Thermal acidization and recovery process for recovering viscous petroleum

A thermal acidization and recovery process for increasing production of heavy viscous petroleum crude oil and synthetic fuels from subterranean hydrocarbon formations containing clay particles creating adverse permeability effects is described. The method comprises injecting a thermal vapor stream through a well bore penetrating such formations to clean the formation face of hydrocarbonaceous materials which restrict the flow of fluids into the petroleum-bearing formation. Vaporized hydrogen chloride is then injected simultaneously to react with calcium and magnesium salts in the formation surrounding the bore hole to form water soluble chloride salts. Vaporized hydrogen fluoride is then injected simultaneously with its thermal vapor to dissolve water-sensitive clay particles thus increasing permeability. Thereafter, the thermal vapors are injected until the formation is sufficiently heated to permit increased recovery rates of the petroleum.

BACKGROUND OF THE INVENTION 
This invention relates to a method for conditioning a subterranean 
formation containing clay particles creating adverse permeability effects 
around a well bore communicating from the surface of the earth to the 
formation in order to increase the recovery of heavy viscous hydrocarbon 
materials, such as petroleum crude oil or synthetic fuels. The presence of 
clay particles may create adverse permeability effects in the formation 
and particularly around the well bore by swelling if water-sensitive 
clays, particle plugging by dispersal of clay fines or by particle 
invasion of such fines. Such effects reduce permeability of the formation 
both to fluids injected for stimulation of production of viscous 
hydrocarbons and to the production of the hydrocarbons themselves. 
There are many methods known in the art for injecting thermal energy into a 
formation for the purpose of reducing the viscosity of heavy viscous 
petroleum crude oil so that it may be recovered. Such methods are usually 
classified as "thermal drive", "single well thermal injection" or the 
like. Thermal drive processes basically involve injecting thermal energy, 
usually from steam boilers or in situ combustion, into an oil-bearing 
formation by means of an injection well, driving the petroleum towards one 
or more adjacent producing wells and recovering the petroleum through the 
producing wells. Single well thermal injection processes usually involve 
injecting thermal energy into the oil-bearing formation by means of an 
injection well and subsequently withdrawing the resulting heated petroleum 
through the same well. Such single well thermal injection processes are 
also commonly referred to as "huff-and-puff" processes. There are, of 
course, many modified versions of these basic techniques known in the art 
which employ a wide variety of thermal energy agents, such as hot water, 
in situ combustion gases, steam, heated condensable and non-condensable 
gases, and the like. 
Although many thermal injection methods have been useful under certain 
conditions, there are many formations known to contain large volumes of 
heavy viscous petroleum from which the petroleum has not been economically 
and efficiently recovered by the employment of any known thermal injection 
technique. By way of example, there are many formations located throughout 
the United States, particularly throughout southern Illinois, western 
Missouri, southeastern Oklahoma, and southern Kansas, saturated with heavy 
viscous crudes, e.g., having viscosities greater than 200 centipoises 
and/or API gravities below about 22.degree. (both at 60.degree. F.), which 
have not been recovered in economic quantities by employment of 
conventional recovery techniques. Additionally, previous attempts to 
increase the recovery of such heavy crudes from such formations by the 
employment of known thermal injection processes, especially direct single 
well steam injection, have been substantially unsuccessful. As known, one 
of the primary problems in attempting to recover such viscous crudes from 
such formations is that the formations have such low relative 
permeabilities to oil and water that thermal energy cannot be injected 
into the formations at economic injection rates. In fact, there are many 
formations which have such low relative permeabilities to oil and water 
that they will not accept sufficient quantities of thermal energy by the 
employment of known injection processes at any injection rate. 
A recent patent discloses a method for enhancing petroleum production in 
such formation. For example, U.S. Pat. No. 3,993,135 discloses a method 
comprising initially heating a well bore penetrating the formation and 
surrounding subterranean strata with a thermal vapor stream containing 
combustion gases and superheated steam until sufficient heat is imparted 
thereto to permit the thermal vapor stream to be injected into the 
formation at a desired high injection rate. The well bore and surrounding 
strata are heated by continuously injecting the thermal vapor stream into 
the well and simultaneously venting a portion of the vapor stream from the 
well at the surface to remove condensed liquids formed from while heating 
the well bore and formation face. The heated fluid is then injected 
directly into the formation at a desired high injection rate until the 
formation and viscous petroleum contained therein are heated and the 
viscosity of the hydrocarbons is reduced. Injection is then discontinued 
and the heated crude is produced through the well. Surprisingly, and 
contrary to prior attempts, a formation having low relative permeabilities 
to water and oil will readily accept a thermal vapor stream containing 
steam at high injection rates when the heated fluid containing steam is 
injected in accordance with the process of U.S. Pat. No. 3,993,135. U.S. 
