Note: Descriptions are shown in the official language in which they were submitted.
I So
This invention relates to a method for treating
earthen formations, particularly those formations which
contain clay, shale or other fines to improve the flow of
fluid through the formation. More particularly the
invention relates to such a method wherein the movement of
fines and swelling of water sensitive fines is minimized,
any decrease in the permeability of the formation upon
contact with water is minimized, the permeability is
increased, and the viscosity of any oil in the formation
is decreased.
Many earthen formations contain clays, shales,
and/or fines, such as silt-sized or smaller particles.
The formation can be exposed at the surface of the earth,
e.g., roadbeds, hillsides and the like, or it can be a
subterranean formation, including both those just below or
near the surface, in which formations, footings or walls
of structures rest, and those a substantial distance below
the surface, from which oil, gas, or other fluids can be
produced.
When contacted by water, water-sensitive clays
and shales, for example montmorillonite, can swell and
decrease the permeability of the formation. Other non-
clay fines often are free to move and tend to be carried
along with a fluid flowing through the formation until
they become lodged in pore throats, i.e., the smaller
interstices between the grains of the formation. This at
least partially plugs the openings and reduces the Perle
ability of the formation. Thus, finely divided paretic-
slate matter can obstruct flow through a formation by
swelling, migration, or both.
--1--
~3';7~i6
when footings or foundations of buildings rest
in formations containing such fines, damage or at least
great inconvenience often stems from the inability of the
earth to carry away water due to decreased permeability of
the formation when wet. Likewise, drainage of formations
surrounding septic tanks and underlying roadbeds is
desirable.
One common instance in which fluids are produced
from or injected into formations is in connection with the
production of oil. Often it is desired to treat oil
bearing formations to increase the amount of oil recover-
able therefrom. One popular method is to inject steam
into the formation. The steam can be either dry or wet,
i.e., it can contain a liquid water phase. In some
instances, steam is injected via a well, the well is then
shut in temporarily and allowed to soak, and subsequently
production is commenced from this same well In other
instances, steam is injected via one well and acts as a
drive fluid to push oil through the formation to one or
more offset wells through which the oil is produced. In
either instance, when the steam reaches the subterranean
formation, it at least partially condenses, thus exposing
the formation rocks to fresh water. Even through the
steam may act to mobilize the oil in the formation, it the
formation contains fines and water sensitive clays, the
permeability of the formation can be reduced as a result
of the contact of the fines by the fresh water, the
increase in oil production can be lower than expected,
and t in some instances, production can even he lower than
before the treatment.
-2-
In another instance, a fines-containing subtler-
reunion formation penetrated by a well may require stimuli-
lion because of water damage which occurred during drill-
in or fracturing operations.
Various treatments have been proposed to stab-
live clays in a formation Such treatments include
injecting into the formation solutions containing such
material as potassium hydroxide, sodium silicate, hydroxy-
aluminum, organic acid chrome complexes, organic polymers,
and salts of a hydrous oxide-forming metal such as zircon
Nemo oxychloride. While each of these treatments has met
with some success in particular applications, the need
exists for a further improved method for treating a fines-
; containing formation to minimize the adverse effect of the
fines on formation permeability, particularly when such a
formation is contacted by a fluid containing water.
Briefly, the invention provides a method for treating earthen formations, particularly those which
contain finely divided particulate matter. The method
involves:
(a) injecting into the formation an organ-
silicon compound, selected from the group consisting of
Solon halides, organosilane hydrides, organosilane
alkoxides, and organosilane amine, in which an organ-
Solon halide, hydrides or amine has the formula:
1 1
R2- -So - R
I
65~
wherein R is a halogen, hydrogen, or an amine radical
which can be substituted with hydrogen, organic radicals,
or sill groups, R] is hydrogen, an amine, or an organic
radical having from 1 to 50 carbon atoms, and R2 and R3
are hydrogen or the same or different halogens, amine, or
organic radicals having from 1 to 50 carbon atoms, and in
which an organosilane alkoxide has the formula:
~R4
R5 I - OR
R6
wherein R4, R5, and R6 are independently selected from
hydrogen, amine, halogen, alkoxide, and organic radicals
having from 1 to 50 carbon atoms, and R7 is an organic
radical having from 1 to 50 carbon atoms; and
(b) subsequently, injecting steam, to which has
been added a compound containing ammonia Cal nitrogen,
selected from the group consisting of ammonium hydroxide,
ammonium salts of inorganic acids, ammonium salts of
carboxylic acids, qua ternary ammonium halides, amine or
substituted amine hydrochloride, derivatives of ammonium
Senate, and water-soluble ammonia or ammonium ion precut-
sons selected from the group consisting of asides of
carbamic acid and thiocarbamic acid, derivatives of such
asides, tertiary carboxylic acid asides and their sub-
stituted and alkylated derivatives characterized by the
formula
. Y R
If 19
R8 - C - N
Rho
eye
wherein (1) R8 is hydrogen or an organic radical, (2) Rug
and Rio are independently selected from hydrogen and
organic radicals/ and (3) Y is oxygen or sulfur.
