CA1307458C - Sand consolidation methods - Google Patents
Sand consolidation methodsInfo
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- CA1307458C CA1307458C CA000600506A CA600506A CA1307458C CA 1307458 C CA1307458 C CA 1307458C CA 000600506 A CA000600506 A CA 000600506A CA 600506 A CA600506 A CA 600506A CA 1307458 C CA1307458 C CA 1307458C
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Abstract
SAND CONSOLIDATION METHODS
(D# 79,016-F) ABSTRACT OF THE DISCLOSURE
Methods are provided for selectively consolidating naturally occurring mineral grains such as sand within a subterranean formation to form a fluid permeable barrier which restrains the movement of sand particles when oil passes through the barrier. 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 is provided, mixed with steam to form a multiphase or aerosol treating fluid, and injected into the formation to be consolidated. The well is shut in for sufficient period of time for polymerization to convert the injected fluids into a permeable barrier around the wellbore.
(D# 79,016-F) ABSTRACT OF THE DISCLOSURE
Methods are provided for selectively consolidating naturally occurring mineral grains such as sand within a subterranean formation to form a fluid permeable barrier which restrains the movement of sand particles when oil passes through the barrier. 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 is provided, mixed with steam to form a multiphase or aerosol treating fluid, and injected into the formation to be consolidated. The well is shut in for sufficient period of time for polymerization to convert the injected fluids into a permeable barrier around the wellbore.
Description
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_~rET.~_~F~ vRMrI~N
Thi.s invent.ion collce~ me~llnds ~or treati.ng wel.l.s completed in subterraneall forma~:iolls colltai.l~ g unconsoJ.i.dated particul.at:e matter, e.g. (.nlcollsol..i~ated salld, whi.cll ~)i.nd tlle unconsoli.dated sand gl-ai.lls to~Jet:ller in tlle E)ortlons of the formation immediatel.y adjacent t:o t:l~e pereorat-i.ons of tlle wel.]., in order to form a sl:ahle yel s~:ill. e~lnid permeabl.e barri.er around the wellbore, wll.i.cl~ perm.it:~ r)rodnction of f].lli.ds Erom the formation while restra:ini.llg tlle movemellt: Oe sand i.nto the wellbore during the f.l.-l:i.d prodllcl:ioll phase. More parti.cularly, thi.s invention pertains t:c- all inexl~etlsive method foL-accompl.islli.n~ sand consoli(~al:.ioll in l)ro(~ oil wells Ill~ i the sancl naturally prese~ in tlle ~ormcltic~ll alld an inexpellsi.ve method which utiliæes a sllbstalll:i.,lJ.~.y redllced number of procedural steps. Tlle metllo(l 1.ednces tlle l:ime and cost of treatinq wells, and plod-lces ~1 consolidat:ed permeab].e sand-polymer matrix wlli.c:ll re(i~lces movemellt oF sand dnrill~J o;.l producti.on for up to several. yeals, bllt wllicll .i.s more easi.ly removed during workover operati~ s tllan collsoli.dated sand produced by prior art: me~:llo(1s. ;t:il~ more pal-t;.cul.arl.y, thi.s invention`comprises a mel:llod for selecti.vel.y consol.i.datillg sand grai.ns t:ogc3ther i.n t-llc! lonll~ .Idj<l(~c~lll 1() t.lle inlct: oF a 1 307~5~
producing wellbore by use of a mul.tiphas( flui.d compri.sing steam containing a polymeri~ab]e monomer wit}l the catalyst already mixed wi.th the resin in order to achieve more uniform mixing and to reduce the number of steps in prior art methods including first cleaning the sand grains, followed by contacting the sand with sufficient catalyst-containing fluid to deposit catalyst on the sand grain surface, prior to i.njecting the polymerizable resin.
BACKGROlJNn OF TIIE TNVENTION
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 unconsolidated sand production. When wells are completed in petroleum-containing formations which formations also contain unconsolidated granular mineral material such as sand or gravel, production of fluids from -the formatlon causes the flow of the particulate matter into the wellbore, which often leads to any of several diffi.cult and expensive problems. Sometimes a well is said to "sand up", meaning the lower portion of the production wel.l. becomes f:illed with sand, after which further production of flui.d from the formati.on becomes difficult or impossible. In other instances, sand production along with the flllid resul.ts .in passage of granul.ar mineral material into the pump and associated hardware of the producing well, whi.ch causes accel.erated wear of the mechanical components of the producing oil weJ.l. Sustained production of sand sometimes forms a cavity in the formation which coll.apses and destroys the well. A11 of these problems are known to exis-t and many methods have been disclosed in the prior art and applied in oil fields in order to reduce or elimi.nate producti.on of 1 30~4~8 unconsolidated sand from a pekroleum fL, ,iation during the course of oll production.
The above-descri.bed probl,em and potential solutions to the problem have been the subject o-~ extensive research by the petroleum industry in the hope of developing techniques which minimize or eliminate the movement of sand particles into the producing well and associated equipment during the course of producing fluids from the formation. One such general approach suggested in the prior art involves treating the porous, unconsolidated mass sand around the wellbore in order to cement the loose sand grains to~ether, thereby forming a permeable consolidated sand mass which will allow production of fluids but which will restrain the movement of sand particles into the wellbore. The objecti.ve o~ s~lch procedures is to create a permeable barrier or si,eve adjacent to the perforations or other openings in the well casin~ which establish communication between the production formation and the production tubing, wllich restrains the flow of loose particulate mineral matter such as sand. Another approach i.nvolves removing a portion of the formation around the well and packing specially prepared resin-coated granular material into the formation around the wellbore which is subsequently caused to be cemented together.
It is a primary objective oE any operable sand consolidation method that a barri.er be formecl around the wel.lbore which restrains the movement of sand part.i.cles into the well while offering little or no restr:i.ction to the flow of fluids, particularly oil, from the format;.on into the wellbore where it can be pumped to the surface of khe earth.
Another very important quality of a satisfactory sand consolidation method i.s durabili.ty of the permeable barrier formed around the wellbore. Once the barrier is formed and the well is placed on production, there will be a substantial continuing flow of Eluids througll the flow channels wikhln the 1 307~5~
permeable barrier, and it is important ~lat the barrier last for a significant period of time, e.g. seve~ll months and preferably years, without excessive abrasive wear ~ir other deterioration of the consolidation matrix which would canse the particulate matter to once again flow into the well~ore. '~'his is a particularly difficult objective to accomplish in the instance of sand consolidation procedures applied to wells completed in formations subjected to steam flooding or other thermal recovery methods.
The production of fluids in steam flooding operations involve higher temperatures and higher pH fluids than are normally encountered in ordinary primary production, and this greatly aggravates the stability prohlem of sand conso]idation procedures.
An antithetical problem has developed in some of the modern sand consolidation processes. After a year or more of oil production, plugging of the consolidated sand mass filter often occurs and it then becomes necessary to workover the well, removing the plu~ged consolidated sand mass and then ~`orming a new sand consolidating mass in i.ts place. Some resin-consolidated sand filters are so durable that removal of the consolidated sand mass durin~ workover is costly and time-consuming. ~ccordingly, there is an unfulfilled need for sand consolidation methods which are durable eor a reasonable period of time, in the order of one or two years of` production, but which are easy and inexpensive to remove when it becomes necessary to work over the well. Ideally, there is a need for sand consolidation met~lods which restrain the movement of sand during production for a year or more, but which are then more likely to disintegrate than to become plugged.
It is also important that the 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 1 307~58 delay the consolidatlon reaction that ~las lead to multi-step procedures in which first a cata:Lyst is injected into the Eormation, after which the polymerizable resin--containing fluid is i.njected separately. While this :red~lces the propensity for the fluid to polymerize in the :injection string, it does give rise to several problems which consti.tute 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 sand consolidation is accomplished. Second, injection of catalyst into the formation in advance of the polymerizable fluid does not accomplish uniform mixin~ ~ c~talys~ wlth all of the subse~uently-injected polymerizable fluid to the degree necessary to ensure optimum polymerization of the resin, and thus often fails to` achieve maximum, uniform strenyth and ~urability of the consol.i.dated mass. Use of aqueous flui.ds to inject catal.yst often gives rise to the need for yet additional preliminary steps to clean the sand to remove formation petro].eum so the catalyst will be absorbed by the sand and ].ater mi.x with the subsequently injected resin containing fluid.