Pat. No. 4,118,923 describes apparatus particularly suited for generating 
a thermal vapor stream for use in the described method. 
Best results are obtained with the above process when the heated fluid is 
injected at the maximum injection rate possible so as to impart heat to 
the formation as rapidly as possible. But it has now been found that the 
above process cannot be applied to maximum efficiency in those formations 
which clay particles which cause adverse permeability effects by swelling 
upon contact with water or being of such fine particle size that the 
particles migrate through the formation ultimately plugging the formation. 
Injection of a thermal vapor stream as described in U.S. Pat. No. 
3,993,135 causes the fine particles to migrate through the formation to 
ultimately plug the formation. Where the clays are water-sensitive, 
swelling occurs. Such swelling lowers the already low permeability of such 
formations which lowers, for practical purposes flow of the thermal vapor 
stream into such formations and greatly impeds the recovery of petroleum 
from such wells. Additionally, when a continuous thermal drive technique 
is employed the presence of such clays within the formation around the 
drive well impeds the ability to drive the petroleum crudes from the field 
through the use of the injection well. Examples of such clays which 
adversely affect the permeability of such formation include, for example, 
illite, smectite, bentonite and montmorillonite. 
Traditional treatment of such formations with hydrogen fluoride to dissolve 
the clay or with clay stabilizers has proved unsuccessful, partly because 
of the difficulty of removing carbonaneous materials, such as oil, from 
the clay particles. The coating of crude oil prevents the hydrogen 
fluoride from attacking and dissolving the clays. This result is partly 
because hydrogen fluoride reacts with calcium, magnesium and other metals 
contained in the formation to form insoluble metal fluoride salts which 
are deposited within the pores of the formation to further limit its 
permeability. Attempts to solve this problem, such as described in U.S. 
Pat. No. 4,136,739 illustrate the difficulty in treating formations with 
hydrofluoric acid and hydrochloric acid to solve the problems created by 
clay particles which adversely effect the permeability of oil-bearing 
formation. These problems are compounded when heavy viscous hydrocarbons 
are present in the formation. Further, conventional acidizing with 
hydrogen fluoride is very corrosive and causes considerable damage to the 
well bore. 
Treatment similar to that described in the prior art was attempted where a 
liquid hydrocarbon, in this case diesel fuel, was injected into the 
formation to attempt to remove heavy viscous crude in the presence of such 
clay particles to make them susceptible to treatment with hydrofluoric 
acid failed. No increased permeability was noticed. 
SUMMARY OF THE INVENTION 
Applicant has now discovered a method by which the problems created by the 
presence of clay particles which adversely effect permeability in a 
formation containing highly viscous hydrocarbon materials such as 
petroleum crude oils and synthetic fuels are solved, allowing the 
formation to be stimulated by the injection of a thermal vapor stream 
comprising steam and combustion gases, such as, for example, carbon 
dioxide. The method of this invention comprises initially injecting the 
thermal vapor stream through the bore hole to clean that part of the 
formation in the vicinity of the bore hole of hydrocarbon crude oil to 
expose the clay particles; injecting vaporized hydrochloric acid 
simultaneously with the thermal vapor stream until calcium; magnesium and 
other metals, if present, in the formation about the bore hole have 
reacted to form water-soluble chloride salts; injecting vaporized 
hydrofloric acid simultaneously with the thermal vapor stream until 
sufficient amounts of the clay in the formation about the bore hole have 
been dissolved by the hydrofluoric acid; and, continuing to inject the 
thermal vapor into the formation until sufficient heat has been imparted 
thereto to permit the petroleum therein to be recovered at an improved 
recovery rate. 
Where mobile, fine clay particles are present, a known clay stabilizer may 
be added with any of the injection steps after the crude oil has been 
cleaned from the clay particles to further assist in curing the problem 
converted with particulate migration. 
Injection of hydrogen chloride and hydrogen fluoride sequentially, or 
simultaneously after some initial HCl injection, as a vapor at high 
temperatures insures that the formation about the bore hole may be 
properly conditioned for a distance of at least five feet of the bore hole 
to eliminate the problems caused by clay particles when the thermal vapor 
stream is employed to stimulate production of the viscous petroleum 
contained therein.

