Method for treating earthen formations which contain water-sensitive, finely divided particulate matter wherein there is injected into the formation steam or a mixture of steam and hot water containing an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, an ammonium salt of an inorganic acid, an ammonium salt of a carboxylic acid, ammonium cyanate, derivatives of ammonium cyanate, ammonium thiocyanate, and a water-soluble ammonia or ammonium ion precursor 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 akylated derivatives. Preferred additives include ammonium carbonate and urea. If the formation is a subsurface oil-containing formation, the treatment can be part of a method for enhanced oil recovery.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
This invention relates to a method for treating earthen 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 decrease in the permeability of the formation upon contact 
with water is minimized and the permeability can even be increased. 
2. Description of the Prior Art 
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 
permeability of the formation. Thus, finely divided particulate matter can 
obstruct flow through a formation by swelling, migration or both. 
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 
recoverable 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 though the steam may act to mobilize the oil in the formation, 
if the formation contains fines and water-sensitive clays, the 
permeability of the formation can be so 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, in some instances, production can even be lower 
than before the treatment. 
In another instance a fines-containing subterranean formation penetrated by 
a well may require stimulation because of water damage which occurred 
during drilling or fracturing operations. 
Various treatments have been proposed to stabilize clays in a formation. 
Such treatments include injecting into the formation solutions containing 
such materials as potassium hydroxide, sodium silicate, hydroxy-aluminum, 
organic acid chrome complexes, organic polymers and salts of a hydrous 
oxide-forming metal such as zirconium 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 affect of the fines on formation 
permeability, particularly when such a formation is contacted by a fluid 
containing water. 
Therefore, it is a principal object of this invention to provide a method 
for reducing the permeability damage in and/or increasing the permeability 
of formations containing finely divided particulate matter due to passage 
of a fluid therethrough. 
It is another object to provide a method for inhibiting permeability 
impairment due to migration, transformation and/or swelling of very fine 
particles within a porous formation. 
It is yet another object to stabilize a formation containing 
water-sensitive clays, shale and other fines. 
It is a further object to provide such a method wherein steam is injected 
into the formation. 
It is a still further object to stimulate a formation which has been 
damaged by water. 
Other objects, advantages and features of this invention will become 
apparent to those skilled in the art from the following description and 
appended claims. 
SUMMARY OF THE INVENTION 
Briefly the invention provides a method for treating or conditioning 
earthen formations, particularly those which contain finely divided 
particulate matter, such as water-sensitive clays and shale and/or other 
fines, which materials are free to move through the formation, transform 
and/or swell if contacted by an aqueous liquid, whereby the migration, 
transformation, and/or swelling of the fines is reduced so as to maintain 
a relatively high permeability through the formation and to increase the 
permeability of formations previously damaged. The method involves 
injecting into the formation steam to which has been added at some point 
prior to the time the steam contacts the formation an effective 
fines-stabilizing amount, typically more than 0.1 to 25 percent by weight 
based on the weight of the boiler feedwater used to generate the steam, of 
a compound containing ammoniacal nitrogen selected from the group 
consisting of ammonium hydroxide, an ammonium salt of an inorganic acid, 
an ammonium salt of a carboxylic acid, ammonium cyanate, derivatives of 
ammonium cyanate, ammonium thiocyanate, and a water-soluble ammonia or 
ammonium ion precursor 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 
characterized by the formula: 
##STR1## 
wherein (1) R is hydrogen, or an organic radical, particularly 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) R.sub.1 
and R.sub.2 are independently selected from hydrogen and organic radicals, 
with alkyl groups containing 1 to about 8 carbon atoms being the preferred 
organic radicals, and (3) X is oxygen or sulfur. The preferred additives 
are ammonium carbonate and urea, an amide of carbamic acid. Urea is most 
preferred. 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 production from a formation penetrated by one or more 
wells. 
DETAILED DESCRIPTION OF THE INVENTION 
Most formations, regardless of their composition, contain at least some 
fines, detrital material or authigenic material which are not held in 
place by the natural cementatious 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 and 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. 
Formation 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. 
Fines are present to some extent in most sandstones, shales, limestones, 
dolomites 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 screen commonly available (400 U.S. 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 feldspars, muscovite, 
calcite, dolomite and barite; water-swellable clays such as 
montmorillomite, beidellite, nontronite, saponite, hectorite and 
sauconite, with montmorillonite being the clay material most commonly 
encountered; non-water-swellable clays such as kaolinite and illite; 
shales; and amorphous materials. 
In the method of this invention, the above-described fines are stabilized, 
rendered less likely to reduce permeability when a water-containing fluid 
passes through the formation, and, in some instances, the permeability of 
the formation is increased compared to what it was prior to the treatment. 