Many materials have been utilized for consoli.dating sand in the formation ad~acent to production of wel.lbores. One of the more successful agents utili.zed for this purpose are resins comprising oligomers of furEuryl alcohol whi.ch can be polymerized in situ to form a so:l.id matrix which binds the sand grains together, while at the same time offering superior resistance to high temperatures and to ca~lsti.c substances whi.ch may be encountered in steam flood operations. One of the problems in utilizing furfuryl al.cohol oligomers to polymerize i.n the formation for the purpose Oe consolidating sand grains is failing to achieve uniform catalysi.s of the polymerization. Many catalysts that are effective for polymeri.zing furfuryl alcohol resins cannot be admixed with the furfuryl alcohol to permit a 1 307~158 single fluid containing both the resiJ ,nd the catalyst to be injected into the formation, beeause tlli time of polymerization is so short or unpredictable that there is exeessive 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 aleohol, in which the catalyst used is a water soluble aeidie salt, preferably zirconyl chloride, whieh is injected in an aqueous solution into the formation prior to the resin eontaining fluid inject.ion. The salt absorbs on the sand ~rains, and sufficient acidic sa:lt remai.ns adsorbed on the sand grain during the subsequent resin fluid injection stage that adequate polymerization oecurs. Although this has been very effective in most difficult situati.ons where sand consoli.dation procedures are utilized, particularly in connecti.on with thermal flooding such as steam injection procedures, the procedure nevertheless requires a multi-fluld injeetion procedure which requires more time and is more expensive than is desired. Usually a preliminary sand eleanin~ step is required before injecting the aqueous-eatalyst so].ut:i.on in or~er to remove the naturally-oeeurring oi.l film from t~le sand ~rai.ns to ensure good eatalyst adsorption on the sand. Also, althou~h catalyst mixes with the subsequently injected polymer to a lim.ited degree, usually suffieient to eause polymer:izat;.on, it is believed that superior performance would result if t~le eatalyst resin mi.xture can be made more homogenous prior to polymerization, in order to aehieve a dense strong durable eon.soLidation mass.
In U.S. ~,669,543 whi.ch issued June 2, 19~7, there is deseribed a method for eonsolidati.ng sand using an aeid curable resin an~ utilizing as a catalyst, the react.ion product of an aeid and an alkyl metal or ammon;um molybdate. In that instance, the catalyst is incorporated in an aqueous carrier flui.d which eompri.ses the continuous phase of an emulsion in whi.ch the 1 7, 07~58 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 to achieve to the degree of completion and accuracy of timing necessary to accomplish the desired strong durable consolidating matrix necessary for a long lasting sand consolidation process.
In our copending Canadian aPPlication Serial No. 600,499 disclosed sand consolidation methods using an oligomer of furfuryl alcohol, a hydrolyzable ester as combi~ation diluent and water extractor, and an oil soluble acid catalyst. While this produces a durable, temperature resistant permeable consolidated sand sieve, it has sometimes been difficult to remove during workover.
In view of the foregoing review of the current state of the art, it can be appreciated that there is still a substantial unfulfilled need for sand consolidation processes employing a polymerizable material in which complete mixing between the catalyst and the re~in is accomplished prior to the polymerization reaction, in order to ensure that the polymerization reaction proceeds to completion, thus ensuring that the resultant polymer matrix posses the maximum possible strength and durability for the desired time period, but which either self destructs after a period of time or which is easily removed during workover. There ~s also a need for a sand consolidation pro~ess in which the number of separate fluid injection stages is reduced to a minimum of one or two, in order to reduce the time and cost of the sand consolidation method.
SUMMARY OF THE ~NVFNTION
We have discovered novel me~hods for consolidating sand involving the use of a single f~uid comprising steam, polymerizable monomer, preferably furfuryl alcohol, an organic diluent such as a low carbon alcohol and a non-volatile acid cat~lyst which can safely be mixed with the 5team on the surface so a single, multiple phase fluid containing steam, catalyst and the monomer is injected into the unconsolidated sand. It is desired that catalyst action be sufficiently slow at ordinary surface ambient temperatures that there is no danger of premature reaction of the resin resulting in plugging of the surface mixing equipment or the injection string utilized for pumping the polymerizable monomer down the well into the formation.
A preferred embodiment of the pr~sent invention, comprisQs a method for consolidating unconsolidated mineral particles including sand in a ~ubterranean petroleum formation penetrated by a well in fluid communication with at least a portion of the ~ormation, comprising:
(a) providing a ~and consolidating fluid comprising a polymerizable monomer, diluent for the mo~omer, and a non-volatile strong ~cid catalyst capable of causing polymerization of the monomer at fluid injection temperatures;
(b) mixing the sand consolidating fluid with steam to form a multiphase treating fluid;
(c) ~njecting said treating fluid into the formation to occupy the void space of at least a portion of the formation adjacent to the well; and (d) allow~ng the injected fluids to remain in the formations for a period ~f time sufficient to accomplish at least partial polymerization of the monomer, forming a permeable consolidated mass around the wellbore.
1 30745~
Further, according to the present invention, there is provided a method for forming a fluid impermeable zone in a permeable, subterranean oil-containing formation adjacent to a wellbore penetrating said formation, comprising:
a. providing a fluid compri~ing a polymerizable monomer, a diluent for said monomer, and a strong acid catalyst which causes polymerization of the monomer at steam temperatures;
b. forming a mixture of said fluid from step (a) with steam c. injecting said fluid mixture into the formation to saturate at least a portion of the formation; and d. allowing ~aid ~luid Lo remain in the formation for a period of time sufficient to accomplish at least partial polymerization of said monomer, forming a fluid impermeable barrier between the well and the formation.
me catalyst activity is highly d4p3xlrt on fluid pH, te~ature, and monomer concentration. At fluid temperature as low as 194F;
with catalyst incorporated in the treating fluid, polymerization of the monomer will occur in a very short period of time. The preferred embodiment involves preparation of treating fluid on the surface comprising steam and a mixture comprising from 20 to 30 percent polymerizable monomer, preferably furfuryl alcohol, from 80 to 70 percent of a diluent, preferably a low carbon -8a-, - :.. . -..
1 ~n7458 alcohol such as methanol, and sufficient non-volatile, strong acid such as sulfuric acid to produce a fluid comprising the furfuryl alcohol, diluent and acid having an acid normality of from .10 to ~.0 and preferably .25 to .50. The normality of the acid is critical in controlling the reaction rate, control of which is essential to avoid polymerization of the monomer in the injection line, but still have polymerization occur in the formation near the wellbore. Lower acid content is used for deeper formation depth.
The mixture of steam, monomer, diluent and acid is a multiphase mixture, similar to an aerosol. This mixture is B
`, :: L ~
1 ~0745~
injected into the formation wltho~ danyer of premature polymerization. The injected mixtllr~ simultaneously removes and displaces undesired oil and other llaterial coating the sand grains, and accomplishes a thorough cfiating of the sand grains with the monomer catalyst mixture. It: is not necessary to inject salt water or other fluids after injecting the treating fluid to maintain permeability, as the vapor phase of the injected fluid ensures residual permeability of the consolidated sand mass. The well is then shut in for a period of from 2 to 9 hours and preferably at least 6 hours. The preferred shut-in period is a function of the formati.on temperature. This one-step procedure results in the formation of a permeable, durable, consolidated sand mass around the perforations of the wellhore which restrains the movement of sand into khe wellbore duri.ng production operations, whi].e permitting re1atively free flow of formation fluids, particularly formation petroleum, into the wellbore. The thickness of the permeable mass formed around the perforations of the production well casing is determined by the volume of the fluid comprising the polymeri.zi.ncJ monomer and catalyst injected into the formation. Ordinari.ly it is sufficient for our purposes if the volume of pol.ymerized sand is at least 12 inches ln thickness measured Erom the prod~lcti.on well perforations. I~ the thickness exceeds 1~ ialclles, the barrier i.s sti.l:l. ef~:ecti.ve l~llt is unnecessar.ily expens:ive and may be f:low restricting. This procedure results in a permeable mass which is stronqer than previous techniques because the catal.ys-t is more completely dispersed and mixed in the resi.n prior to polymerization than is possible by injecting a fluicl containing the catalyst ei.ther before or after the polymer injection phase, but not so strong that it is clifficult to remove during workover operation due to the relatively thin coating of polymer on the sand grains. The procedure also requires l.ess k:;.me to accomplish i.n the ~iel.d and _g _ 1 7,07~58 is less expensive, because the number of separate injection steps is reduced over other prior art methods.