DETAILED DESCRIPTION OF THE INVENTION 
It will be understood that the instant invention may be employed for the 
recovery of substantially any type viscous hydrocarbon materials, such as 
crude petroleum oil or synthetic fuel from substantially any type of 
subterranean formation containing clay particles which adversely effect 
the permeability of the formation. One of the primary advantages of this 
invention is that it provides for the injection of a thermal vapor stream 
containing combustion gases and steam at high injection rates thereby 
permitting the formation to be heated to a predetermined desired level at 
which the crude oil will be flowable in relatively short periods of time. 
However, the instant process is particularly useful for recovering heavy 
viscous crudes; e.g., those having viscosities greater than 200 centipoise 
(at 60.degree. F.) and/or API gravities (at 60.degree. F.) of about 
22.degree. or below, from subterranean formations having low relative 
permeabilities to water and oil and containing water-sensitive or fine, 
mobile particulate clays. 
More specifically, the instant method is useful for recovering such highly 
viscous crudes from a formation where the low permeability of the 
formation is due, at least in part, to the swelling of water-sensitive 
clay particles which, when contacted with the thermal vapor stream, expand 
to inhibit the migration of the thermal vapor stream into the formation at 
distances more remote from the well bore or where mobile, fine clay 
particles migrate and plug the formation. 
Many of such viscous crude-bearing formations having low relative 
permeabilities to oil and water are well-known, and are usually located 
within the range of from about 500 to about 2,000 ft. below the earth's 
surface. Included among such formations, by way of example, are those of 
Pennsylvanian sandstone, such as Bartlesville sandstone of the Cherokee 
group, which are known to be located throughout southern Illinois, western 
Missouri, southeastern Kansas and northeastern Oklahoma. Such formations 
often contain about 10% to 16% of troublesome clay particles. 
The practice of this invention can be most easily understood by reference 
to the drawing. As illustrated, a producing formation 10 bearing heavy 
viscous petroleum is penetrated by a well 11 which has been drilled from 
the surface of the earth 12. The well 11 has preferably been completed in 
a conventional manner and includes a string of casing 13 set within a well 
bore 14 to the petroleum-bearing formation 10 and supported by a cement 
sheath 15. The well bore 14 has penetrated the petroleum-bearing formation 
and has been drilled to near the bottom of the desired formation injection 
zone. The well bore 14 may be left open as in an open hole completion or a 
screen or slotted liner or perforated casing (not shown) may be set in the 
well bore lower end 14a to support the walls of the well bore 14 Of 
course, the casing may be set all the way through the formation, cemented 
and perforated. 
The well 11 also includes a string of tubing 17 disposed within the casing 
13 and the well bore 14 extending through the formation 10 thereby forming 
annular space 18. Preferably, the tubing 17 extends downwardly to near the 
well bore lower end 14a. A conventional sealing device (not shown) is 
provided adjacent the top of the well head 19 to seal off the casing 
annulus 18 and maintain pressure within the well. In an optional 
embodiment to be discussed subsequently, a second short length of 
supplemental tubing 37 is included within the tubing 17 and forms a second 
annulus 40 therewith. Tubing 37 extends partially the length of tubing 17, 
terminates in opening 37a and is held in place by centralizer 389 which 
has openings therein (not illustrated) to allow fluid flow in tubing 17 
pass centralizer 39. A conventional sealing device 38 is provided at the 
top of tubing 17 to seal off the second annulus 40 and maintain pressure 
within the well. 
In the first step of the method of this invention the formation face 10a 
and surrounding strata adjacent the well bore 14 is preliminarily 
"preconditioned" to clean or remove viscous crude, paraffins, or other 
hydrocarbonaceous materials adhering to the particles of the 
formation--including clay particles contained therein--which could 
restrict flow of the thermal vapor stream into the petroleum-bearing 
formation 10. 
In the first step in carrying out the method of the invention the well bore 
14 and surrounding strata through which the well 11 extends to and through 
the formation 10 is initially heated by injecting a thermal vapor stream 
containing combustion gases and superheated steam; i.e., particularly 
carbon dioxide and superheated steam, into the annulus 18 through a 
valve-controlled pipe 20. The heated thermal vapor stream travels down the 
annulus 18 where part of it contacts and penetrates the formation face 10a 
and surrounding strata adjacent the well bore 14 while the remainder 
enters the open end 17a of the tubing 17, causing the thermal vapor and 
any condensed fluid as well as any hydrocarbonaceous material removed from 
the formation about the bore hole to pass upwardly through the tubing 17 
where it is vented into suitable collection means (not shown) at the 
surface through a suitable venting means 23 connected with the surface end 
of the tubing 17, such as by pipe 22. The venting means 23 include a means 
for controlling the pressure in the tubing, such as a valve, restriction 
orifice, automatic operating valve or a combination of such devices. This 
pressure controlling means 23 is preferably installed between the end of 
the pipe 22 and a valve 21. 