In the case of a subterranean formation penetrated by a well, the 
treatment can improve the production or injection capability of the well, 
i.e., stimulate the well. 
While the reasons for these effects on the formation permeability 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: (1) The ammonia or 
ammonium ions add to the total dissolved solids content both of the water 
component of the steam, if wet steam is employed, and of the water 
condensing from the steam itself. These solids appear to decrease the 
swelling tendency of the clays when exposed to water, even water contacted 
subsequent to the carrying out of this method. (2) Some non-clay fines 
treated with steam alone appear to react hydrothermally to produce 
water-swellable clays which then reduce permeability. The presence of the 
ammonia or ammonium ions in the steam decreases the occurrence of this 
reaction to form clays. The ammonia or ammonium ion may react with 
water-swellable clays to transform them into materials 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 
depending on the previous history of the well, for example, wells drilled 
with water-base drilling fluid and/or whose surrounding formations have 
been exposed to water. As used herein the term "stimulation" can include 
both improving the fluid flow rate through a formation and removing 
formation damage therefrom. 
Examples of suitable ammonium salts of inorganic acids include 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, NH.sub.2 
COONH.sub.4.NH.sub.4 HCO.sub.3, (NH.sub.4).sub.2 CO.sub.3.2NH.sub.4 
HCO.sub.3, ammonium borate, ammonium chromate and ammonium dichromate. 
Ammonium carbonate, also referred to as the double salt ammonium 
sesquicarbonate, is preferred. 
Examples of suitable ammonium salts of a carboxylic acid include ammonium 
acetate, ammonium citrate, ammonium tartrate, ammonium formate, ammonium 
gallate and ammonium benzoate. 
Examples of derivatives of ammonium cyanate include cyanuric acid, urea 
cyanurate 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 amides of carbamic acid and 
thiocarbamic acid including urea, biuret, triuret, thiourea and ammonium 
carbamate. Urea is the most preferred additive 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 
amides and their substituted and alkylated amide counterparts 
characterized by the formula: 
##STR2## 
wherein (1) R is hydrogen or an organic radical, particularly 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) R.sub.1 
and R.sub.2 are independently selected from hydrogen and organic radicals, 
with alkyl groups containing 1 to about 8 carbon atoms being the preferred 
organic radical, and (3) X is oxygen or sulfur. Preferred tertiary 
carboxylic acid amides and their substituted and alkylated amide 
counterparts include formamide, acetamide, N,N-dimethylformamide, 
N,N-diethylformamide, N,N-dimethylacetamide, N,N-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-octylpropionamide, 
N-methyl,N-hexyl-n-butyramide, N-methyl,N-propylcaproamide, 
N,N-diethylcaprylamide and the like. N,N-dimethylformamide is an 
especially preferred tertiary carboxylic acid amide. 
The ammonia or ammonium ion-containing additive 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 ammonium 
ion-containing additive used. Typically, there is used more than 0.1 to 25 
percent by weight ammonium ion-containing additive, preferably 0.5 to 5 
percent by weight, based on the weight of the boiler feedwater used to 
generate the steam. 
Additives which are liquid at ambient temperatures can be added directly 
either to the boiler feedwater or to the steam itself. If added to the 
steam, the addition can be made either at the surface as the steam is 
being injected into the formation or down a well penetrating the formation 
to be treated, or the additive can be injected downhole via a separate 
conduit and mixed with the steam downhole prior to its entering the 
formation. Additives which are solids at ambient temperature can be added 
directly to the feedwater 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 weight urea and 65 to 50 percent by weight water. 
If one of the chief objectives in the application 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 treatments 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 that 
there be used the steam generated from about 250 to 3,000 barrels of 
feedwater per vertical foot of formation to be treated. Preferably the 
steam should be injected at a rate of about 200 to 1500 barrels of 
feedwater per day per well.

The invention is 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 California well T-33 having a depth of 1,124 feet which is newly 
completed produces for two months at a rate of 24 barrels per day (B/D) 
oil and 1 B/D water. It is desired to carry out an enhanced oil recovery 
treatment of this well with steam. However, it is believed the formation 
may contain fines which might damage the permeability of the formation if 
treated with steam. That is, experience with nearby wells indicates the 
formation may be water sensitive. 