DETAILED DESCRTPTION OF T~IF._PREFERRED EMBODTMENTS
We have di.scovered, and this constitutes our invention, that it is possible to accomplish improved sand consoli.dation methods utilizlng the sand naturally occurring in the formation in a process employing a single multiphase fluid injection step in whi.ch a mixture of steam, polymerizable monomer, a catalyst for the polymerization of the monomer, and a organic diluent, is injected into the formation to enter the void space in the portion of the ~ormation adjacent to the production well. The injection of steam and polymerization chemicals is roughly analogous to a spray pai.~ting operation applied to ~ wire screen, where the wires are coated but the holes remain open. This method accomplishes coating the formation gran-llar materi.al, e.g.
the formation sand, with the mixture of polymerizable monomer anc catalyst. Since the reactive components of the fluid injected into the formation in this step are organic and contains a diluent, and are at steam temperatures, the minor amounts of formation petroleum and other oi.l-base materials coati.ng anA
contaminating the surface of the sancl grai.ns is effective:Ly removed or dissolved,maki.llg a prior sand cleaning step unnecessary. It .l.s a particul.ar eeature. Oe this method that a preliminary wash step to remove materials coating the sand grains is not required. We have conAucted laboratory tests, using format;.on sand containin~ crude o:i~, to which additional oil was deliberately added, and we still obtained successful consolidation by this method without any preliminary wash step.
1 ~!()7~58 The polymeriza~le monomer ~ ich We have found to be especially preferable ~or use in our sand consol.idation reaction is furfuryl alcohol. Any monomer which will polymerize upon exposure to heat and contact wi.th an ac:id catalyst can be used .in this process; however, furfuryl alcohol (C4T~3OCH2O) is the particularly preferred polymeri~able monomer. This material has 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.
Dur.ing the i.njecting step the l~ixture of steam, monomer, diluent and catalyst enters the formation as an aerosol with steam vapor compr.ising the gaseous phase and dispersed drops of monomer and acid compri.si.ng the dispersed phase. The multiphase mixture is at or near steam temperature, which is ordinarily greater than the formation temperature. Drops of monomer and acid condense on the sand gra.ins, forming a liquid coating on the sand grai.lls havi.llg suffi.cient thickness to bind the sand grains together. Pol.ymerization occurs quick:l.y in this liquid film, the reaction rate being roughly first order with monomer concentration and pll. At l50C the polymerizati.on occurs in a matter of seconds, while the mi.xture of monomer and aci.d are stable anA unreactive at surface conditions of` 30C for several days.
The furfuryl al.cohol uti.l:ized in our process is so reactive to acid that i.t must be diluted with an appropriate solvent in order to permit it to be dispersed in the steam and injected into the formation Witllout premature reaction. Presence of a diluent accomplishes relatively complete coating of the sand grains in the formation between the sand grains. Any inexpensive solvent for the furfuryl alcohol. monomer would accompl.ish this ob~ective. According:l.y, our preferrecl diluent for the furfuryl 1 7~07458 alcoho~. monomer is a low carbon a:L~ Ihol, and our especially preferred so]vent is methanol.
It is necessary for thi.s procedure that the acid catalyst utilized be non-volatil.e so tllat it remains in the fluid phase of the multiphase treat:ing fluid. This permits thorough mixing of the catalyst with the polymerizable monomer whi.ch i.s essential in or order to ensure that the polymerization reaction occurs uniformly throughout the entire mass of sand contacted by the polymerizable monomer. Prior art methods which utilize a catalyst injected in a non-miscible fluid either before or after injection of the fluid containing the pol.ymerizable 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. It i.s not necessary in our invention that once the fluid is p.l.aced .in the formati.on, it be l.eEt i.n a quiescent state for a lon~ perlod of time sufficient to ensure temperature equalization with the formation, as is required in most prior art methods. The polymerization reaction occurs very rapidly and is completed in a relatively brief period of time, so the well can be put on producti.on i.n a matter of hours.
Our methods are preferably accomplished using the following materi.als and procedures. Our invention is especially successful when applied to formati.ons conta.in.ing unconsolidated sand and heavy oil wh.ich ordinar.ily req~lires steam stimulation to achieve commercial oi:l recove:ry rates. Such formations are typical.ly relatively shal:low, e.g. seldom deeper thall 2,000 feet.
If it i8 desired to apply the metllods of our invention to deeper formations, some modifi.cations to the injection procedures may be required to avoid polymerization i.n the injection line.
It is necessary that a source of steam be available at or near the well. The quality of steam is not critical to our process, and from 50 to 80 percent steam may be used.
1 ~0745~3 A consolida-ting fluid is p ovided on the surface near the well. This fluid is liquid ph~-lst and comprises from 10 to 50 and preferably from 20 to 30 percent by volume of a polymerizable monomer. Furfuryl alcohol is our especially preferred polymerizable monomer because it is inexpensive, readily available, non-toxic, easily auto polymerized by acid, and forms a strong, durable polymer which withstands hostile conditions in a producing well including those associated with steam stimulation.
A diluent is used with furfuryl alcohol to reduce the reaction rate on contact wlth acid. Directly mixing furfuryl alcohol wit~ acid can produce hiqh reaction rates or even an explosion. Any polar organic diluent may be used, but low molecular weight alcohol is the preferred di]uent and methanol is our especially preferred material. Non-polar solvents must not be used since uncontrolled reaction rates including explosions result. The consolidating fluid should contain from 90 to 50 and preferably from 80 to 70 percent by volume polar organic diluent.
The acid used to catalyze the polymerization of the monomer should be non-volatile strong acid. Sulfuric acid and trichloroacetic acid are the preferred acids. The concentration of acid in the treating eluid i.5 very critlcal, since the acid concentration determines the reaction rate o e the polymerization.
Since the reactable monomer and acid are mixed with steam on the surface, the temperature of the fluid will be known, but not easily adjustable; therefore, the acid content of the treating fluid and the concentration of monomer are the primary means for controlling the polymerization rate. It is desired that essentially little or no reaction occur in the injection string before the fluid enters the formation. Since the depth and temperature of the formation are well known and the fluid injection rate is controllable or known, it is possible to adjust the acid content of the treating fluid so po]ymerization occurs 1 3!:)7458 precisely when desired, which is sho~tly after the fluid enters the formation.
The following is a guideli~le for adjusting acid content of the treating fluid for various formation temperatures in order to cause the polymerization to occur at the desired time.
TAsLE 1 Preferred Treating Fluid Acid Content for Various Temperatures Acid Content Temperature (F~ (Normality) Time 73 1 1.5 hr.
.2 9 hr.
.1 17 hr.
.05 32 hr.
194 1 45 sec.
.2 4 min.
.1 8 min.
.05 14 min.
300 1 6 sec.
.2 30 sec.
.1 60 sec.
.05 2 min.
Ordinarily, this fluid is injected relatively fast when using a 1 to 3 inch diameter line in the wellbore carrying treating fluid and steam where the steam generator delivers steam having quality values of from 50 to 80 at a pressure of from 250 to 350 pounds per square inch. Under these conditions the transit time in the injection string will be from 10 to 60 seconds.
In applying our methods, the consolidating fluid described above is mixed with steam on the surface, with the mixture passing through an injection string and into the 1 307~58 formation where consol.i.dation is desired. The consolidating fluid is mixed with steam in a volume ratio in the range of one part consolidating -fluid to from .2 to 1 and preferably . 4 to . 6 parts by volume steam.
The mixture of consolidatin~ fluid and steam forms a two-phase mixture, ideally an aerosol, and enters the formation in that form. The treating fluid droplets coalesce on the sand grains, forming a liquid coating on the said particles. si.nce the dispersed drops of liquid in the aerosol treatin~ fluid include the polymerizabl.e monomer and the acid, the liquid film formed on the sand surface comprises both monomer and acid. As the film forms, the polymer.ization of monomer begins due to contact w.ith acid and proceeds very rapidly. The vapor port:ion of steam maintains the void spaces between monomer-coated sand grains open, which i.nsures that the consolidated sand mass wilL
have sufficient permeab.i].ity to al.:low oil flow there through later, after the coating has cured and oil production has been resumed.
The quantity of the consolldatiny flui.d comprisiny the polymerizable monomer, diluent and catalyst injected i.nto the formation varies depending on the thickness and porosity of the formation to which the sand consolidati.on process is to be applied, as well as the diameter of the well and the desired thickness of the permeable barr.ier in the formation. The thickness and porosity o~ the forn~ati.on and the diameter of the well will always be known, and it l.s ordi.nar:i.J.y satisfactory if depth of the penetrati.on is in the range of from 6 to 12 inches from the well bore.
Since this process does not require completely fi.lling the void space of the portion of the formation being treated with consolidating fluid, the required volume of consolidating fluid is from lO to ~0 percent of the pore space of portion of the formation being treated. As an example, if it is desired to -1.5-4 5 ~
treat a formation whose thickness i5 1; f~.~t and porosity is 35~
to form a permeable barrier just outside the perforations of the wellbore which is ~ inches thick, and t-le well being treated is 10 inches in diameter, then the volum, of fluid necessary is calculated according to the example be ow.
Volume in cubic feet equa].s 2 ~(~)2 x (~It.) x (Porogity) x (0.20) l44 ~2 3 l~(5~2 x 1.8 x (.35) x (0.20) 3.9~5 cubic feet = 29.6 gallons of the fluid comprising monomer, diluent and acid. Since this fluid is mixed with steam in the ratio of ~ to 1, the total volume of treating fluid is 120 gallons.