If desired, the thermal vapor stream may be injected into the tubing 17, 
such as through piping 24 connected therewith and vented at the surface 
from the annulus 18 by appropriate venting pressure controlling means 25 
mounted with pipe 26. However, annulus injection and venting through the 
tubing 17 for heating and cleaning the well 11, the casing 13 and 
surrounding strata is preferred. 
The injection of the thermal vapor stream into the well 11 contacts the 
tubing 17, casing 13 and the formation face 10a may cause, depending upon 
the formation temperature, substantially simultaneous condensation of 
condensable fluids, e.g., steam, in the thermal vapor stream which may 
collect in the well bore 14. If the rate at which the fluid condenses in 
the well bore 14 is greater than the rate which the formation can accept 
at the injection pressure employed, the well bore 14 starts to accumulate 
fluids usually at the bottom 14a. As these fluids accumulate they reduce 
the area of the formation injection zone which in turn reduces the 
injection rate of the heated fluid into the formation. As this condition 
continues, the level of condensed fluids can rise to a level in the well 
bore 14 and formation 10 where it effectively seals off the entire 
formation injection horizon and the maximum injection rate of the heated 
fluid into the formation may drop to near zero. 
However, by simultaneously venting, as described previously and taught by 
U.S. Pat. No. 3,993,135, which is incorporated herein by reference for all 
purposes, the injected thermal vapor stream at the surface through the 
pressure control means 23 any condensed liquids formed and collected in 
the well bore 14 are forced into the tubing 17 through its open lower end 
17a and are forced or lifted towards the surface. The simultaneous venting 
step thus sweeps the condensed liquids from the well bore 14 thereby 
eliminating the aforementioned blockage problems. 
The thermal vapor stream is preferably continuously injected and 
simultaneously vented until the well and surrounding subterranean strata 
are heated sufficiently to substantially eliminate condensation of the 
heated fluid within the well 11 or at least reduce the amount of 
condensation to a level which the formation will accept without causing 
the aforementioned blockage problems. The time required will vary widely, 
depending upon well location, depth, and surrounding strata temperatures, 
types of strata, etc. and is best determined emperically, such as by 
directly injecting the thermal vapors into the formation by discontinuing 
venting and observing whether a desired high formation injection rate can 
be maintained. 
The thermal vapors may be injected into the well 11 at any desired rate to 
impart heat through the well and surrounding subterranean strata. However, 
it is prefered to employ the maximum injection rate possible so as to 
impart heat as rapidly as possible. Such maximum injection rates may be 
obtained by employing an injection pressure practiceable below the 
formation fracture gradient pressure which may be readily determined, if 
desired, by known techniques. More specifically, it is preferred to employ 
an injection pressure within the range of from about 200 to about 1500 
psig (14 to about 105 kg/cm.sup.2 gauge). Again, such injection procedure 
is described in U.S. Pat. No. 3,993,135, previously incorporated by 
reference. 
Further, the thermal vapor stream is vented at the surface at a rate 
sufficient to keep the gas velocity in tubing 17 high enough to lift any 
condensed liquids formed and collected in the well bore 14 towards the 
surface so as to keep it substantially free of liquids while maintaining 
substantially full pressure on the formation. This may be readily 
accomplished by the employment of the aforementioned appropriate vent 
pressure control means at the surface, such as a valve, restriction 
orifice or like device in the conventional manner to provide a gas 
velocity in the tubing within the range of from about 10 to about 40 
ft./sec. (3 to about 12 meters/second). 
During the above-mentioned injecting and venting the heated fluid through 
the well 11 the formation face 10a adjacent the well bore lower end 14a is 
continuously exposed directly to the heated fluid, thereby gradually 
increasing its temperature and the temperature of the heavy viscous 
petroleum therein. This "pre-conditioning" of the adjacent formation face 
cleans the well bore 14 and formation face 10a of viscous crude, 
paraffins, or materials which could tend to restrict flow of the thermal 
vapors into the petroleum-bearing formation 10. It also exposes the clay 
particles which adversely effects permeability and makes them susceptible 
to further treatment. 