I've invention further provides a method for
treating subterranean formations which contain formation
fines to minimize impairment of formation permeability due
to the presence of the formation fines comprising:
(a) injecting into the formation about 0.5 to
100 gallons per vertical foot of formation to be treated
of (i) an organosilane halide having the formula:
Al
R2 - So - R
R3
wherein R is a halogen, Al is an alkyd, alkenyl, or aureole
group having from 1 to 18 carbon atoms and R2 and R3 are
the same or different halogens, or alkyd, alkenyl, or aureole
groups having from 1 to 18 carbon atoms; or (ii) an
organosilane alkoxide having the formula:
lo
R - So OR
R6
wherein R4, R5, and R6 are independently selected from
hydrogen, amine, alkyd, alkenyl, aureole, and carbohydroxyl
groups having from 1 to 18 carbon atoms, and R7 is so-
looted from an amine, ally]., alkenyl, and aureole group
having from 1 to 18 carbon atoms; and
(b) subsequently, injecting steam steam gent
crated from about 250 to 3,000 barrels of feed water per
vertical foot of formation to be treated, said steam
containing about 0.1 to 25 percent by weight, based on the
US
weight of boiler feed water used to generate the steam, of
a compound containing ammonia Cal nitrogen, selected from
the group consisting of ammonium hydroxide, ammonium salts
of inorganic acids, ammonium salts of carboxylic acids,
qua ternary ammonium halides, amine or substituted fine
hydrochloride, derivatives of ammonium Senate, and
water-soluble ammonia or ammonium ion precursors selected
from the group consisting of asides of carbamic acid and
thiocarbamic acid, derivatives of such asides, tertiary
carboxylic acid asides and their substituted and alkylated
derivatives characterized by the formula:
Y I
If
R8 - C - N
Rio
wherein (1) R8 is hydrogen, an alkyd group containing 1 to
about 8 carbon atoms, or an alpha-hydroxy substituted
alkyd group containing 1 to about carbon atoms, (2) I
and Rho are independently selected from hydrogen and alkyd
groups containing 1 to about 8 carbon atoms, and (3) Y is
oxygen or sulfur.
The invention further provides a method for
: treating an earthen formation to stimulate the flow of
fluids through the formation comprising:
(a) injecting into the formation 0.5 to ].00
gallons per vertical foot of formation to be treated of an
alkylated amine substituted organosilane alkoxide, as a
solution, up to about 50 percent by volume, in a heckler-
carbon carrier liquid selected from the group consisting
of crude oils, aliphatic hydrocarbons, aromatic hydrocar~
~3'765~
bony and petroleum distillation products, which solution
further contains a polymerization catalyst; and
(b) subsequently, injecting steam generated
from about 250 to 3,000 barrels of feed water per vertical
foot of formation to be treated, said steam containing
about 0.1 to 25 percent by weight, based on the weight of
boiler feed water used to generate the steam, of a compound
which contains ammonia Cal nitrogen, selected from the
group consisting of ammonium salts of inorganic acids and
asides of carbamic acid.
Also provided by the invention is a method for
enhanced oil recovery from a subterranean formation
penetrated by a well wherein steam is injected into the
formation, which comprises:
(a) injecting into the formation 0.5 to 100
gallons per vertical foot of formation to be treated of an
alkylated amine substituted organosilane alkoxide as a
solution, up to about 50 percent by volume, in a hydrocar
bun carrier liquid selected from the group consisting of
I crude oils, aliphatic hydrocarbons, aromatic hydrocarbons,
and petroleum distillation products, which solution
further contains a polymerization catalyst; and
tub) subsequently, injecting steam generated
from about 250 to 3,000 barrels of feed water per Jertical
foot of formation to be treated, said steam containing
ablate 0.1 to 25 percent by weight, based on the weight of
boiler feed water used to generate the steam, of a compound
containing ammonia Cal nitrogen, selected from -the group
consisting of ammonium salts of inorganic acid and asides
of carbamic acid.
I
If the earthen formation is a subterranean
formation, the treatment can be part of a method for
enhanced oil recovery or a method for stimulating product
lion from a formation penetrated by one or more wells.
Most formations, regardless of their composition,
contain at least some fines, detrital material or authi-
genie material which are not held in place by the natural
cementations material that binds the larger formation
particles, but instead are loose in the formation or
become dislodged from the formation when fluid is passed
through the formation as a result of rainfall, flow of
ground water or during production of formation fluids via
a well penetrating the formation or injection of fluids
into the formation from the surface or via a well. The
loose fines tend to become dispersed in the fluids passing
through the formation no migrate along with the fluid.
