Use of alkali metal silicate foam with a chemical blowing agent

A method for reducing the permeability in a desired area of a formation wherein a solid foam is formed in situ by injecting a one phase solution into the formation. Said solution comprises an alkali metal silicate, a chemical surfactant, and an alkali metal salt of azodicarboxylic acid in an amount sufficient to produce a foam. The azodicarboxylic acid salt decomposes when the pH is reduced to less than about 12 and generates gas in an amount sufficient to form a foam which subsequently hardens. When hardened the foam reduces the permeability in a desired area.

FIELD OF THE INVENTION 
This invention relates to a method for reducing permeability of a 
subterranean formation, primarily for use in steam stimulation recovery 
techniques. More particularly, this invention relates to a method of 
blocking an area of a subterranean formation by use of a rigid, 
impermeable foam includind alkali metal silicates wherein chemical blowing 
agents are utilized. 
BACKGROUND OF THE INVENTION 
Steam stimulation recovery techniques are widely used to increase 
production from an oil bearing formation. In steam stimulation techniques, 
steam is used to heat the section of a formation adjacent to a wellbore so 
that production rates are increaesd through lowered oil viscosities and 
the corresponding reduced resistance to flow through the injected area. 
In a typical conventional steam stimulation injection cycle, steam is 
injected into the desired section of a reservoir. A shut-in or "soak" 
phase may follow, in which thermal energy diffuses through the formation. 
A production phase follows in which oil is produced until oil production 
rates decreases to an uneconomical amount. Subsequent injection cycles are 
often used to increase recovery. 
Steam stimulation techniques recover oil at rates as high as 80-85% of the 
original oil in place in zones in which the steam contacts the reservoir. 
However, there are problems in contacting all zones of a reservoir due to 
heterogeneities in the reservoir such as high/low permeability streaks, 
which may cause gravity override, and steam fingering. When any of these 
heterogeneities are present in a reservoir, the efficiency of the process 
begins to deteriorate due to reduced reservoir pressure, reservoir 
reheating, longer production cycles, and reduced oil-steam ratios. As a 
result, steam stimulation may become unprofitable. 
Various methods have been proposed so that steam can be diverted to 
uncontacted zones of a reservoir. One such method is disclosed in U.S. 
Pat. No. 2,402,588 issued to Andresen ("Andresen"). Andresen discloses a 
method of sealing a more permeable area of a reservoir by injecting into a 
reservoir a dilute alkaline solution of sodium silicate under low 
pressure. An acid gas such as carbon dioxide is then injected to reduce 
the alkalinity of the solution, resulting in gelling. 
Another method is disclosed in U.S. Pat. No. 3,645,336 issued to Young et 
al. ("Young"). Young discloses the plugging of a zone of a reservoir by 
injecting a mixture of steam and sodium silicate into the permeable zone. 
A second mixture containing steam and a gelling agent such as carbon 
dioxide is injected in the permeable zone, and the two mixtures are 
allowed to react. A hard silica gel plug is formed. 
Yet another method is disclosed in U.S. Pat. No. 3,805,893 to Sarem 
("Sarem"). Sarem discloses the formation of a gelatinous precipitate by 
injection of small slugs of a dilute aqueous alkaline metal silicate 
solution, followed by water and then a dilute aquenous solution of a water 
soluble material which reacts with the alkali metal silicate to form a 
precipitate. The precipitate hardens to form a substantially impermeable 
substance. 
U.S. Pat. No. 3,965,986 issued to Christopher ("Christopher") discloses 
still another method. In Christopher, a slug of fumed colloidal silica and 
water is injected into a reservoir. This slug has a relatively low 
viscosity. A surfactant is then injected which forms a gel on contact with 
the silica slug. 
Meyers et al. ("Meyers") disclosed a method for reducing the permeability 
of a subterranean formation in U.S. Pat. No. 4,676,318. Here an alkali 
metal silicate foam was produced by injecting into the formation a 
solution of alkali metal silicate, a chemical surfactant, and a 
non-condensible gas. The foam hardens into a substantially impermeable 
solid. The foam may be used to reduce permeability in areas of the 
formation which have been steam swept during steam stimulation cycles. 
Thus, subsequent steam stimulation cycles were directed to uncontacted 
areas of the formation. 
In each of the above methods the gas required for forming the foam was 
injected into the formation. Therefore, what is required is a method 
whereby a foam can be generated by a gas released in-situ. 
SUMMARY OF THE INVENTION 
In the practice of this invention, steam is diverted from selected areas of 
an oil bearing formation by injecting into said formation a solution 
including alkali metal silicate, a chemical blowing agent, and a cationic 
chemical surfactant ("silicate solution"). Said chemical blowing agent is 
suitable for the conditions existing in said formation. This solution is 
injected into the desired area of the formation in an amount sufficient to 
treat said desired area. The rate or injection is sufficient to allow 
placement of said solution into the desired formation area or zone prior 
to significant gas release from said chemical blowing agent. Foam 
generated in a high permeability strata of said formation causes steam 
diversion to a less permeable zone thereby enhancing sweep of the 
formation. 