The thermal vapor stream preferably employed to heat and clean the 
formation face of the well 11 and surrounding subterranean strata is 
usually a mixture of superheated steam and combustion gases essentially 
free of solid carbonaceous particles. Such a mixture of steam and 
combustion gases are preferably produced as described in U.S. Pat. Nos. 
3,993,135, 3,948,322 and 4,718,925, all incorporated herein by reference 
for all purposes. Any process and apparatus known in the art can be 
employed for injecting such steam-gas mixtures with a mixture of carbon 
dioxide and steam being particularly useful. 
It is preferred to employ a steam-gas mixture which is produced by 
initially burning a hydrocarbon fuel, such as diesel oil, gasoline, 
heating oil, natural gas, propane, butane, lease crude, etc. in the 
presence of substantially stoichiometric quantities of pressurized air 
under relatively high pressures, e.g., within the range of from about 200 
to about 1500 psig and contacting the resulting pressurized combustion gas 
stream with water as described in the aforementioned patents. As 
illustrated in the drawing, this may be carried out by simultaneously 
injecting a hydrocarbon fuel from a suitable fuel storage supply 30 and a 
pressurized stream of air produced by a suitable air compressor 31 through 
suitable piping 32 and 33 respectively, into a pressurized combustion 
chamber 34 specifically designed for high pressure combustion, such as the 
one described in U.S. Pat. No. 4,118,925, wherein the fuel is burned under 
high pressure. The quantities of fuel and pressurized air are regulated to 
provide essentially complete combustion in the pressurized combustion 
chamber 34, resulting in a pressurized combustion gas stream essentially 
free of solid carbonaceous particles, e.g., soot. 
The pressurized combustion gases, usually having a temperature within the 
range of from about 2,000.degree. to about 4,000.degree. F., is then 
passed into a steam generator 35 where it is contacted with water provided 
through suitable piping 36 to form steam. The resulting mixture of 
combustion gases and superheated steam forming the thermal vapor stream, 
can then be injected into the well annulus 18 through piping 20 or into 
the well tubing 17 through piping 24 under any pressure within the range 
of from about 200 to about 1500 psig, depending upon the formation 
fracture pressure gradient to enter the formation at a temperature within 
the range of from about 550.degree. to about 700.degree. F. The 
temperatures stated are illustrative, with the important consideration 
being that the thermal vapor stream enters the formation with superheated 
steam. At such temperatures and pressures, the thermal vapor stream is 
injected into the well 11 for heating it and the surrounding strata, 
described hereinabove, or directly into the formation at steam-gas 
injection rates within the range of from about 200,000 to about 2 million 
standard cubic feet per day (scfd) and heat injection rates within the 
range of from about 20 million to about 250 million BTU heat per day. 
In accordance with the inventive method, after the surrounding strata is 
sufficiently heated and the clay particles substantially cleaned of 
hydrocarbaneous materials, vaporized hydrochloric acid is injected 
simultaneously with the thermal vapor stream through the well bore and 
thereafter vaporized hydrofluoric acid is injected simultaneously with the 
thermal vapors. This injection allows for solubilization or stabilization 
of the clay particles which would, without this treatment, adversely 
effect the permeability of the formation. 
With reference to the drawing, acid injection may be accomplished by adding 
it directly to the supply line 24 through which the heated fluid is 
injected into the well. After that, the acid added to the supply line will 
vaporize as a result of contact with the heated fluid. This method is not 
preferred because it exposes the mild steel of the supply line to the 
corrosive effect of the acid. The acid in the vapor phase is less 
corrosive than its liquid counterpart. Thus it is preferred to vaporize 
the acid prior to its admixture with the heated fluid. This may be 
accomplished by employing hydrogen chloride or hydrogen fluoride gas 
rather than aqueous solutions of these acids. In this event, it is merely 
necessary to inject the hydrogen chloride or hydrogen fluoride directly 
into the thermal vapor injection line 24. Upon mixture with the thermal 
vapors, the hydrogen chloride or hydrogen fluoride will become heated to 
the same temperature of the thermal vapors. It is important to avoid 
corrosion that the temperature of the mixture of thermal vapors and the 
acid mixture be above point which the hydrogen chloride or hydrogen 
fluoride, as the case may be, will condense. 
Alternately, an aqueous acid solution may be heated to vaporization in a 
heater 43, prior to injection via conduit 46 into tubing 17 where it 
becomes mixed with the thermal vapor, which is simultaneously injected 
into tubing 17. This method requires a heater 43 constructed of a 
corrosive resistant metal. 