After the steam and consol.idation fluid is injected, the wel:L should be shut in and l.eft to stand for a period of from 1 to 24 and preferably from 2 to 9 hours to permit completion of the polymerizatlon.
There are situat.ions different from tllese described above when it is desirable to orm a strong, impermeable barrier around a wellbore, such as when excessive water flow is mixin~
with oil produced from an adjacent layer, or when steam override at the producing wel.l in a steam drive project is encoulltered.
These problems can be corrected by formin~ a barrier similar to that described above, except that the barrier has no permeability or very low permeability to fluid flow. A strong, dura~le impermeable barrier can be provided by use of the steam and polymerizable monomer, di.luent and acid injection step described above, by reducing the acidity of the fluid. The lower the acid normality, the slower the pol.ymerization reaction, and the 1 30745~
farther the fluid wiLl travel away fr(n the well before polymerization. A very small amount of brine or other fluid should be pumped down the well tubing to ensure that the monomer-containing fluid is removed therefrom, but the volume o~
fluid should be carefully controlled to ensure that none of the fluid enters the formation. The composition and quantity of the monomer fluid is precisely the same as is described above for sand consolidation use except for the lower acid content. The well should be shut in for from 2 to 9 hours to allow the monomer sufficient time to polymerize completely prior to resumption of oil production.
EXPERIMENTAL
The fo1.lowi.ng laboratory tests were performed and the results are given below.
Our experiments were performed using a plpe section that measured approximately l.S lnches in diameter and 6 lnches in length. The cell. was packed w.ith l~ern River Field ~ormation sample. Kern River crude oil was then injected into the formation material to represent tlle situation that would be encountered in a freshly drilled portion of formation. A
consolidating fluid compri.sing the furfuryl alcoho]., methanol and catalyst as is descri.bed below was mixed with steam and i.njected into the cell. Approximate].y .l ].iters of the monomer fluid was utilized in the treatment process and approximately .02 liters of saturated steam was utilized in each experience.
Example l. A mixture. of 50% furfuryl alcohol in methanol with 0.05 N hydrochlori.c acid resulted ln no consolidation.
Example 2. The same 50% furfuryl alcohol in methanol with acidity of 0.25N HCI plugged the sand pack.
Example 3. A run using 1.0% furfuryl alcohol and 0. 25 N
HCl resulted in sand coating, but no consolidation. Steam was 1 3n7458 injected for six hours after the cons~ idating fluid was injected.
Example ~. A run similar to run 3 was conducted, except the cell was shut in for several hours without passiny steam through the cell. The results were the same as in Example 3.
Example 5. A run using 0.~5 N ~2SO4 plus 20% furfuryl alcohol injected over a period of 5 minutes using 300F steam resulted in consolidation of about 50~ of the sand.
Subsequent tests indicated that the optimum consolidation of 100 percent of the sand occurred when the consolidating fluid contained from 23~ to 27% furfur~l alcohol, with from 77 to 73 percent methanol and sufficient sulfuric acid to result in the fluid acidity being from .25 to .50 N.
A larger scale experimental cell having a volume of 18.0 liters was constructed to permit further testing under conditions much closer to actual field conditions. The cell was heated to controlled temperatures of 300~F similar to subterranean formations. Oil saturated Kern formation sand was packed into the cell. A simulated one inch diameter well was provided in the center of the cell. A steam line was attached to the well to permit introducing 300F steam into the wel:L. The steam line was equipped with valves and back pressure regulato-rs to permit introducing the consolidating fluid into the line to permit mixing of fluid with steam. ~ sample comprising 500 ml.
of fluid (30 percent furfuryl alcohol, 70 percent methanol and 0.5N sulfuric acid) was mixed with steam and injected into the well in our cell. The cell was maintained at 300~F for 6 hours.
After 6 hours, the vat was allowed to cool and the sand was carefully removed from the cell. A strong, permeable consolidated sand mass was present around the well, the average diameter of the mass being twelve (12.0) inches attached to the perforations in the well.
1 3n7~5~
A second experiment using W~ r-saturated Ottawa sand produced the same results.
FIELD EXAMPL.E
For the purpose of complete disclosure, includincJ 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 containing formation, the formation being from 2,540 to 2,588 feet. Considerable sand production has been experienced in other wells completed in this formation in the past, and so it is ¢ontemplated that some treatment must be appl ied i.n order to permit oil production from this formation without experienclng the various problems of unconsolidated sand production. This particular well has not been used for oil. producti.on, 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 particle size to accommodate sand consolidation process using the natural sand present in the formationO It is decided therefore to inject steam and the sand consolidat.ion fluid into the formation immediately adjacent to the perforation of the producing wel.l i.n order to bind the naturally occurr:incJ
sand yrains toyether and form a stable mass which eorms a permeable barrier to restrain the flow of formation sand into the well while still perm;.ttincJ the free flow of formation fluids including petroleum throuc~ll the barrier. It is determined that it is sufficient to treat approxi.mately 12 inches into the formation. ~ased on experience in thi.s fi.eld, it is expected that the porosity of the formation to be treated is approximately ~0%. The outside casiny diameter of the well beiny treated is ~ ~,07~58 ten inches. The volumP of sand conso.lida-ting fluid necessary to treat this portion of formation is delermi.ned as follows:
3 14(1-2 + 12)2 - 3-14 (-2)2 X (o~o) (~) (0.20) = 3.14(17)2 - 3 1~(5)2 X (.40) (48) (0-2~) 1~
- 22.12 Cu.Ft. or 165.5 gallons In order to accomplish ade~uate contact of the portion of the uneonsolidated sand formation adjaeent to the production well, ~ total of 166 ~:l:Lons of sand consoli.dati.ng f.l.u.i.d i.s required. The required volume of sand consolidation treating fluid is formulated by mixing 45 gallons of furfuryl alcohol with 119.0 gallons of methanol to which had previously been added 2.0 gal].ons of sulfuric aeid. The sand eonsolidation fluid is injected into a steam li.ne at the wellhead in a ratio of 90 parts steam to 10 parts sand eonsolidating fluid. Steam temperature i.s 300F. This fluid is injeeted into the formation at a rate of about 1,440 gallons per hour. After all of the kreating flui.d has been injeeted into the format.i.on, the well. is shut i.n eor 6 hours to ensure eomp:l.ete polymerizatl.on. ~t the conelusion oE
this shut-in period, the well is plaeed on produetion and essentially sand-free oi.l produetion is obtained.
Although our invention has been deseribed in terms of a series of speeifie preferred embodiments and illustrative examples whieh applieants believe to include the best mode for applying their invention known to them at the time of this 1 ~07~5~
appli.cation, it will be recognized to t~lose skilled in the art that various modifications may be made to the composition and methods described herein without departing from the true spirit and scope of our invention which is defined more precisely in the claims appended hereinafter below.
_~rET.~_~F~ vRMrI~N
Thi.s invent.ion collce~ me~llnds ~or treati.ng wel.l.s completed in subterraneall forma~:iolls colltai.l~ g unconsoJ.i.dated particul.at:e matter, e.g. (.nlcollsol..i~ated salld, whi.cll ~)i.nd tlle unconsoli.dated sand gl-ai.lls to~Jet:ller in tlle E)ortlons of the formation immediatel.y adjacent t:o t:l~e pereorat-i.ons of tlle wel.]., in order to form a sl:ahle yel s~:ill. e~lnid permeabl.e barri.er around the wellbore, wll.i.cl~ perm.it:~ r)rodnction of f].lli.ds Erom the formation while restra:ini.llg tlle movemellt: Oe sand i.nto the wellbore during the f.l.-l:i.d prodllcl:ioll phase. More parti.cularly, thi.s invention pertains t:c- all inexl~etlsive method foL-accompl.islli.n~ sand consoli(~al:.ioll in l)ro(~ oil wells Ill~ i the sancl naturally prese~ in tlle ~ormcltic~ll alld an inexpellsi.ve method which utiliæes a sllbstalll:i.,lJ.~.y redllced number of procedural steps. Tlle metllo(l 1.ednces tlle l:ime and cost of treatinq wells, and plod-lces ~1 consolidat:ed permeab].e sand-polymer matrix wlli.c:ll re(i~lces movemellt oF sand dnrill~J o;.l producti.on for up to several. yeals, bllt wllicll .i.s more easi.ly removed during workover operati~ s tllan collsoli.dated sand produced by prior art: me~:llo(1s. ;t:il~ more pal-t;.cul.arl.y, thi.s invention`comprises a mel:llod for selecti.vel.y consol.i.datillg sand grai.ns t:ogc3ther i.n t-llc! lonll~ .Idj<l(~c~lll 1() t.lle inlct: oF a 1 307~5~
producing wellbore by use of a mul.tiphas( flui.d compri.sing steam containing a polymeri~ab]e monomer wit}l the catalyst already mixed wi.th the resin in order to achieve more uniform mixing and to reduce the number of steps in prior art methods including first cleaning the sand grains, followed by contacting the sand with sufficient catalyst-containing fluid to deposit catalyst on the sand grain surface, prior to i.njecting the polymerizable resin.