They are carried along and are either carried all the way
through the formation and can be produced if the fluid is
flowing to a well, or they can become lodged in the
formation in constrictions or pore throats and thus reduce
formation permeability. In addition, if the fines are
clays or shale which swell in the presence of water and
the fluid passing through the formation is or contains
water, permeability reduction can occur due to swelled
clay or shale particles occupying a greater proportion of
the formation pore volume.
oration fines can be incorporated into the
formation as it is deposited over geologic time, or in the
case of subterranean formations, can be introduced into
the formation during drilling and completion operations.
so
Fines are present to some extent in most sandstones,
shales, limestones, dolomite, and the like. Problems
associated with the presence of fines are often most
pronounced in sandstone-containing formations. "Formation
fines" are defined as particles small enough to pass
through the smallest mesh sieve commonly available (400
US. Mesh, or 37 micron openings). The composition of the
fines can be widely varied, as there are many different
materials present in subterranean formations. broadly
fines may be classified as being quartz, other minerals
such as feldspar, Muscovite calcite, dolomite and
Burt; water-swellable clays such as montmorillomite,
beidellite, nontronite, sapient, hectorite, and sequent,
with montmorillonite being the clay material most commonly
encountered; non-water-swellable clays such as coolant
and islet; shales; and amorphous materials.
In the broad sense a permeable formation is
"treated" with a fluid by injecting therein the fluid
which flows through the pores and contacts the formation
rock. In treating a substantial volume of a formation,
for example the drainage area of a subterranean oil-
bearing formation penetrated by a well, the volume of
fluid required to treat the entire formation can be quite
large.
The combination treatment of this invention
provides a method for improving the flow of fluids through
a substantial volume of a formation. Treatment of the
formation with a slug of an oxganosilicon compound is
believed to coat the formation fines contacted, binding
them in place and restricting their subsequent movement
I 7~5~
during passage of a fluid through the formation, thus
primarily maintaining the permeability of the formation in
the vicinity of the Wilbur. Treatment: with an organ-
silicon compound is primarily intended to stabilize
permeability rather than increase it but, in some cases,
it may also increase the permeability of the formation.
It does little to affect the viscosity of any oil present
in the formation. Injection of a slug of steam, contain-
in a compound which contains ammonia Cal nitrogen lowers
the viscosity of oil in the formation, rendering it more
easily displaced and recovered. The ammonia Cal nitrogen
compound in the steam stabilizes fines, rendering them
less lawlessly to reduce permeability when a water-containing
fluid passes through the formation, and, in some instances,
increases the permeability of the formation compared to
what it was prior to the treatment, i.e., stimulates the
formation. Thus, the combination of the two treatments,
sequentially carried out, stabilizes or improves the
permeability of a maximum volume of the formation, espy-
Shelley a fines-containing formation.
There is an advantage to treating with both
types of material, in the sequence described herein,
rather than treating with only one material. Used alone,
an organosilicon compound is limited in formation coverage.
As a pretreatment, an organosilicon compound penetrates
the formation to a much more shallow depth than that
reached by steam. Further, vertical coverage of a product
in interval will usually not be even: some zones can
receive much of the treatment, while other zoner. receive
little or no treatment. It, following treatment with an
--10--
~3~7~
organosilicon compound, steam it injected, much of the
formation will not have been protected. However, by
adding ammonia Cal nitrogen to the steam, the nitrogen,
being present in both the liquid and vapor phases, will
act to stabilize much of the formation against fines
movement. Although better coverage is obtained by ammo-
Nikolai nitrogen in the steam, organosilicon compounds
provide superior fines stabilization in many formations,
preventing permeability losses near the Wilbur, which
would normally be observed if ammonia Cal nitrogen is used
alone.
Among the organosilicon compounds suitable for
use in this invention are organosilane halides, organ-
Solon hydrides, and organosilane amine having the
formula:
R2 So - R
R3
wherein R is a halogen, hydrogen, or an amine radical
which can be substituted with hydrogen, organic radicals,
or sill groups, R1 is hydrogen, an amine, or an organic
radical having from 1 to 50 carbon atoms, and R2 and R3
are hydrogen or the same or different halogens, aminesr or
organic radicals having from 1 to 50 carbon atoms.
Preferably, R is a halogen selected from the group consist-
in of chlorine, bromide, and iodine, with chlorine being
most preferred, R1 is an alkyd, alkenyl, or aureole group
having from 1 to 18 carbon atoms, and R2 and R3 are the
same or different halogens, or alkyd, alkenyl, or aureole
groups having from 1 to 18 carbon atoms.
I
Suitable specific organosilane halides include
methyldiethylchlorosi]ane, dimethyldichlorosilane, methyl-
trichlorosilane, dimethyldibromosilane, diethyldiiodo-
Solon, di.propyldichlorosilane, dipropyldibromosilarle,
butyltrichlorosilane t phenyltribromosilane, diphenyldi~
chlorosilane, tolyltribromosilane, methylphenyldichloro-
Solon, and the like.
Also suitable for use in this invention are
organosilane alkoxides having the formula:
R4
R5 So - OR
R6
wherein R4, R5, and R6 are independently selected from
hydrogen, amine, halogen, alkoxide, and organic radicals
having from 1 to 50 carbon atoms, provided not all of R4,
R5, and R6 are hydrogen, and R7 is an organic radical
having from 1 to 50 carbon atoms. Preferably, R4, R5, and
R6 are independently selected from hydrogen, amine, alkyd,
alkenyl, aureole, and carbohydroxyl groups having from 1 to
18 carbon atoms, with at least one of the R4, R5, and R6
groups not being hydrogen, and R7 is selected from amine,
alkyd, alkenyl, and aureole groups having from 1 to 18 carbon
atoms. When R4, R5, and/or R6 are carbohydroxyl groups,
alkoxy groups are preferred.
