CA1237656A - Increasing the flow of fluids through a permeable formation - Google Patents

Abstract

ABSTRACT OF THE DISCLOSURE

Method for treating a formation, particularly one containing finely divided particulate material, to increase the flow of fluids through the formation wherein there is injected therein an organosilicon compound, preferably in a hydrocarbon carrier liquid, followed by injection of steam containing a compound which contains ammoniacal nitrogen, selected from the group consisting of ammonium hydroxide, ammonium salts of inorganic acids, ammonium salts of carboxylic acids, quaternary ammonium halides, amine or substituted amine hydrochlorides, derivatives of ammonium cyanate, and water-soluble ammonia or ammonium ion precursors selected from the group consist-ing of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives. A
preferred nitrogen-containing compound is urea.

Description

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.

~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:

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 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 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

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

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 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 ~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

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:

R5 So - OR

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-~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, 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-~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 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:

~3'~6S6 Al 2 I Al 4 Z --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-~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:

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

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.

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.

~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.

.
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.

~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.

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 ~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.

30~

Claims (54)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A method for treating a fines-containing earthen formation, comprising:
(a) injecting into the formation an organo-silicon compound selected from the group consisting of organosilane halides, organosilane hydrides, organosilane alkoxides, and organosilane amines, in which an organosilane halide, hydride, or amine has the formula:

wherein R is a halogen, hydrogen, or an amine radical which can be substituted with hydrogen, organic radicals, or silyl 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, amines, or organic radicals having from 1 to 50 carbon atoms, and in which an organosilane alkoxide has the formula:
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 ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, ammonium salts of inorganic acids, ammonium salts of carboxylic acids, quaternary ammonium halides, amine or substituted amine hydrochlorides, derivatives of ammonium cyanate, and water-soluble ammonia or ammonium ion precursors selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary caxboxylic acid amides and their substituted and alkylated derivatives characterized by the formula:

wherein (1) R8 is a hydrogen or an organic radical, (2) R9 and R10 are independently selected from hydrogen and organic radicals, and (3) Y is oxygen or sulfur.

2. The method defined in claim 1 wherein the organosilicon compound is injected in an amount sufficient to coat a substantial portion of the formation fines.

3. The method defined in claim 1 wherein the amount of organosilicon compound employed is about 0.5 to 100 gallons per vertical foot of formation to be treated.

4. The method defined in claim 1 wherein R is a halogen, R1 is an alkyl, alkenyl, or aryl group having from 1 to 18 carbon atoms, R2 and R3 are the same or different halogens, or alkyl, alkenyl, or aryl groups having from 1 to 18 carbon atoms, R4, R5, and R6 are independently selected from hydrogen, amine, alkyl, alkenyl, aryl, and carbohydroxyl groups having from 1 to 18 carbon atoms, and R7 is selected from amine, alkyl, alkenyl, and aryl groups having from 1 to 18 carbon atoms.

5. The method defined in claim 1 wherein the organosilicon compound is injected as a solution, up to about 50 percent by volume, in a hydrocarbon carrier liquid selected from the group consisting of crude oils, aliphatic hydrocarbons, aromatic hydrocarbons, and petro-leum distillation products.

6. The method defined in claim 1 wherein there is included in the injected organosilicon compound up to about 50 percent by volume of a polymerization catalyst.

7. The method defined in claim 1 wherein there is injected into the formation before the organosilicon compound about 0.5 to 100 gallons per vertical foot of formation to be treated of a preflush of a hydrocarbon liquid.

8. The method defined in claim 1 wherein there is injected into the formation before the organosilicon compound about 0.5 to 100 gallons per vertical foot of formation to be treated of a preflush of a hydrocarbon liquid containing up to about 50 percent by volume of a polymerization catalyst.

9. The method defined in claim 1 wherein there is injected into the formation following the organosilicon compound about 0.5 to 100 gallons per vertical foot of formation to be treated of an afterflush of a hydrocarbon liquid.

10. The method defined in claim 1 wherein the organosilane alkoxide is an alkylated amine substituted organosilane alkoxide.

11. The method defined in claim 1 wherein the organosilane alkoxide is 3-aminopropyltriethyoxysilane.

12. The method defined in claim 1 wherein the amount of the compound containing ammoniacal nitrogen is about 0.1 to 25 percent by weight based on the weight of boiler feedwater used to generate the steam.