BACKGROlJNn OF TIIE TNVENTION
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 unconsolidated sand production. When wells are completed in petroleum-containing formations which formations also contain unconsolidated granular mineral material such as sand or gravel, production of fluids from -the formatlon causes the flow of the particulate matter into the wellbore, which often leads to any of several diffi.cult and expensive problems. Sometimes a well is said to "sand up", meaning the lower portion of the production wel.l. becomes f:illed with sand, after which further production of flui.d from the formati.on becomes difficult or impossible. In other instances, sand production along with the flllid resul.ts .in passage of granul.ar mineral material into the pump and associated hardware of the producing well, whi.ch causes accel.erated wear of the mechanical components of the producing oil weJ.l. Sustained production of sand sometimes forms a cavity in the formation which coll.apses and destroys the well. A11 of these problems are known to exis-t and many methods have been disclosed in the prior art and applied in oil fields in order to reduce or elimi.nate producti.on of 1 30~4~8 unconsolidated sand from a pekroleum fL, ,iation during the course of oll production.
The above-descri.bed probl,em and potential solutions to the problem have been the subject o-~ extensive research by the petroleum industry in the hope of developing techniques which minimize or eliminate the movement of sand particles into the producing well and associated equipment during the course of producing fluids from the formation. One such general approach suggested in the prior art involves treating the porous, unconsolidated mass sand around the wellbore in order to cement the loose sand grains to~ether, thereby forming a permeable consolidated sand mass which will allow production of fluids but which will restrain the movement of sand particles into the wellbore. The objecti.ve o~ s~lch procedures is to create a permeable barrier or si,eve adjacent to the perforations or other openings in the well casin~ which establish communication between the production formation and the production tubing, wllich restrains the flow of loose particulate mineral matter such as sand. Another approach i.nvolves removing a portion of the formation around the well and packing specially prepared resin-coated granular material into the formation around the wellbore which is subsequently caused to be cemented together.
It is a primary objective oE any operable sand consolidation method that a barri.er be formecl around the wel.lbore which restrains the movement of sand part.i.cles into the well while offering little or no restr:i.ction to the flow of fluids, particularly oil, from the format;.on into the wellbore where it can be pumped to the surface of khe earth.
Another very important quality of a satisfactory sand consolidation method i.s durabili.ty of the permeable barrier formed around the wellbore. Once the barrier is formed and the well is placed on production, there will be a substantial continuing flow of Eluids througll the flow channels wikhln the 1 307~5~
permeable barrier, and it is important ~lat the barrier last for a significant period of time, e.g. seve~ll months and preferably years, without excessive abrasive wear ~ir other deterioration of the consolidation matrix which would canse the particulate matter to once again flow into the well~ore. '~'his is a particularly difficult objective to accomplish in the instance of sand consolidation procedures applied to wells completed in formations subjected to steam flooding or other thermal recovery methods.
The production of fluids in steam flooding operations involve higher temperatures and higher pH fluids than are normally encountered in ordinary primary production, and this greatly aggravates the stability prohlem of sand conso]idation procedures.
An antithetical problem has developed in some of the modern sand consolidation processes. After a year or more of oil production, plugging of the consolidated sand mass filter often occurs and it then becomes necessary to workover the well, removing the plu~ged consolidated sand mass and then ~`orming a new sand consolidating mass in i.ts place. Some resin-consolidated sand filters are so durable that removal of the consolidated sand mass durin~ workover is costly and time-consuming. ~ccordingly, there is an unfulfilled need for sand consolidation methods which are durable eor a reasonable period of time, in the order of one or two years of` production, but which are easy and inexpensive to remove when it becomes necessary to work over the well. Ideally, there is a need for sand consolidation met~lods which restrain the movement of sand during production for a year or more, but which are then more likely to disintegrate than to become plugged.
It is also important that the 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 1 307~58 delay the consolidatlon reaction that ~las lead to multi-step procedures in which first a cata:Lyst is injected into the Eormation, after which the polymerizable resin--containing fluid is i.njected separately. While this :red~lces the propensity for the fluid to polymerize in the :injection string, it does give rise to several problems which consti.tute 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 sand consolidation is accomplished. Second, injection of catalyst into the formation in advance of the polymerizable fluid does not accomplish uniform mixin~ ~ c~talys~ wlth all of the subse~uently-injected polymerizable fluid to the degree necessary to ensure optimum polymerization of the resin, and thus often fails to` achieve maximum, uniform strenyth and ~urability of the consol.i.dated mass. Use of aqueous flui.ds to inject catal.yst often gives rise to the need for yet additional preliminary steps to clean the sand to remove formation petro].eum so the catalyst will be absorbed by the sand and ].ater mi.x with the subsequently injected resin containing fluid.
Many materials have been utilized for consoli.dating sand in the formation ad~acent to production of wel.lbores. One of the more successful agents utili.zed for this purpose are resins comprising oligomers of furEuryl alcohol whi.ch can be polymerized in situ to form a so:l.id matrix which binds the sand grains together, while at the same time offering superior resistance to high temperatures and to ca~lsti.c substances whi.ch may be encountered in steam flood operations. One of the problems in utilizing furfuryl al.cohol oligomers to polymerize i.n the formation for the purpose Oe consolidating sand grains is failing to achieve uniform catalysi.s of the polymerization. Many catalysts that are effective for polymeri.zing furfuryl alcohol resins cannot be admixed with the furfuryl alcohol to permit a 1 307~158 single fluid containing both the resiJ ,nd the catalyst to be injected into the formation, beeause tlli time of polymerization is so short or unpredictable that there is exeessive 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 aleohol, in which the catalyst used is a water soluble aeidie salt, preferably zirconyl chloride, whieh is injected in an aqueous solution into the formation prior to the resin eontaining fluid inject.ion. The salt absorbs on the sand ~rains, and sufficient acidic sa:lt remai.ns adsorbed on the sand grain during the subsequent resin fluid injection stage that adequate polymerization oecurs. Although this has been very effective in most difficult situati.ons where sand consoli.dation procedures are utilized, particularly in connecti.on with thermal flooding such as steam injection procedures, the procedure nevertheless requires a multi-fluld injeetion procedure which requires more time and is more expensive than is desired. Usually a preliminary sand eleanin~ step is required before injecting the aqueous-eatalyst so].ut:i.on in or~er to remove the naturally-oeeurring oi.l film from t~le sand ~rai.ns to ensure good eatalyst adsorption on the sand. Also, althou~h catalyst mixes with the subsequently injected polymer to a lim.ited degree, usually suffieient to eause polymer:izat;.on, it is believed that superior performance would result if t~le eatalyst resin mi.xture can be made more homogenous prior to polymerization, in order to aehieve a dense strong durable eon.soLidation mass.
In U.S. ~,669,543 whi.ch issued June 2, 19~7, there is deseribed a method for eonsolidati.ng sand using an aeid curable resin an~ utilizing as a catalyst, the react.ion product of an aeid and an alkyl metal or ammon;um molybdate. In that instance, the catalyst is incorporated in an aqueous carrier flui.d which eompri.ses the continuous phase of an emulsion in whi.ch the 1 7, 07~58 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 to achieve to the degree of completion and accuracy of timing necessary to accomplish the desired strong durable consolidating matrix necessary for a long lasting sand consolidation process.
In our copending Canadian aPPlication Serial No. 600,499 disclosed sand consolidation methods using an oligomer of furfuryl alcohol, a hydrolyzable ester as combi~ation diluent and water extractor, and an oil soluble acid catalyst. While this produces a durable, temperature resistant permeable consolidated sand sieve, it has sometimes been difficult to remove during workover.
In view of the foregoing review of the current state of the art, it can be appreciated that there is still a substantial unfulfilled need for sand consolidation processes employing a polymerizable material in which complete mixing between the catalyst and the re~in is accomplished prior to the polymerization reaction, in order to ensure that the polymerization reaction proceeds to completion, thus ensuring that the resultant polymer matrix posses the maximum possible strength and durability for the desired time period, but which either self destructs after a period of time or which is easily removed during workover. There ~s also a need for a sand consolidation pro~ess in which the number of separate fluid injection stages is reduced to a minimum of one or two, in order to reduce the time and cost of the sand consolidation method.