Suitable organosilane alkoxides include divinely-
dimethoxysilane, divinyldi-2-methoxyethoxy Solon, Dow-
glycidoxypropyl) dimethoxysilane, vinyltriethoxysilane,
vinyltrls-2-methoxyethoxysilane, 3-glycidoxypropyltri-
methoxysilane~ 3-methacryloxypropyltrimethoxysilane,
2-(3,4 epoxycyclohexyl) ethyltrimethoxysilane, Newman-
-12-
~37656
ethyl-3-propylmethyldimethoY~ysilane, N-2-aminoethyl-3-
propylmethyldimethoxysilane, N-2-aminoethyl-3-aminopropyl-
trimethoxysilane, 3-aminopropyltriethoxysilane, N-[2-amlno-
ethyl)-3-aminopropyltrimetho~ysilane, and the like.
Preferred organosilane allcox:ides include the
amine containing sullenness, for example 3-aminopropyltri-
ethoxysilane. The presence of the amine function appears
to result in a stronger adsorption of the Solon on the
formation rock. The resultant polymer renders the treated
portion of the formation less oil-wet than when a non-
-amine-containing Solon is employed. Thus, in subsequent
production of oil through the formation, less oil is
retained by the formation and more of the oil is produced.
The amount of organosilicon compound which can
be used varies widely depending on such factors as the
characteristics of the particular compound employed, the
nature, permeability, temperature, and other characters-
tics of the subterranean formation, and the like. con-
orally, the organosilicon compound is employed in an
amount sufficient to maintain the rate of flow of liquid
through the formation at a relatively constant rate
following a treatment. Often, this is an amount suffix
client to coat a substantial portion of the formation
fines. Typically, about 0.5 to 100 gallons, per vertical
foot of formation to be treated, of the or~anosilicon
compound is employed
The organosilicon compounds, hereinafter no-
furred to as "Solon material," can be injected either
with or without a hydrocarboll carrier liquid. It is
preferred to utilize a hydrocarbon carrier liquid since,
-13
I
with carrier-containing solutions, there is lest opera
unity for the Solon material to contact water and at
least partially react during its passage down the well
conduit and through the formation in the immediate vial-
nit of the Wilbur. The Solon material either alone or
mixed with a hydrocarbon carrier liquid passes readily
through a permeable formation However, reacted Solon
material tends to plate out on the face of the formation
and penetrates the formation only to a limited extent.
Suitable hydrocarbon carrier liquids include crude oil,
aliphatic hydrocarbons such as hexane, aromatic hydrocar-
buns such as Ben one or Tulane, or petroleum distillation
products or fractions such as kerosene, naphthas or diesel
fuel. Preferably, solutions of about 0.2 to 50 percent by
volume Solon material in hydrocarbon carrier are employed
While the reaction of the Solon material with
materials in the formation is not completely understood,
and while the invention is not to be held to any paretic-
ular theory of operation, it is believed that the Solon
material condenses on and reacts with active sites on
siliceous surfaces with which it comes in contact to form
a polymer. It is believed that the Solon monomer first
hydrolyzes and forms a reactive intermediate and either an
acid or alcohol depending on the type of monomer:
R it
R-fi-OR H20 R-fi-OH + HO
R R
X X
Six + HO R-Si-OH + HO
X X
Lo 7656
The reactive intermediates, "silanols," then
condense to begin formation of the polymer.
R R R R
R-Si-OH + Hoosier R-Si-O-Si-R HO
I
R R R R
The growth of the polymer can proceed as hydrol~
Isis and condensation continue.
The sullenly can also react with active sites on
the rock to covalently bind the polymer to it:
.10
Irk Surface I
-Sue Hess -Swiss
Jo
O + Jo O -~2H20
-Sue Hess -Swiss
I
The polymer becomes covalently bonded to any siliceous
surface, including clays and the quartz grains which
define the pore structure in sandstones or poorly console
ideated or unconsolidated formations containing siliceous materials The polymer acts as a "glue" to bind formation
fines in place, thus reducing their movement when a fluid
flows through the formation. The polymer also coats any
water-swellable clays and thereby reduces their subsequent
swelling by water-containing fluids.
The rate of reaction of the injected Solon
material with the siliceous materials in the formation
depends on various factors such as the organic substitu-
ens of the Solon material, the concentration of Solon
material in the injected solution, the particular hydra-
15-
~23 I
carbon carrier, if used, and the formation temperature.
