Note: Descriptions are shown in the official language in which they were submitted.
~ 3~7458
s~-N~ TJln~ (?~ s
n L~
_~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
--3--
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.
1 307458
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.
8-
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.
--10--
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
-14-
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)
144
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
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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
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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.
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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
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~ ~,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)
144
= 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
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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.
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