13. The method defined in claim 1 wherein the amount of the compound containing ammoniacal nitrogen is about 0.5 to 5 percent by weight based on the weight of boiler feedwater used to generate the steam.

14. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is added to the boiler feedwater used to generate the steam,

15. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is added to the steam.

16. The method defined in claim 1 wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the steam at the surface of the well.

17. The method defined in claim 1 wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the steam downhole before the steam enters the subsurface stratum.

18. The method defined in claim 1 wherein the fines include water-swellable clays.

19. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is an ammonium salt of an inorganic acid selected from the group consist-ing of ammonium chloride, tetramethyl ammonium chloride, ammonium bromide, ammonium iodide, ammonium fluoride, ammonium bifluoride, ammonium fluoroborate, ammonium nitrate, ammonium nitrite, ammonium sulfate, ammonium sulfite, ammonium sulfamate, ammonium carbonate, ammonium bicarbonate, NH2COONH4.NH4HCO3, (NH4)2CO3.2NH4HCO3, ammonium borate, ammonium cyanate, ammonium thiocyanate, ammonium chromate, and ammonium dichromate.

20. The method of claim 1 wherein the compound containing ammoniacal nitrogen is ammonium carbonate.

21. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is an ammonium salt of a carboxylic acid selected from the group consist-ing of ammonium acetate, ammonium citrate, ammonium tartrate, ammonium formate, ammonium gallate, and ammonium benzoate.

22. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is a derivative of ammonium cyanate selected from the group consisting of cyanuric acid, urea cyanurate, and ammelide.

23. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is an amide of carbamic acid selected from the group consisting of urea, biuret, triuret, and ammonium carbamate.

24. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is urea.

25. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is thiourea.

26. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is a derivative of carbamic acid selected from the group consisting of monomethylolurea and dimethylolurea.

27. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is a tertiary carboxylic acid amide, substituted tertiary carboxylic acid amide, or derivative of a tertiary carboxylic acid selected from the group consisting of formamide, acetamide, N,N-dimethylformamide, N,N-diethylformamide, N,N-dimethyl-acetamide, N,N-diethylacetamide, N,N-dipropylacetamide, N,N-dimethylpropionamide, and N,N-diethylpropionamide.

28. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is selected from the group consisting of ammonium chloride, ammonium bromide, ammonium fluoride, ammonium bifluoride, and ammonium iodide.

29. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is a quaternary ammonium compound having the formula:

wherein at least one of the substituents R11, R12, R13, and R14 is an organic hydrophobic group having 1 to 20 carbon atoms. The other substituents are independently alkyl or hydroxyalkyl groups having 1 to 4 carbon atoms, benzyl groups, or alkoxy groups of the formula (C2H4O)nH
or (C3H6O)nH where n is 2 to 10 and Z is the chloride ion.

30. The method defined in claim 1 wherein the compound containing ammoniacal nitrogen is an amine or substituted amine hydrochloride selected from the group consisting of mono-, di-, and tri-alkyl amine hydro-chlorides wherein the alkyl group contains 1 to 20 carbon atoms, straight chain or branched aryl amine hydrochlor-ides, hydroxy-substituted amine hydrochlorides, and heterocyclic-substituted amine hydrochlorides.

31. The method defined in claim 1 wherein the organic radical which comprises R8 is an alkyl group containing 1 to about 8 carbon atoms or an alpha-hydroxy substituted alkyl group containing 1 to about 8 carbon atoms.

32. The method defined in claim 1 wherein the organic radicals which comprise R1 and R2 are the same or different alkyl groups containing 1 to about 8 carbon atoms.

33. The method defined in claim 1 wherein the permeability of the earthen formation is increased by at least 50 percent, based on the permeability prior to the carrying out the method.

34. The method defined in claim 1 wherein the permeability of the earthen formation is increased by at least 150 percent, based on the permeability prior to the carrying out the method.

35. The method defined in claim 1 wherein there is first injected an alkylated amine substituted organosilane alkoxide, and wherein steam contains a compound selected from the group consisting of urea and an ammonium salt of an inorganic acid.

36. The method defined in claim 35 wherein the organosilane alkoxide is injected as a solution in a hydrocarbon carrier liquid, selected from the group consisting of crude oil, aliphatic hydrocarbons, aromatic hydrocarbons, and petroleum distillation products, which solution further contains a polymerization catalyst.

37. The method defined in claim 36 wherein the solution is injected in an amount about 0.5 to 100 gallons per vertical foot of formation to be treated.