While the reaction of the Solon material with the sift-
Swiss material occurs in the absence of a polymerization
catalyst, to is possible to speed up the rate of reaction,
either by including a polymerization catalyst in the
Solon material-containing solution or by injecting a
prewash of a slug of hydrocarbon carrier, containing a
polymerization catalyst, prior to the injection of the
Solon material-containing solution. Suitable catalysts
for polymerizing Solon material are jell known in the art
and can be either acidic or alkaline materials. Examples
of acidic catalysts include if) organic or inorganic acids
or acid-forming materials such as acetic acid, ethyl
acetate, formic acid, ethyl format, hydrochloric acid,
sulfuric acid and hydroiodic acid, and (2) organic or
inorganic bases or base-forming materials such as sodium
hydroxide, butyLamine, piperidine, phosphines and alkali
metal Amadeus If catalyst is used, no more than about 50
percent by volume of catalyst, based on the volume of the
injected solution, should be employed In this instance,
the term "injected solution" is defined as a hydrocarbon
carrier liquid preflush, a Solon or a solution of a
Solon, and a hydrocarbon carrier. Preferably, no more
than about 10 percent ho volume of catalyst, based on the
volume of injected solution, should be employed.
Before injecting the Solon material-containing
solution, it is optional, but preferred, to backfill the
formation, i.e., inject a slug of a preflush composition.
The preflush dislodges any bridges of fines that might
have been formed at pore throats during production of
lug
~Z3~;S~
fluids from the formation. This increases the probability
that subse~uen~ly-injected Solon material will bind the
fines in position, at a location in the formation other
than at a pore throat, thus increasing the permeability of
the formation compared to what it was before the treatment
The materials which can be used as a preflush are the same
hydrocarbon carrier liquids described above, which are
sometimes injected along with the Solon material. As
mentioned above, the preflush can also contain a catalyst
for polymerizing Solon material. The volume of preflush
to be used is typically about 0.5 to 100 gallons per
vertical foot of formation to be treated.
In selecting a preflush material, it is pro-
furred to avoid a mutual solvent, i.e., a material, such
as a lower alkyd alcohol, in which the Solon, the hydra-
carbon carrier liquid, and water each have at least some
volubility. When a mutual solvent is injected into a
water-containing formation as a preflush, the formation
retains a least some of the resulting solution of water
in the mutual solvent. If a solution of Solon in a
hydrocarbon carrier liquid is then injected into this
formation, sore of the solution of water in the mutual
solvent dissolves in the solution of Solon in the hydra
carbon carrier. As a result, water can contact the Solon
and hydrolyze the Solon to form a polymer before the
Solon has adsorbed on the formation rock. This polymer
aloes not adsorb on the formation and does not bind format
lion fines in place.
Similarly, following injection of the Solon
ma~erial-containing solution, it is optional, buy
-17-
it
preferred, to inject a slug of an after flush or over flush
material to displace the Solon materlal-containing
solution out of the Wilbur and into the formation. The
same hydrocarbon carrier liquids described above or any
convenient aqueous or non aqueous fluid, liquid or gaseous,
can be used as the after flush. The volume of liquid
after flush to be used is typically about 0.5 to 100
gallons per vertical foot of formation to be treated.
While an aqueous displacement fluid can be used, it is
preferred that no portion of the aqueous displacement
fluid be injected into the silane-treated formation. Most
hydrocarbon-producing formations contain sufficient
connate water to hydrolyze the Solon after the Solon has
adsorbed onto the formation rock and require no additional
water for hydrolysis. If water is injected into a format
lion containing both a Solon and liquid formation hydra-
carbons or a hydrocarbon carrier liquid, there is danger
that the injected water will contact and hydrolyze the
Solon at the water hydrocarbon interface such that the
hydrocarbon layer will be a barrier to reaction of the
sullenly and condensation products with the rock surface.
Also, it is often desired that no water be injected into
those formations which produce only oil and contain no
water other than connate water.
The second treating solution injected into the
formation is a slug of steam containing a compound which
contains ammonia Cal nitrogen, selected from the group
consisting of ammonium hydroxide, ammonium salts of
inorganic acids, ammonium salts of carboxylic acids,
qua ternary ammonium halides, amine or substituted amine
~3765~
hydrochloride, derivatives of ammonium Senate, and water-
soluble ammonia or ammonium iron precursors selected from
the group consisting of asides of carbamic acid and trio-
carbamic acid derivatives of such asides, tertiary acid
asides and their substituted and alkylated derivatives.
Ammonium hydroxide, Leo aqua ammonia, can be
used in aqueous solutions of various strengths ranging up
to solutions containing 30 percent by weight ammonia, the
most concentrated solution generally commercially avail-
able.
Examples of suitable ammonium salts of inorganic acids include ammonium chloride, tetramethyl ammonium
chloride, ammonium bromide, ammonium iodide, ammonium
fluoride, ammonium bifluoride, ammonium Senate, ammonium
thiocyanate, ammonium fluoroborate, ammonium nitrate,
ammonium nitrite, ammonium sulfate, ammonium sulfite,
ammonium sulfa mate, ammonium carbonate, ammonium bicarbon-
ate, NH2COONH4.NHAHC03, (NH4)2C03.2N~I4HC03, ammonium
borate, ammonium chromates and ammonium dichromate.
Ammonium carbonate, also referred to as the double salt
ammonium sesquicarbonate, and ammonium chloride are
preferred.
Examples of suitable ammonium salts of a garb-
oxylic acid include ammonium acetate, ammonium citrate,
ammonium tart rate, ammonium format, ammonium gullet, and
ammonium bonniest.