A one-inch diameter core having a length of 2.7 inches is removed from the 
well and tested in the laboratory to determine its sensitivity to water 
and its response to a treatment with steam containing ammonium ions. First 
a 3 percent by weight aqueous solution of sodium chloride is injected into 
the core at ambient temperature and 15 p.s.i. pressure for 3.5 hours at 
rates starting at 9.1 milliliters per minute (mls./min.) and dropping to 4 
mls./min. as the permeability stabilizes. This established a base 
permeability of 92.8 millidarcys (mds.). Next, distilled water is flowed 
through the core at ambient temperature and 15 p.s.i. for 3.25 hours at 
rates starting at 6 mls./min. and dropping to 0.15 ml./min. where the 
permeability stabilizes at 3.5 percent of the base permeability to the 
sodium chloride solution. Next, there is added to boiler feedwater 64 
grams/liter (gs./l) of ammonium carbonate. Steam is generated and injected 
into the core at 500.degree. F. and 700 p.s.i. back pressure for 6 hours 
at a flow rate of 0.5 ml./min. Next, an aqueous solution containing 64 
gs./l. of ammonium carbonate is injected into the core at ambient 
temperature and 15 p.s.i. for 6 hours at a flow rate of 13.2 mls./min. The 
permeability increased to 330 percent of the base permeability to the 
sodium chloride solution. 
This Example shows that the injection of fresh water sharply reduces the 
permeability of the core. However, the permeability can be restored, and 
even substantially increased by treatment with steam containing ammonium 
carbonate. Thus, a well treated in this manner is stimulated. A treatment 
according to this invention commonly increases the permeability of a 
fines-containing formation at least 50 percent, often at least 150 
percent, and in this instance, 330 percent of the base permeability. 
EXAMPLE 2 
There is injected into another one-inch diameter, 2.7 inch long core from 
the same well a 3 percent by weight aqueous solution of sodium chloride at 
ambient temperature and 15 p.s.i. for 3.75 hours at flow rates starting at 
17.2 mls./min. and dropping to 12.2 mls./min. as the permeability 
stabilizes. This establishes a base permeability of 223 mds. Next, an 
aqueous solution containing 32 grams per liter ammonium carbonate is 
injected through the core at ambient temperature and 15 psi for 3 hours at 
a flow rate starting at 6.8 ml/min and stabilizing at 4.7 ml/min. The 
permeability drops to 40 percent of the base permeability to the sodium 
chloride solution. Next, there is added to boiler feedwater 32 g/1 of 
ammonium carbonate. Steam is generated and injected into the core at 
500.degree. F. and 700 p.s.i. back pressure for 2 hours at a flow rate of 
2 mls./min. For the next 2 hour period, the treatment is the same except 
the concentration of ammonium carbonate in the feedwater is reduced to 16 
gs./l. For the next 2 hour period, the treatment is the same except the 
concentration of ammonium carbonate in the feedwater is reduced to 8 
gs./l. At this point the permeability of the core is 173 percent of the 
base permeability to the sodium chloride solution. Next, there is flowed 
through the core a 3 percent by weight aqueous solution of sodium chloride 
at ambient temperature and 15 p.s.i. for 2 hours at a flow rate starting 
at 24 mls./min. and stabilizing at 22.5 mls./min. The permeability of the 
core is 184 percent of the base permeability to the originally injected 
sodium chloride solution. Finally, distilled water is injected through the 
core at ambient temperature and 15 p.s.i. for 2.75 hours at a flow rate 
starting at 28 mls./min. and stabilizing at 14 mls./min. The permeability 
of the core is 109 percent of the base permeability. 
This Example shows that a core which is given a treatment with steam 
containing ammonium carbonate increases in permeability. The permeability 
remains high even when distilled water is run through the core. 
EXAMPLE 3 
Well T-33 is given a steam stimulation treatment as follows. A 42 percent 
by weight aqueous solution of urea is prepared and held in a blending 
tank. Eighty percent quality steam is generated by a battery of steam 
generators and flowed down a carbon steel flow line towards the well. At 
the surface of the well a 7-foot long section of stainless steel conduit 
is positioned in the carbon steel flow line. The aqueous solution of urea 
is injected into the steam flowing to the well at the upstream end of the 
stainless steel conduit segment to minimize corrosion. Steam generated 
from 600 barrels of feedwater per day is injected for 12.5 days The first 
day 674 gallons per day of the 42 percent by weight aqueous solution of 
urea is added to the steam. The second day 337 gallons per day of the same 
urea solution is added to the steam. For the remaining 10.5 days of the 
treatment, 168.5 gallons per day of the same urea solution is added to the 
steam. At the end of the treatment it is calculated that 2.3 billion 
B.T.U's. of heat is added to the formation. The well is shut in for 7 days 
and allowed to soak. The well is then returned to production. The 
production rate is as follows: 
1st week--160 B/D oil and 75 B/D water. 
2nd week--108 B/D oil and 61 B/D water. 
3rd week--98 B/D oil and 11 B/D water. 
4th week--90 B/D oil and 11 B/D water. 
Thus, the treatment increases the rate of oil production substantially with 
no observable evidence of permeability reduction due to swelling or 
movement of formation fines. 
While various specific embodiments and modifications of this invention have 
been described in the foregoing specification, further modifications are 
included within the scope of this invention as defined by the following 
claims.