38. 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:
wherein R is a halogen, R1 is an alkyl, alkenyl, or aryl group having from 1 to 18 carbon atoms and R2 and R3 are the same or different halogens, or alkyl, alkenyl, or aryl groups having from 1 to 18 carbon atoms; or (ii) an organosilane alkoxide having the formula:
wherein R4, R5, and R6 are independently selected from hydrogen, amine, alkyl, alkenyl, aryl, and carbohydroxyl groups having from 1 to 18 carbon atoms, and R7 is selected from amine, alkyl, alkenyl, and aryl groups having from 1 to 18 carbon atoms; and (b) subsequently, injecting steam generated from about 250 to 3,000 barrels of feedwater 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 feedwater used to generate the steam, of a compound containing ammoniacal nitrogen, selected from the group consisting of ammonium hydroxide, ammonium salts of inorganic acids, ammonium salts of carboxylic acids, quaternary ammonium halides, amine or substituted fine hydro-chlorides, derivatives of ammonium cyanate, and water-soluble ammonia or ammonium ion precursors selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives char-acterized by the formula:

wherein (1) R8 is hydrogen, an alkyl group containing 1 to about 8 carbon atoms, or an alpha-hydroxy substituted alkyl group containing 1 to about 8 carbon atoms, (2) R9 and R10 are independently selected from hydrogen and alkyl groups containing 1 to about 8 carbon atoms, and (3) Y is oxygen or sulfur.

39. The method defined in claim 38 wherein the organosilane halide or organosilane alkoxide is injected as a solution, up to about 50 percent by volume, in a hydrocarbon carrier liquid selected from the group consist-ing of crude oil, aliphatic hydrocarbons, aromatic hydro-carbons, and petroleum distillation products.

40. The method defined in claim 38 wherein there is included in the organosilane halide or organosilane alkoxide injected up to about 50 percent by volume of a polymerization catalyst, selected from the group consist-ing of organic acids or bases, inorganic acids or bases, and acid or base-forming materials.

41. The method defined in claim 38 wherein the organosilane alkoxide is an alkylated amine substituted organosilane alkoxide.

42. The method defined in claim 41 wherein the organosilane alkoxide is 3-aminopropyltriethoxysilane.

43. The method defined in claim 38 wherein the compound which contains ammoniacal nitrogen is added to the boiler feedwater used to generate the steam.

44. The method defined in claim 38 wherein the compound which contains ammoniacal nitrogen is added to the steam.

45. The method defined in claim 38 wherein the compound which contains ammoniacal nitrogen is ammonium carbonate.

46. The method defined in claim 38 wherein the compound which contains ammoniacal nitrogen is urea.

47. 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 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 hydrocarbon carrier liquid selected from the group consisting of crude oils, aliphatic hydro-carbons, aromatic hydrocarbons, and petroleum distil-lation products, which solution further contains a polymerization catalyst; and (b) subsequently, injecting steam generated from about 250 to 3,000 barrels of feedwater 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 feedwater used to generate the steam, of a compound which contains ammoniacal nitrogen, selected from the group consisting of ammonium salts of inorganic acids and amides of carbamic acid.

48. The method defined in claim 47 wherein the alkylated amine substituted organosilane alkoxide is 3-aminopropyltriethoxysilane.

49. The method defined in claim 47 wherein the ammonium salt of an inorganic acid is ammonium carbonate.

50. The method defined in claim 47 wherein the amide of carbamic acid is urea.

51. In a method for enhanced oil recovery from a subterranean formation penetrated by a well wherein steam is injected into the formation, the improvement 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 hydrocarbon carrier liquid selected from the group consisting of crude oils, aliphatic hydro-carbons, aromatic hydrocarbons, and petroleum distil-lation products, which solution further contains a polymerization catalyst; and (b) subsequently, injecting steam generated from about 250 to 3,000 barrels of feedwater 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 feedwater used to generate the steam, of a compound containing ammoniacal nitrogen, selected from the group consisting of ammonium salts of inorganic acid and amides of carbamic acid.

52. The method defined in claim 51 wherein the alkylated amine substituted organosilane alkoxide is 3-aminopropyltriethoxysilane.

53. The method defined in claim 51 wherein the ammonium salt of an inorganic acid is ammonium carbonate.

54. The method defined in claim 51 wherein the amide of carbamic acid is urea.