The qua ternary ammonium compounds for use in
this invention can be represented by the general formula:
-19-
~3'~6S6
Al 2 I Al 4 Z --
R13
wherein at least one of the substituent:s Roll, R12, R13,
and R14 is an organic hydrophobic group having 1 to 20
carbon atoms. The other substituents are independently
alkyd or hydroxyalkyl groups having 1 to 4 carbon atoms,
bouncily groups, or alkoxy groups of the formula (Cowan
or (Cowan where n is 2 to 10. The preferred cation in
the qua ternary cation is the qua ternary ammonium compound.
The anion Z, preferably is chloride. This can be no-
placed by various other anions such as bromide, iodide, or
ethyl sulfate ions. Exemplary of suitable qua ternary
ammonium compounds are tetramethyl ammonium chloride,
ductile dim ethyl ammonium chloride, dodecyl trim ethyl
ammonium chloride, Seattle trim ethyl ammonium chloride,
Seattle trim ethyl ammonium bromide, dodecyl trim ethyl bouncily
ammonium chloride, ethyltrimethyl ammonium iodide, idea-
methyltrimethyl ammonium iodide, tetraethyl ammonium
iodide, tetramethyl ammonium hepta-iodide, and methyl
pyridinum chloride. Particularly good results have been
obtained with tetramethyl ammonium chloride.
Also useful are amine or substituted amine
hydrochloride such as the moo-, do-, and tri-alkyl amine
hydrochloride wherein the alkyd group contains 1 to 20
carbon atoms r straight chain or branched, aureole amine
hydrochloride, hydroxy-substituted amine hydrochloride
and heterocyclic substituted amine hydrochloride.
Examples of suitable materials include methyl amine hydra-
chloride, ethyl amine hydrochloride, propylamine hydra-
20--
~3'7~5~i
chloride, butylamine hydrochloride, dodecylamine hydra-
chloride, eicosylamine hydrochloride, diethy]amine hydra-
chloride, triethylamine hydrochloride, benzylamine hydra-
chloride, naphthylamine hydrochloride, hydroxylamine
hydrochloride 2-aminopyridine hydrochloride, and 4-amino-
pardon hydrochloride. Particularly good results have
been obtained with butylamine hydrochloride.
Examples of derivatives of ammonium Senate
include cyan uric acid, urea sonority, and ammelide.
The ammonium ion precursors suitable for use in
this invention are water-soluble materials which hydrolyze
in the presence of steam to form ammonia and/or ammonium
ions.
One group of ammonium ion precursors are the
asides ox carbamic acid end thiocarbamic acid, including
urea, Burt, triuret, Thor, and ammonium carbamate.
Urea is one of the most preferred additives for use in the
present invention.
Another group of ammonium ion precursors are
derivatives of carbamic acid and thiocarbamic acids
including monomethylolurea and dimethylolurea.
Still another group of ammonium ion precursors
are tertiary carboxylic acid asides and their substituted
and alkylated aside counterparts characterized by the
formula:
Y / R9
R8-C-N
Rio
wherein I R8 is hydrogen or an organic radical, portico-
laxly an alkyd group containing 1 to about 8 carbon atoms,
I
or an alpha-hydroxy substituted alkyd group containing 1
to about 8 carbon atoms I?) Rug and Rio are independently
selected from hydrogen and organic radicals, with alkyd
groups containing 1 to about 8 carbon atoms hying pro-
furred organic radicals, and to) Y is oxygen or sulfur.
Preferred tertiary carboxylic acid asides and their
substituted and alkylated amine counterparts include
formamide, acetamide, M~N-dimethylformamide, N,N-diethyl-
formamide, N,N-dimethylacetamide, NjM--diethylacetamide,
N,N-dipropylacetamide, N,N-dimethylpropionamide, and
N,N-diethylpropionamide. Other species which may be used
include N-methyl,N-ethylacetamide, N-methyl,N-octylpropion-
aside, N-methyl,N-hexyl-n-butyramide, N-methyl,N-propyl-
caproamide, N,M-diethylcaprylamide, and the like. N,N-di-
methylformamide is an especially preferred tertiary
carboxylic acid aside.
The compound containing ammonia Cal nitrogen
should be employed in an amount which is effective in
stabilizing fines. This amount will vary depending
especially on the nature and amount of fines present in
the particular formation being treated and the particular
additive used. Typically, there is used about 0.1 to 25
percent by weight of compound containing ammonia Cal
nitrogen, preferably 0.5 to 5 percent by weight, based on
the weight of the boiler feed water used to generate the
steam.
Additives which are liquid at ambient tempera-
lures can be added directly, either to the boiler feed
water or to the steam itself. If added to the steam, -the
addition can be made either at the surface, as the steam
-22-
3~7~
is being injected into the formation, or down a well
penetrating the formation to he treated, or the additive
can be injected Donnelly via separate conduit and mixed
with the steam Donnelly, prior to its entering the format
lion. Additives which are solids at ambient temperature
can be added directly to the feed water or a concentrated
solution thereof can be prepared and then employed as
described above for a liquid additive. An example of a
suitable concentrated solution is a solution containing 35
to 50 percent by weigh urea and 65 to 50 percent by
weight water.