It is therefore an object of this invention to provide for a chemical 
blowing agent that is soluble in the injection solution which decomposes 
in-situ to liberate gas at a rate and in an amount sufficient to make a 
foam. 
It is another object of this invention to provide for a method whereby the 
formulation of the foamable injection solution can be modified thus 
allowing for variable propagation distances prior to foam generation. 
It is yet another object of this invention to alleviate injectivity 
problems by utilizing a single phase solution. 
It is still another object of this invention to form a foamed gel in-situ. 
It is a yet still further object of this invention to increase the 
effectiveness of a gel during profile control while reducing the amount of 
gel utilized.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
In a preferred embodiment, at least one, and usually three or four 
conventional steam stimulation cycles are completed. After three or four 
steam stimulation cycles, the efficiency of the process begins to 
deteriorate. Steam continues to preferentially contact reservoir areas 
which were previously swept by steam. At this point, steam diversion 
becomes desirable to ensure further productive stimulation. 
A solution is injected into the steam swept zones which includes an alkali 
metal silicate, preferably sodium silicate, one or more cationic chemical 
surfactants, and a chemical blowing agent. The volume of silicate solution 
injected depends on the area of the reservoir requiring permeability 
reduction and on the magnitude of the reservoir heterogeneity. For 
example, if the heterogeneity has been identified as a local high 
permeability streak or fracture, the volume of foamed solution required 
may only be 100 to 200 cubic meters. However, if there is generally high 
permeability in the steam swept zone, volumes of up to 1,000 cubic meters 
may be required. As the volume of solution used should be determined 
following evaluation of the reservoir, the aforementioned volumes should 
not be considered limits, but estimates of the average volume required. 
The solution may be injected through the wells by which steam was injected. 
More than one well may be used for injection in order plug a communication 
channel. The solution may preferably contact the zones of the formation 
which have been previously swept by steam, as resistance to flow is lowest 
in these zones. Silicate contained in the solution should be between about 
2 percent and 5 percent of the solution weight. Commercially available 
silicate solutions include silicon dioxide and disodium oxide. The ratio 
of moles of silicon dioxide to moles of disodium oxide may vary from about 
1:1 to 1:4. The ratio in a typical commercial solution is about 1:3.22. 
The solution is most effective when the solution includes about 0.001 to 
0.005 moles of cationic surfactant per mole of sodium silicate. The 
solution may also contain a catalyst to initiate gel formation. This 
catalyst should be a weak acid such as ammonium sulfate in an amount from 
about 0.5 to 0.6 moles of catalyst per mole of disodium oxide. A silicate 
solution is disclosed in U.S. Pat. No. 4,676,318. This patent is 
incorporated by reference herein. 
A chemical blowing agent which can be utilized in the silicate injection 
solution comprises an alkali metal salt of azodicarboxylic acid. The 
sodium salt of azodicarboxylic acid is preferred. Potassium, lead, 
cadmium, zinc, and barium salts of azodicarboxylic acid can also be used. 
This compound can be formed on site by the treatment of azodicarbonamide 
with sodium hydroxide and alkali carbonate with resulting ammonia 
evolution. When heated, this salt liberates nitrogen and carbon dioxide, 
yet it is very stable at room temperature in basic solutions of a pH 
greater than 12. Surfactant addition may be reduced or even eliminated in 
some instances due to surfactant production in-situ. The pH decline from 
hydroxide consumption will accelerate the foam generation reaction. The 
decomposition of the salt of azodicarboxylic acid is auto-catalytic in 
that hydroxide is consumed. The accompanying pH change will initiate gel 
formation, reducing, and possibly eliminating, the required weak acid 
component in the formulation. Because the sodium salt of azodicarboxylic 
acid is extremely soluble in water, a desired amount of foam can be 
generated for even the most permeable zones in a formation by 
incorporating the required amount of said salt into the solution. Toluene 
sulfonyl hydrazide and p,p'-oxybis(benzenesulfonyl hydrazide) also develop 
water solubility at high pH, but performance economics lie firmly in favor 
of the modified azodicarbonamide. Toluene sulfonyl hydrazide and 
p,p'-oxybis(benzenesulfonyl hydrazide) decompositions are not acid 
catalyzed; therefore, gas liberation would slow with declining pH. 
The type of surfactant used is also an important variable. Tetra-alkyl 
ammonium salts, such as trimethyldecyl ammonium chloride, are one 
preferred class of effective surfactants. Cationic surfactants are 
generally preferred because of superior foaming when contacting the 
generated gases and silicate solutions. While not wishing to be bound by 
theory, it appears that cationic surfactants such as tetra-alkyl ammonium 
chloride chemically react with silicate monomers resulting in the 
formation of high foaming, long chain quaternary alkyl ammonium silicates. 
When anionic and nonionic surfactants are used, the same high degree of 
foam formation is not observed. 