SUMMARY OF THE ~NVFNTION
We have discovered novel me~hods for consolidating sand involving the use of a single f~uid comprising steam, polymerizable monomer, preferably furfuryl alcohol, an organic diluent such as a low carbon alcohol and a non-volatile acid cat~lyst which can safely be mixed with the 5team on the surface so a single, multiple phase fluid containing steam, catalyst and the monomer is injected into the unconsolidated sand. It is desired that catalyst action be sufficiently slow at ordinary surface ambient temperatures that there is no danger of premature reaction of the resin resulting in plugging of the surface mixing equipment or the injection string utilized for pumping the polymerizable monomer down the well into the formation.
A preferred embodiment of the pr~sent invention, comprisQs a method for consolidating unconsolidated mineral particles including sand in a ~ubterranean petroleum formation penetrated by a well in fluid communication with at least a portion of the ~ormation, comprising:
(a) providing a ~and consolidating fluid comprising a polymerizable monomer, diluent for the mo~omer, and a non-volatile strong ~cid catalyst capable of causing polymerization of the monomer at fluid injection temperatures;
(b) mixing the sand consolidating fluid with steam to form a multiphase treating fluid;
(c) ~njecting said treating fluid into the formation to occupy the void space of at least a portion of the formation adjacent to the well; and (d) allow~ng the injected fluids to remain in the formations for a period ~f time sufficient to accomplish at least partial polymerization of the monomer, forming a permeable consolidated mass around the wellbore.
1 30745~
Further, according to the present invention, there is provided a method for forming a fluid impermeable zone in a permeable, subterranean oil-containing formation adjacent to a wellbore penetrating said formation, comprising:
a. providing a fluid compri~ing a polymerizable monomer, a diluent for said monomer, and a strong acid catalyst which causes polymerization of the monomer at steam temperatures;
b. forming a mixture of said fluid from step (a) with steam c. injecting said fluid mixture into the formation to saturate at least a portion of the formation; and d. allowing ~aid ~luid Lo remain in the formation for a period of time sufficient to accomplish at least partial polymerization of said monomer, forming a fluid impermeable barrier between the well and the formation.
me catalyst activity is highly d4p3xlrt on fluid pH, te~ature, and monomer concentration. At fluid temperature as low as 194F;
with catalyst incorporated in the treating fluid, polymerization of the monomer will occur in a very short period of time. The preferred embodiment involves preparation of treating fluid on the surface comprising steam and a mixture comprising from 20 to 30 percent polymerizable monomer, preferably furfuryl alcohol, from 80 to 70 percent of a diluent, preferably a low carbon -8a-, - :.. . -..
1 ~n7458 alcohol such as methanol, and sufficient non-volatile, strong acid such as sulfuric acid to produce a fluid comprising the furfuryl alcohol, diluent and acid having an acid normality of from .10 to ~.0 and preferably .25 to .50. The normality of the acid is critical in controlling the reaction rate, control of which is essential to avoid polymerization of the monomer in the injection line, but still have polymerization occur in the formation near the wellbore. Lower acid content is used for deeper formation depth.
The mixture of steam, monomer, diluent and acid is a multiphase mixture, similar to an aerosol. This mixture is B
`, :: L ~
1 ~0745~
injected into the formation wltho~ danyer of premature polymerization. The injected mixtllr~ simultaneously removes and displaces undesired oil and other llaterial coating the sand grains, and accomplishes a thorough cfiating of the sand grains with the monomer catalyst mixture. It: is not necessary to inject salt water or other fluids after injecting the treating fluid to maintain permeability, as the vapor phase of the injected fluid ensures residual permeability of the consolidated sand mass. The well is then shut in for a period of from 2 to 9 hours and preferably at least 6 hours. The preferred shut-in period is a function of the formati.on temperature. This one-step procedure results in the formation of a permeable, durable, consolidated sand mass around the perforations of the wellhore which restrains the movement of sand into khe wellbore duri.ng production operations, whi].e permitting re1atively free flow of formation fluids, particularly formation petroleum, into the wellbore. The thickness of the permeable mass formed around the perforations of the production well casing is determined by the volume of the fluid comprising the polymeri.zi.ncJ monomer and catalyst injected into the formation. Ordinari.ly it is sufficient for our purposes if the volume of pol.ymerized sand is at least 12 inches ln thickness measured Erom the prod~lcti.on well perforations. I~ the thickness exceeds 1~ ialclles, the barrier i.s sti.l:l. ef~:ecti.ve l~llt is unnecessar.ily expens:ive and may be f:low restricting. This procedure results in a permeable mass which is stronqer than previous techniques because the catal.ys-t is more completely dispersed and mixed in the resi.n prior to polymerization than is possible by injecting a fluicl containing the catalyst ei.ther before or after the polymer injection phase, but not so strong that it is clifficult to remove during workover operation due to the relatively thin coating of polymer on the sand grains. The procedure also requires l.ess k:;.me to accomplish i.n the ~iel.d and _g _ 1 7,07~58 is less expensive, because the number of separate injection steps is reduced over other prior art methods.
DETAILED DESCRTPTION OF T~IF._PREFERRED EMBODTMENTS
We have di.scovered, and this constitutes our invention, that it is possible to accomplish improved sand consoli.dation methods utilizlng the sand naturally occurring in the formation in a process employing a single multiphase fluid injection step in whi.ch a mixture of steam, polymerizable monomer, a catalyst for the polymerization of the monomer, and a organic diluent, is injected into the formation to enter the void space in the portion of the ~ormation adjacent to the production well. The injection of steam and polymerization chemicals is roughly analogous to a spray pai.~ting operation applied to ~ wire screen, where the wires are coated but the holes remain open. This method accomplishes coating the formation gran-llar materi.al, e.g.
the formation sand, with the mixture of polymerizable monomer anc catalyst. Since the reactive components of the fluid injected into the formation in this step are organic and contains a diluent, and are at steam temperatures, the minor amounts of formation petroleum and other oi.l-base materials coati.ng anA
contaminating the surface of the sancl grai.ns is effective:Ly removed or dissolved,maki.llg a prior sand cleaning step unnecessary. It .l.s a particul.ar eeature. Oe this method that a preliminary wash step to remove materials coating the sand grains is not required. We have conAucted laboratory tests, using format;.on sand containin~ crude o:i~, to which additional oil was deliberately added, and we still obtained successful consolidation by this method without any preliminary wash step.
1 ~!()7~58 The polymeriza~le monomer ~ ich We have found to be especially preferable ~or use in our sand consol.idation reaction is furfuryl alcohol. Any monomer which will polymerize upon exposure to heat and contact wi.th an ac:id catalyst can be used .in this process; however, furfuryl alcohol (C4T~3OCH2O) is the particularly preferred polymeri~able monomer. This material has 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.
Dur.ing the i.njecting step the l~ixture of steam, monomer, diluent and catalyst enters the formation as an aerosol with steam vapor compr.ising the gaseous phase and dispersed drops of monomer and acid compri.si.ng the dispersed phase. The multiphase mixture is at or near steam temperature, which is ordinarily greater than the formation temperature. Drops of monomer and acid condense on the sand gra.ins, forming a liquid coating on the sand grai.lls havi.llg suffi.cient thickness to bind the sand grains together. Pol.ymerization occurs quick:l.y in this liquid film, the reaction rate being roughly first order with monomer concentration and pll. At l50C the polymerizati.on occurs in a matter of seconds, while the mi.xture of monomer and aci.d are stable anA unreactive at surface conditions of` 30C for several days.
The furfuryl al.cohol uti.l:ized in our process is so reactive to acid that i.t must be diluted with an appropriate solvent in order to permit it to be dispersed in the steam and injected into the formation Witllout premature reaction. Presence of a diluent accomplishes relatively complete coating of the sand grains in the formation between the sand grains. Any inexpensive solvent for the furfuryl alcohol. monomer would accompl.ish this ob~ective. According:l.y, our preferrecl diluent for the furfuryl 1 7~07458 alcoho~. monomer is a low carbon a:L~ Ihol, and our especially preferred so]vent is methanol.
It is necessary for thi.s procedure that the acid catalyst utilized be non-volatil.e so tllat it remains in the fluid phase of the multiphase treat:ing fluid. This permits thorough mixing of the catalyst with the polymerizable monomer whi.ch i.s essential in or order to ensure that the polymerization reaction occurs uniformly throughout the entire mass of sand contacted by the polymerizable monomer. Prior art methods which utilize a catalyst injected in a non-miscible fluid either before or after injection of the fluid containing the pol.ymerizable 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. It i.s not necessary in our invention that once the fluid is p.l.aced .in the formati.on, it be l.eEt i.n a quiescent state for a lon~ perlod of time sufficient to ensure temperature equalization with the formation, as is required in most prior art methods. The polymerization reaction occurs very rapidly and is completed in a relatively brief period of time, so the well can be put on producti.on i.n a matter of hours.