If one of the chief objectives in the applique-
lion of this treatment to an enhanced oil recovery method
is to use steam to mobilize oil which otherwise would be
difficult to recover, the amount of steam to be used is
well known in the art and is the same as for steam treat-
mints in general. If mobilization of oil is of secondary
importance, as in treating a surface formation or a water
injection well completed in a fines-containing formation
to stabilize the fines, it is recommended to use the steam
generated from about 250 to 3,000 barrels of feed water per
vertical foot of formation to be treated. Preferably the
steam should be injected at a rate of about ~00 to 1,500
barrels ox feed water per day per well.
While the reasons for the effect on the format
lion permeability of steam containing a compound which
contains ammonia Cal nitrogen are not completely understood,
and the invention is not to be held to any particular
theory of operation, it is believed that the success of
this method may be due to one or more of the following two
-23~
it
reasons: (1) the ammonia or ammonium ions add to the
total dissolved solids content both of the water component
ox the steam, if wet steam is employed, and of the water
condensing from the steam itself, which solids appear to
decrease the swelling tendency of the clays when exposed
to water, even when such exposure is subsequent to the
carrying out of this method; and (2) some nonequal fines
treated with steam alone appear to react hydrothermally to
produce water-swellable clays which then reduce permeably-
fly. but the presence of the ammonia or ammonium ions in the steam inhibits this clay-forming reaction and the
ammonia or ammonium ion may react with water-swellable
clays to transform them into material which have less
tendency to swell in water.
The method of this invention can be employed to
treat or condition fines containing earthen formations
which are exposed at the surface, located just below the
surface, or which are located a substantial distance below
the surface and are penetrated by a well. In one manner
of treating subterranean formations penetrated by a well,
the treatment can involve an enhanced oil recovery method
wherein steam is injected into the formation to mobilize
oil, and the method of this invention prevents formation
; damage by the steam. In another instance, the treatment
can involve stimulation of a well penetrating a formation
whose permeability has been impaired previously. Such
impairment can occur in various ways depenfling on the
previous history of the well, for example, wells drilled
with water-base drilling fluid and/or whose surrourlding
formations have been exposed to water. As used herein the
-24~
issue
term "stimulation" can include both improving the fluid
flow rate through a formation and removing formation
damage therefrom.
The invention it further illustrated by the
following examples which are illustrative of various
aspects of the invention and are not intended as limiting
the scope of the invention as defined by the appended
claims.
EXAMPLE 1
A first laboratory test is carried out utilizing
only one step of the two-step process of this invention,
it steam containing a compound which contains an~oniacal
nitrogen is employed but no treatment with an organosilicon
compound is carried out. A first synthetic core is
prepared by packing a 1-inch diameter 3-inch-long tube
with loose sand from the Sespe formation of California.
The Sespe formation contains about 9 percent by weight
clays and about 10 to 25 percent by weight silt. The
synthetic core is treated as follows:
(a) A 3-percent by weight aqueous solution of
sodium chloride is injected into the core at a
pressure of 15 pounds per square inch (psi) for 2
hours. The final flow rate stabilizes at 1~2 Millie
liters per minute (ml./min.)~ The permeability is
calculated as 31.0 millidarcys muds and taken as
the "original permeability" of the core.
(b) Distilled water is injected into the core
at lo psi for 1 hour. The final flow rate is 0.2L
ml./min. This is 16 percent of the original Perle-
ability.
-25-
~3~65~
(c) Steam containing 2 grams per liter ammonium
carbonate (based on the amount of boiler feed water
used) is injected into the core a-t 500 F. and 700
psi for 8 hours.
(d) A 3-percent by weight aqueous solution of
sodium chloride is injected into the core at a
pressure of 15 psi for 2 hours. The final flow rate
is 1.45 mls./min. This is 120 percent of the original
permeability.
(~) Distilled water is injected into the core
at 15 psi for 1 hour. The final flow rate is 0.18
ml./min. This is 15 percent of the original Perle-
ability.
EXAMPLE 2
.
A second laboratory test is carried out utilize
in both steps of the process of this invention, i.e.,
there is injected into a core an organosilicon compound
followed by steam containing a compound which contains
amrnoniacal nitrogen. A second synthetic core is prepared
by packing a l-inch diameter 3-inch-long tube with loose
sand from the Sespe formation of California. The core is
then treated as follows:
(a) 100 ml. of super high flash naphtha is
injected into the core at a flow rate of 2 ml./min.
and 100 F. as a preflush.
(b) 100 ml. of a solution containing 3 percent
by volume 3-aminopropyltriethoxysilane, 2 percent by
volume bottle amine polymerization catalyst, and 95
percent by volume super high flash naphtha carrier
liquid is injected into the core at a flow rate of
100 ml./min. at 100 F.