The pH of the solution will also vary depending on how deep into the 
reservoir the solution must penetrate and how large a volume of foam is 
desired. Silicate solutions designed to foam and gel in a pH range of 9.5 
to 11 generally produce a high quality and stable foam. Also, an alkaline 
solution will temporarily retard the gelling process, thereby allowing the 
solution to be pumped deep into the formation before gas is generated and 
foaming occurs. A weak acid such as ammonium sulfate could be present in 
the solution as a catalyst. The amount or strength of the acid can be 
increased if faster solidification is required. Once the solution has 
penetrated into the formation to the desired depth, heat from the 
formation or a decrease in the pH of the solution below 12 causes the 
sodium salt of azodicarboxylic acid to decompose. Upon decomposition, said 
azodicarboxylic acid releases nitrogen and carbon dioxide gases sufficient 
for foaming the silicate solution containing the cationic surfactant. The 
surfactant stabilizes the foam generated which subsequently hardens. The 
foam will harden into a substantially impermeable solid. Following 
solidification of the foam, steam stimulation cycles can resume. The steam 
from subsequent steam injection cycles will be diverted to areas of the 
formation which have not been previously contacted by steam. Thus, 
additional areas of the reservoir will have lowered oil viscosities and 
reduced resistance to flow. 
Where the formation is above the decomposition temperature of the sodium 
salt of azodicarboxylic acid, water or another cooling fluid can be used 
to cool the formation to allow the solution to penetrate to the desired 
depth. Should it not be desired to cool the formation, azodicarbonamide 
can be included in the silicate solution in the form of a microemulsion. 
A thermodynamically stable dispersion can be made by placing 
azodicarbonamide in suitable oil and solublizing said oil in the silicate 
solution with a suitable surfactant. A method for making a microemulsion 
is disclosed in U.S. Pat. No. 4,008,769 which issued to Chang on Feb. 22, 
1977. This patent is incorporated by reference herein. 
As is true for the other components in the solution, the components 
utilized are formation dependent and will vary. The concentration of 
silicate in the solution will also vary. The silicate solution may be 
injected in a series of slugs. It may be desired to increase the 
concentration with successive slugs to increase the strength of the foam 
nearest the wellbore, or to inject the desired volume of silicate solution 
with a subsequent injection of a quantity of solution with a higher 
concentration of silicate. The foam in the near wellbore area would have 
sufficient strength to withstand the high injection pressure of subsequent 
steam stimulation cycles. 
In order to demonstrate the effectiveness of this invention, the following 
test was performed. 
TEST 
A 1% solution of azodicarbonamide (ABFA) was made in 1% Na.sub.2 SiO.sub.3 
which had an inital pH of 12.7. The blowing agent slowly dissolved with 
stirring to yield a clear, yellow solution of pH 11.4. Within a few hours, 
the solution had completely lost coloration, indicating complete 
decomposition. The final solution had a pH of 9.9. The kinetics of 
decomposition can be determined spectrophotometrically. The accompanying 
pH changes are complicated by NH.sub.3 and CO.sub.3 chemistry. Perhaps a 
week later a gel appeared which was colorless and loose. This test 
introduced the possibility of a combined alkaline-foam-gel treatment. The 
kinetics of blowing agent decomposition can be adjusted by the initial 
system pH to give variable propagation distances. Although a pH of 12.7 
was able to convert the insoluble azodicarbonamide to the soluble 
carboxylate, it appears that a pH of 12.8 will readily react with the 
blowing agent. Calculation of kinetic data from the literature gave a 
carboxylate half life of 3.2 hours for 0.5% ABFA, 1% NaOH and 1% NaCl at 
105.degree. F. 
The solution utilized herein to generate a foam for use in a steam flood 
during profile control can also be used for profile control during a 
waterflood. A waterflood method which can be used herein is disclosed in 
U.S. Pat. No. 4,458,760 issued to Hurd. This patent is incorporated herein 
by reference. After completing a water flooding operation, the more 
permeable zone of a multi-zone formation will have substantially all 
hydrocarbonaceous fluids removed. Hydrocarbonaceous fluids still remain in 
the area of lesser permeability. This novel foamed gel can be used to 
effectively close a zone of greater permeability. Once the zone of greater 
permeability is closed, a water flood can be used to remove 
hydrocarbonaceous fluids from the zone of lesser permeability. 
In flooding operations, a liquid, usually water, is injected into the 
substerranean, oil-bearing formation through an injection well which 
extends from the surface of the earth down into the formation. A 
production well also extends into the formation at an offset or horizontal 
distance from the injection well so that, as the flooding liquid is 
injected into the information through the injection well, it displaces the 
oil towards the production well, from which it may be recovered. Often, 
more than one injection well and more than one production well will be 
used in order to cover the oil field adequately and maximize recovery. 
Various arrangements of injection and production wells are used to this 
end, e.g., linear arrangements to form a line drive, five spot, inverted 
five spot, seven spot, inverted seven spot, all of which are established 
in conventional practice. 
Although the present invention has been described with preferred 
embodiments, it is to be understood that modifications and variations may 
be resorted to without departing from the spirit and scope of this 
invention, as those skilled in the art will readily understand. Such 
modifications and variations are considered to be within the purview and 
scope of the appended claims.