetate.
7. A method as recited in Claim 6 wherein the concentration of butyl acetate in the treating fluid is from 20% to 60% by volume.
8. A method as recited in Claim 6 wherein the concentration of butyl acetate in the treating fluid is from 40% to 50% by volume.
9. A method as recited in Claim 1 wherein the concentration of acid catalyst is from 0.2% to 5.0% by volume.
10. A method as recited in Claim 1 wherein the concentration of acid catalyst is from 0.40% to 4.0% by volume.
11. A method as recited in Claim 1 wherein the aqueous fluid is essentially saturated with respect to said inorganic salt.
12. A method as recited in Claim 1 wherein the aqueous fluid is a sodium chloride brine.
13. A method as recited in Claim 12 wherein the sodium chloride brine is at least 70% saturated.
14. A method as recited in Claim 12 wherein the aqueous fluid is saturated sodium chloride brine.
15. A method as recited in Claim 1 wherein the resin-containing fluid is prepared by dissolving catalyst in the polar organic diluent and then mixing with the resin.
16. A method as recited in Claim 1 wherein the volume of consolidating treating fluid injected into the formation is sufficient to saturate the pore space of the formation adjacent to the producing well for a distance up to 12 inches from the well.
17. A method as recited in Claim 1 wherein the volume of consolidating treating fluid injected into the formation is sufficient to saturate the pore space of the formation adjacent to the producing well for a distance up to 8 inches from the well.
18. A method as recited in Claim 1 wherein the volume of aqueous fluid injected into the formation after injecting the consolidating treating fluid is about equal to the volume of treating fluid used.
19. A method as recited in Claim 1 wherein the concentration of acid catalyst is selected to yield a set time at the formation temperature of from 0.75-4.0 hours.
20. A method as recited in Claim 1 wherein the concentration of acid catalyst is selected to yield a set time at the formation temperature of from 1.0 to 2.0 hours.
21. A method as recited in Claim 1 wherein the formation temperature is up to 80°F and the concentration of acid catalyst is from 5.0% to 3.8% by weight.
22. A method as recited in Claim 1 wherein the formation temperature is from 80°F to 120°F and the concentration of acid catalyst is from 3.8% to 3.1% by weight.
23. A method as recited in Claim 1 wherein the formation temperature is from 120°F to 140°F and the acid catalyst is from 3.1%
to 2.4% by weight.
to 2.4% by weight.
24. A method as recited in Claim 1 wherein the formation temperature is from 140°F to 200°F and the acid catalyst is from 2.4 to 1.4% by weight.
25. A method as recited in Claim 1 wherein the formation temperature is from 200°F to 230°F and the concentration of acid catalyst is from 1.5 to 0.8% by weight.
26. A method as recited in Claim 1 wherein the formation temperature is up to 230°F to 260°F and the concentration of acid catalyst is from 0.8% to 0.5% by weight.
27. A method as recited in Claim 1 wherein the formation temperature is from 260°F to 300°F and the acid catalyst is from 0.50 to 0.3% by weight.
28. A method as recited in Claim 1 wherein the acid catalyst is selected from the group consisting of toluenesulfonic acid, xylenesulfonic acid, chloroacetic acid, di or trichloroacetic acid and mixtures thereof.
29. A method as recited in Claim 28 wherein the acid catalyst is toluenesulfonic acid.
30. A method as recited in Claim 28 wherein the acid catalyst is a mixture of toluenesulfonic acid and xylenesulfonic acid.
31. A method as recited in Claim 29 comprising the additional step of predissolving the acid catalyst in a diluent comprising a low molecular weight alcohol prior to mixing it with the polymerizable resin and diluent.
32. A method as recited in Claim 31 wherein the low molecular weight alcohol is methanol.
33. A method as recited in claim 31 wherein the concentration of the low molecular weight alcohol in the mixture of alcohol and acid catalyst is from 1 to 5 percent by weight.
34. In a method for treating a subterranean formation whose temperature is known or determinable containing sand and petroleum penetrated by a well in fluid communication with at least a portion of the formation, comprising providing a fluid comprising a polymerizable resin, a polar organic diluent for the resin, and a predetermined concentration of an oil soluble acid catalyst capable of causing polymerization of the resin at formation temperatures, said acid having a pK in the range of 0.50 to 1.30, injecting said fluid into the formation to saturate at least a portion of the formation adjacent to the well and allowing the injected fluids to remain in the formations for at least four hours to accomplish at least partial polymerization of the resin.
Wherein the improvement comprises premixing the acid with a low molecular weight alcohol prior to mixing with the polymerizable resin.
Wherein the improvement comprises premixing the acid with a low molecular weight alcohol prior to mixing with the polymerizable resin.
35. A method as recited in claim 33 wherein the low molecular weight alcohol is methanol.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US71851391A | 1991-06-21 | 1991-06-21 | |
| US718,513 | 1991-06-21 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2062395A1 true CA2062395A1 (en) | 1992-12-22 |
Family
ID=24886353
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002062395A Abandoned CA2062395A1 (en) | 1991-06-21 | 1992-03-06 | Sand consolidation methods |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US5285849A (en) |
| CA (1) | CA2062395A1 (en) |
Cited By (1)
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| US3976140A (en) * | 1975-06-23 | 1976-08-24 | Exxon Production Research Company | Method of consolidating subterranean formations using diluted resins |
| US4427069A (en) * | 1981-06-08 | 1984-01-24 | Getty Oil Company | Sand consolidation methods |
| US4669543A (en) * | 1986-05-23 | 1987-06-02 | Halliburton Company | Methods and compositions for consolidating solids in subterranean zones |
| US4842072A (en) * | 1988-07-25 | 1989-06-27 | Texaco Inc. | Sand consolidation methods |
| US4903770A (en) * | 1988-09-01 | 1990-02-27 | Texaco Inc. | Sand consolidation methods |
| US4938287A (en) * | 1989-10-23 | 1990-07-03 | Texaco Inc. | Sand consolidation methods |
| US5040604A (en) * | 1990-01-02 | 1991-08-20 | Texaco Inc. | Sand consolidation method |
| US5005648A (en) * | 1990-01-02 | 1991-04-09 | Texaco Inc. | Treating underground formations |
-
1992
- 1992-03-06 CA CA002062395A patent/CA2062395A1/en not_active Abandoned
- 1992-07-06 US US07/909,479 patent/US5285849A/en not_active Expired - Fee Related
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN101570685B (en) * | 2009-05-27 | 2011-07-27 | 中国石化股份胜利油田分公司孤岛采油厂工艺研究所 | Quick curing agent for coating sand |
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