-26
~L~3~656
(c) So ml. of super high flash naphtha is
injected into the core at a flow rate of 2 ml./min.
at 100~ F. as an over flush
(d) After cooling the core to room temperature,
a 3 percent by weight aqueous solution of sodium
chloride is injected into the core at a pressure of
15 psi for 2 hours. The final flow rate is 0.54
ml./min. The permeability is calculated as 16.7 muds
and taken as the "original permeability" of the core.
(e) Distilled water is injected into the core
at 15 psi for 1 hour. The final flow rate is 0.45
ml./min. This is 84 percent of the original Perle-
ability.
of) Steam containing 2 grams per liter ammonium
carbonate (based on the amount of boiler feed water
used) is injected into the core at 500 F. and 700
psi for 6 hours.
go A 3 percent by weight aqueous solution of
sodium chloride is injected into the core at a
pressure of 15 psi for 2 hours. The final flow rate
is 0.55 ml.tmin. This is 105 percent of the original
permeability.
(h) Distilled water is injected into the core
at 15 psi for 1 hour. The first flow rate is 0.54
ml./min. This is 95 percent of the original Perle-
ability.
A comparison of Examples 1 and 2 shows that:
(1) in Example 1 where a core it treated only with steam
containing ammonium carbonate, the permeability to an
aqueous solutioII of sodium chloride is high, but the
-27~
I
permeability to distilled water is relatively quite low;
and (2) yin Example 2 where the core is treated with
3-aminopropyltriethoxysilane prior to being treated with
steam containing ammonium carbonate, the permeability to
an aqueous solution of sodium chloride is high, and the
permeability remains relatively high when the core is
exposed to distilled water. Thus, distilled water does
negligible damage to the permeability of a core treated
according to the process of this invention.
EXAMPLE 3
Wells in the Sespe formation in California have
a history of production declines thought to be due to
movement of fines in the formation. These wells typically
do not respond particularly favorably to stimulation by
steam injection. One particular well is used as a vent
well in a fourfold operation, i.e., is at a point higher
in the geologic structure than the injection well, and
both removes combustion gases from the formation and
produces some oil. Production averages 3 barrels oil per
day and 5 barrels per day gross production. A core from
the formation is examined in the laboratory and found to
be quite sensitive to damage by movement of non-clay
fines. There is also a problem due to clay dispersion.
Some fines are produced along with well fluids including
iron compounds, quartz grains, feldspar and other
aluminosilicates.
The well is first given a treatment to bind -the
formation fines in place. First, there are injected 4,000
gallons of super high flash naphtha solvent as a preflush.
Next, there are injected 4,000 gallons of a solution
28-
~37656
containing 95 percent by volume of super high flash
naphtha as a carrier liquid, 3 percent by volume of
3-aminopropyltriethoxysilane, and 2 percent by volume of
ethyl format polymerization catalyst. Finally, there is
injected a two-stage over flush, the first stage being
3,000 gallons of super high flash naphtha and the second
stage being 1,600 gallons of an aqueous solution contain-
in 6 percent by weight potassium chloride. Injection is
carried out for about 9 hours at rates varying between 0.5
and 1.0 barrels per minute at a Waldo pressure of 600
to 80Q prig Fracturing pressure is never exceeded and
there is no loss or reduction of infectivity during the
treatment.
Two days later a steam injection treatment of
the well is started. A concentrated solution of urea in
water is added to steam generator feed water to achieve a
urea concentration of 2.0 percent by weight in the feed-
water. Initial stable conditions were 500 barrels/day
feed water injection rate, 60 percent quality steam at
580 F. and 1,200 pi generator conditions. The second
day of steam injection, the concentration of urea in the
feed water is lowered to 1 percent. The third day, and for
the remainder of a one-month steam injection period, the
concentration of urea is lowered to 0.5 percent. In
total, the well is given an injection of 4 billion But
steam slug followed by a two week shut-in soaking period.
The well is then placed on production. It flows
for 14 days before being returned to rod pump production.
While flowing, the well produces 210 to 240 barrels water
per day for about one week before oil production begins.
I
~765~
During the second week of flowing production, the Ross
volume of fluids produced is maintained while estimates of
oil production included ranges from 2 to 32 barrels oil
per day the well is then converted to rod pump product
lion after being killed with an aqueous solution contain-
in 3 percent by weight potassium chloride. During
circulation to kill the well, about 50 barrels of oil are
recovered from the annuls. The initial production by
pump is about 175 barrels per day. After the kill fluid
is recovered and after the annuls has filled with oil,
the well begins producing 22 to 37 barrels oil per day
while maintaining gross production at about 175 barrels
per day. During the following week production averages 30
barrels oil per day and 167 barrels per day gross product
lion. During the following three weeks, production
stabilizes at 70 to 74 barrels oil per day and 175 barrels
per day gross production. A total of more than 16,000
incremental barrels of oil are produced from the well
during the 8-month and 1-week period following treatment.
Solids content of the produced fluids is period-
icily monitored following the steam stimulation treatment
Solids production remains negligible
While various specific embodiments and modifica-
lions of this invention have been described in the forego-
in specification further modifications will be apparent
to those skilled in the art. Such further modifications
are included within the scope of this invention as defined
by the following claims.
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