Our methods are preferably accomplished using the following materi.als and procedures. Our invention is especially successful when applied to formati.ons conta.in.ing unconsolidated sand and heavy oil wh.ich ordinar.ily req~lires steam stimulation to achieve commercial oi:l recove:ry rates. Such formations are typical.ly relatively shal:low, e.g. seldom deeper thall 2,000 feet.
If it i8 desired to apply the metllods of our invention to deeper formations, some modifi.cations to the injection procedures may be required to avoid polymerization i.n the injection line.
It is necessary that a source of steam be available at or near the well. The quality of steam is not critical to our process, and from 50 to 80 percent steam may be used.
1 ~0745~3 A consolida-ting fluid is p ovided on the surface near the well. This fluid is liquid ph~-lst and comprises from 10 to 50 and preferably from 20 to 30 percent by volume of a polymerizable monomer. Furfuryl alcohol is our especially preferred polymerizable monomer because it is inexpensive, readily available, non-toxic, easily auto polymerized by acid, and forms a strong, durable polymer which withstands hostile conditions in a producing well including those associated with steam stimulation.
A diluent is used with furfuryl alcohol to reduce the reaction rate on contact wlth acid. Directly mixing furfuryl alcohol wit~ acid can produce hiqh reaction rates or even an explosion. Any polar organic diluent may be used, but low molecular weight alcohol is the preferred di]uent and methanol is our especially preferred material. Non-polar solvents must not be used since uncontrolled reaction rates including explosions result. The consolidating fluid should contain from 90 to 50 and preferably from 80 to 70 percent by volume polar organic diluent.
The acid used to catalyze the polymerization of the monomer should be non-volatile strong acid. Sulfuric acid and trichloroacetic acid are the preferred acids. The concentration of acid in the treating eluid i.5 very critlcal, since the acid concentration determines the reaction rate o e the polymerization.
Since the reactable monomer and acid are mixed with steam on the surface, the temperature of the fluid will be known, but not easily adjustable; therefore, the acid content of the treating fluid and the concentration of monomer are the primary means for controlling the polymerization rate. It is desired that essentially little or no reaction occur in the injection string before the fluid enters the formation. Since the depth and temperature of the formation are well known and the fluid injection rate is controllable or known, it is possible to adjust the acid content of the treating fluid so po]ymerization occurs 1 3!:)7458 precisely when desired, which is sho~tly after the fluid enters the formation.
The following is a guideli~le for adjusting acid content of the treating fluid for various formation temperatures in order to cause the polymerization to occur at the desired time.
TAsLE 1 Preferred Treating Fluid Acid Content for Various Temperatures Acid Content Temperature (F~ (Normality) Time 73 1 1.5 hr.
.2 9 hr.
.1 17 hr.
.05 32 hr.
194 1 45 sec.
.2 4 min.
.1 8 min.
.05 14 min.
300 1 6 sec.
.2 30 sec.
.1 60 sec.
.05 2 min.
Ordinarily, this fluid is injected relatively fast when using a 1 to 3 inch diameter line in the wellbore carrying treating fluid and steam where the steam generator delivers steam having quality values of from 50 to 80 at a pressure of from 250 to 350 pounds per square inch. Under these conditions the transit time in the injection string will be from 10 to 60 seconds.
In applying our methods, the consolidating fluid described above is mixed with steam on the surface, with the mixture passing through an injection string and into the 1 307~58 formation where consol.i.dation is desired. The consolidating fluid is mixed with steam in a volume ratio in the range of one part consolidating -fluid to from .2 to 1 and preferably . 4 to . 6 parts by volume steam.
The mixture of consolidatin~ fluid and steam forms a two-phase mixture, ideally an aerosol, and enters the formation in that form. The treating fluid droplets coalesce on the sand grains, forming a liquid coating on the said particles. si.nce the dispersed drops of liquid in the aerosol treatin~ fluid include the polymerizabl.e monomer and the acid, the liquid film formed on the sand surface comprises both monomer and acid. As the film forms, the polymer.ization of monomer begins due to contact w.ith acid and proceeds very rapidly. The vapor port:ion of steam maintains the void spaces between monomer-coated sand grains open, which i.nsures that the consolidated sand mass wilL
have sufficient permeab.i].ity to al.:low oil flow there through later, after the coating has cured and oil production has been resumed.
The quantity of the consolldatiny flui.d comprisiny the polymerizable monomer, diluent and catalyst injected i.nto the formation varies depending on the thickness and porosity of the formation to which the sand consolidati.on process is to be applied, as well as the diameter of the well and the desired thickness of the permeable barr.ier in the formation. The thickness and porosity o~ the forn~ati.on and the diameter of the well will always be known, and it l.s ordi.nar:i.J.y satisfactory if depth of the penetrati.on is in the range of from 6 to 12 inches from the well bore.
Since this process does not require completely fi.lling the void space of the portion of the formation being treated with consolidating fluid, the required volume of consolidating fluid is from lO to ~0 percent of the pore space of portion of the formation being treated. As an example, if it is desired to -1.5-4 5 ~
treat a formation whose thickness i5 1; f~.~t and porosity is 35~
to form a permeable barrier just outside the perforations of the wellbore which is ~ inches thick, and t-le well being treated is 10 inches in diameter, then the volum, of fluid necessary is calculated according to the example be ow.
Volume in cubic feet equa].s 2 ~(~)2 x (~It.) x (Porogity) x (0.20) l44 ~2 3 l~(5~2 x 1.8 x (.35) x (0.20) 3.9~5 cubic feet = 29.6 gallons of the fluid comprising monomer, diluent and acid. Since this fluid is mixed with steam in the ratio of ~ to 1, the total volume of treating fluid is 120 gallons.
After the steam and consol.idation fluid is injected, the wel:L should be shut in and l.eft to stand for a period of from 1 to 24 and preferably from 2 to 9 hours to permit completion of the polymerizatlon.
There are situat.ions different from tllese described above when it is desirable to orm a strong, impermeable barrier around a wellbore, such as when excessive water flow is mixin~
with oil produced from an adjacent layer, or when steam override at the producing wel.l in a steam drive project is encoulltered.
These problems can be corrected by formin~ a barrier similar to that described above, except that the barrier has no permeability or very low permeability to fluid flow. A strong, dura~le impermeable barrier can be provided by use of the steam and polymerizable monomer, di.luent and acid injection step described above, by reducing the acidity of the fluid. The lower the acid normality, the slower the pol.ymerization reaction, and the 1 30745~
farther the fluid wiLl travel away fr(n the well before polymerization. A very small amount of brine or other fluid should be pumped down the well tubing to ensure that the monomer-containing fluid is removed therefrom, but the volume o~
fluid should be carefully controlled to ensure that none of the fluid enters the formation. The composition and quantity of the monomer fluid is precisely the same as is described above for sand consolidation use except for the lower acid content. The well should be shut in for from 2 to 9 hours to allow the monomer sufficient time to polymerize completely prior to resumption of oil production.
EXPERIMENTAL
The fo1.lowi.ng laboratory tests were performed and the results are given below.
Our experiments were performed using a plpe section that measured approximately l.S lnches in diameter and 6 lnches in length. The cell. was packed w.ith l~ern River Field ~ormation sample. Kern River crude oil was then injected into the formation material to represent tlle situation that would be encountered in a freshly drilled portion of formation. A
consolidating fluid compri.sing the furfuryl alcoho]., methanol and catalyst as is descri.bed below was mixed with steam and i.njected into the cell. Approximate].y .l ].iters of the monomer fluid was utilized in the treatment process and approximately .02 liters of saturated steam was utilized in each experience.
Example l. A mixture. of 50% furfuryl alcohol in methanol with 0.05 N hydrochlori.c acid resulted ln no consolidation.
Example 2. The same 50% furfuryl alcohol in methanol with acidity of 0.25N HCI plugged the sand pack.
Example 3. A run using 1.0% furfuryl alcohol and 0. 25 N
HCl resulted in sand coating, but no consolidation. Steam was 1 3n7458 injected for six hours after the cons~ idating fluid was injected.
Example ~. A run similar to run 3 was conducted, except the cell was shut in for several hours without passiny steam through the cell. The results were the same as in Example 3.
Example 5. A run using 0.~5 N ~2SO4 plus 20% furfuryl alcohol injected over a period of 5 minutes using 300F steam resulted in consolidation of about 50~ of the sand.
Subsequent tests indicated that the optimum consolidation of 100 percent of the sand occurred when the consolidating fluid contained from 23~ to 27% furfur~l alcohol, with from 77 to 73 percent methanol and sufficient sulfuric acid to result in the fluid acidity being from .25 to .50 N.
A larger scale experimental cell having a volume of 18.0 liters was constructed to permit further testing under conditions much closer to actual field conditions. The cell was heated to controlled temperatures of 300~F similar to subterranean formations. Oil saturated Kern formation sand was packed into the cell. A simulated one inch diameter well was provided in the center of the cell. A steam line was attached to the well to permit introducing 300F steam into the wel:L. The steam line was equipped with valves and back pressure regulato-rs to permit introducing the consolidating fluid into the line to permit mixing of fluid with steam. ~ sample comprising 500 ml.
of fluid (30 percent furfuryl alcohol, 70 percent methanol and 0.5N sulfuric acid) was mixed with steam and injected into the well in our cell. The cell was maintained at 300~F for 6 hours.
After 6 hours, the vat was allowed to cool and the sand was carefully removed from the cell. A strong, permeable consolidated sand mass was present around the well, the average diameter of the mass being twelve (12.0) inches attached to the perforations in the well.
1 3n7~5~
A second experiment using W~ r-saturated Ottawa sand produced the same results.
FIELD EXAMPL.E
For the purpose of complete disclosure, includincJ 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 containing formation, the formation being from 2,540 to 2,588 feet. Considerable sand production has been experienced in other wells completed in this formation in the past, and so it is ¢ontemplated that some treatment must be appl ied i.n order to permit oil production from this formation without experienclng the various problems of unconsolidated sand production. This particular well has not been used for oil. producti.on, 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 particle size to accommodate sand consolidation process using the natural sand present in the formationO It is decided therefore to inject steam and the sand consolidat.ion fluid into the formation immediately adjacent to the perforation of the producing wel.l i.n order to bind the naturally occurr:incJ
sand yrains toyether and form a stable mass which eorms a permeable barrier to restrain the flow of formation sand into the well while still perm;.ttincJ the free flow of formation fluids including petroleum throuc~ll the barrier. It is determined that it is sufficient to treat approxi.mately 12 inches into the formation. ~ased on experience in thi.s fi.eld, it is expected that the porosity of the formation to be treated is approximately ~0%. The outside casiny diameter of the well beiny treated is ~ ~,07~58 ten inches. The volumP of sand conso.lida-ting fluid necessary to treat this portion of formation is delermi.ned as follows:
3 14(1-2 + 12)2 - 3-14 (-2)2 X (o~o) (~) (0.20) = 3.14(17)2 - 3 1~(5)2 X (.40) (48) (0-2~) 1~
- 22.12 Cu.Ft. or 165.5 gallons In order to accomplish ade~uate contact of the portion of the uneonsolidated sand formation adjaeent to the production well, ~ total of 166 ~:l:Lons of sand consoli.dati.ng f.l.u.i.d i.s required. The required volume of sand consolidation treating fluid is formulated by mixing 45 gallons of furfuryl alcohol with 119.0 gallons of methanol to which had previously been added 2.0 gal].ons of sulfuric aeid. The sand eonsolidation fluid is injected into a steam li.ne at the wellhead in a ratio of 90 parts steam to 10 parts sand eonsolidating fluid. Steam temperature i.s 300F. This fluid is injeeted into the formation at a rate of about 1,440 gallons per hour. After all of the kreating flui.d has been injeeted into the format.i.on, the well. is shut i.n eor 6 hours to ensure eomp:l.ete polymerizatl.on. ~t the conelusion oE
this shut-in period, the well is plaeed on produetion and essentially sand-free oi.l produetion is obtained.
Although our invention has been deseribed in terms of a series of speeifie preferred embodiments and illustrative examples whieh applieants believe to include the best mode for applying their invention known to them at the time of this 1 ~07~5~
appli.cation, it will be recognized to t~lose skilled in the art that various modifications may be made to the composition and methods described herein without departing from the true spirit and scope of our invention which is defined more precisely in the claims appended hereinafter below.
Claims (21)
1. A method for consolidating unconsolidated mineral particles including sand in a subterranean petroleum formation penetrated by a well in fluid communication with at least a portion of the formation, comprising:
(a) providing a sand consolidating fluid comprising a polymerizable monomer, diluent for the monomer, and a non-volatile strong acid catalyst capable of causing polymerization of the monomer at fluid injection temperatures;
(b) mixing the sand consolidating fluid with steam to form a multiphase treating fluid;
(c) injecting said treating fluid into the formation to occupy the void space of at least a portion of the formation adjacent to the well; and (d) allowing the injected fluids to remain in the formations for a period of time sufficient to accomplish at least partial polymerization of the monomer, forming a permeable consolidated mass around the wellbore.
(a) providing a sand consolidating fluid comprising a polymerizable monomer, diluent for the monomer, and a non-volatile strong acid catalyst capable of causing polymerization of the monomer at fluid injection temperatures;
(b) mixing the sand consolidating fluid with steam to form a multiphase treating fluid;
(c) injecting said treating fluid into the formation to occupy the void space of at least a portion of the formation adjacent to the well; and (d) allowing the injected fluids to remain in the formations for a period of time sufficient to accomplish at least partial polymerization of the monomer, forming a permeable consolidated mass around the wellbore.
2. A method recited in Claim 1 wherein the monomer is furfuryl alcohol.
3. A method as recited in Claim 2 wherein the concentration of the furfuryl alcohol is from 10 to 50 percent by volume based on the total volume of the sand consolidating fluid.
4. A method as recited in claim 2 wherein the concentration of furfuryl alcohol is from 20 to 30 percent by volume based on the total volume of the sand consolidating fluid.
5. A method as recited in Claim 1 wherein the diluent is a low molecular weight alcohol.
6. A method as recited in Claim 5 wherein the diluent is methanol.
7. A method as recited in Claim 5 wherein the concentration of alcohol in the sand consolidating fluid is from 90 to 50 percent by volume.
8. A method as recited in Claim 5 wherein the concentration of alcohol in the sand consolidating fluid is from 80 to 70 percent by volume.
9. A method as recited in Claim 1 wherein the catalyst is sulfuric acid.
10. A method as recited in Claim 1 wherein the concentration of acid catalyst in the sand consolidating fluid is from .1 to 1.0 normal.
11. A method as recited in Claim 1 wherein the concentration of acid catalyst in the sand consolidating fluid is from .25 to .5 normal.
12. A method as recited in Claim 1 wherein the volume ratio of sand consolidating fluid to steam is from 0.2 to 1.
13. A method as recited in Claim 1 wherein the volume of sand consolidating fluid is sufficient to substantially coat the sand grains in the portion of the formation adjacent to the producing well for a distance up to 12 inches from the well.
14. A method as recited in Claim 1 wherein the acid content of the sand consolidating fluid is adjusted to cause polymerization to occur after a time slightly greater than the time required for the steam and sand consolidating fluid to be injected into the formation.
15. A method as recited in Claim 1 wherein the fluids are left in the formation for a period of at least 6 hours.
16. A method for forming a fluid impermeable zone in a permeable, subterranean oil-containing formation adjacent to a wellbore penetrating said formation, comprising a. providing a fluid comprising a polymerizable monomer, a diluent for said monomer, and a strong acid catalyst which causes polymerization of the monomer at steam temperatures;
b. forming a mixture of said fluid from step (a) with steam c. injecting said fluid mixture into the formation to saturate at least a portion of the formation; and d. allowing said fluid to remain in the formation for a period of time sufficient to accomplish at least partial polymerization of said monomer, forming a fluid impermeable barrier between the well and the formation.
b. forming a mixture of said fluid from step (a) with steam c. injecting said fluid mixture into the formation to saturate at least a portion of the formation; and d. allowing said fluid to remain in the formation for a period of time sufficient to accomplish at least partial polymerization of said monomer, forming a fluid impermeable barrier between the well and the formation.
17. A method as recited in Claim 16 wherein said monomer is furfuryl alcohol.
18. A method as recited in Claim 16 wherein said diluent is a low molecular weight alcohol.
19. A method as recited in Claim 18 wherein said alcohol is methanol.
20. A method as recited in Claim 16 wherein said acid is sulfuric acid.
21. A method as recited in Claim 16 wherein the acid content of the fluid comprising monomer, diluent and catalyst is adjusted to cause the polymerization of monomer to occur after a time slightly greater than the lime required for the fluid to be injected into the formation and to be displaced to a desired location in the formation.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US23937388A | 1988-09-01 | 1988-09-01 | |
| US239,373 | 1988-09-01 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1307458C true CA1307458C (en) | 1992-09-15 |
Family
ID=22901888
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000600506A Expired - Fee Related CA1307458C (en) | 1988-09-01 | 1989-05-24 | Sand consolidation methods |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1307458C (en) |
-
1989
- 1989-05-24 CA CA000600506A patent/CA1307458C/en not_active Expired - Fee Related
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