In a preferred method of acid injection, the heat value of the thermal 
fluid is utilized to vaporize an acid solution and raise it to a 
sufficient temperature such that the mixture enters the formation at a 
temperature above the dew point of the mixture. In this embodiment, acid 
solution is pumped from reservoir 47 or 48 to supplementary tubing 37. 
Supplementary tubing 37 is constructed of a corrosive resistant steel such 
as Hastelloy B. Simultaneously with the injection of acid solution through 
supplementary tubing 37, thermal vapors are being injected into tubing 17 
and passing down annulus 40 in a heat exchange relationship with 
supplementary tubing 37. Tubing 17 and supplementary tubing 37 form a heat 
exchanger in which acid flowing through supplementary tubing 37 becomes 
vaporized prior to passing through opening 37a where it becomes mixed with 
the thermal vapors in one preferred embodiment of this invention. 
Sufficient hydrochloric acid is injected into the formation surrounding the 
bore hole in order to react with such calcium and magnesium compounds as 
may be contained in the formation to form water soluble metallic 
chlorides. The hydrogen chloride treatment when such compounds are present 
prepares the formation for hydrofluoric acid injection. If hydrofluoric 
acid were injected without prior hydrochloric treatment, the hydrofluoric 
acid would react with the calcium and magnesium, if present in the 
formation, to form insoluble metallic fluorides which would deposit within 
the pores of the formation and impair its permeability. The amount of 
hydrochloric acid needed can be readily determined by core analysis of the 
formation. 
Preferably a 35%, by weight, aqueous solution of hydrochloric acid is used 
as a source of hydrogen chloride even though anhydrous hydrogen chloride 
gas may be used. The rate of addition is adjusted such that about 5 to 
about 30 gallons of such 35% solution is used per hour preferably from 
about 5 to about 10 gallons per hour. Greater or lesser amounts of 
hydrochloric acid may be used with the heating time being varied 
accordingly. 
The injection of hydrochloric as a vapor at elevated temperatures above the 
dew point simultaneously with the injection of the thermal vapor is 
important to insure that the hydrochloric acid will be carried into the 
formation adjacent the well bore for a distance of at least 5 feet. The 
amount of hydrochloric acid necessary to treat the formation around the 
well bore for the required distance of at least 5 feet may readily be 
determined by determining the calcium and magnesium content of the 
formation from a core sample or samples of formation fluids. It is 
preferred to employ an excess of hydrochloric acid to ensure that the 
formation is properly perconditioned for the subsequent hydrofluoric acid 
treatment. 
After the hydrochloric acid injection, the well is acidized with 
hydrofluoric acid in order to remove the troublesome clay particles in 
that part of the formation which surrounds the well bore 11. Hydrofluoric 
acid injection may be accomplished in substantially the same manner, and 
with the same temperature requirements, as hydrogen chloride injection. 
That is, the hydrofluoric acid may be added as a gas to the heated fluid 
supply line 24 as an aqueous solution, usually 70% by weight hydrofluoric 
acid, which is vaporized in a heater 43 prior to injection, or injected as 
an aqueous solution which is vaporized by indirect heat exchange with the 
thermal vapors in the same manner as previously described which is 
simultaneously injected into the well. 
The hydrofluoric acid usually amounts to about 3%, by volume, of the amount 
of thermal vapor being injected. Lesser amounts may be acceptable but 
would require additional times of injection and greater amounts may cause 
corrosion and do not normally result in significant reduction in injection 
time. The preferred range is from about 2% to about 6%. This amount is 
easily accomplished by injection of from about 5 to about 30 gallons per 
hour, preferably from about 5 to about 10 gallons per hour, of a 70% 
weight solution of aqueous hydrofluoric acid. 
Injection of hydrofluoric acid as a heated vapor simultaneously with the 
injection of the thermal vapors at temperatures above the dewpoint of the 
mixture insures that the hydrofluoric acid will be carried into the 
formation surrounding the bore hole for a distance of about 5 feet or 
more. The hydrofluoric acid then reacts with the clay particles of the 
formation in the immediate vicinity of the well bore to render them 
incapable of swelling. A surfactant may optionally be added to the 
hydrofluoric acid to be injected to increase the activity of such acid in 
its removal of the clay particles. 
In those formations where plugging of the pores within the formation is 
caused by the migration of very fine clay particles which are either 
removed from the sandstone substrate or are suspended in the pore volume 
fluids, known clay stabilizing compounds may be added, usually 
simultaneously with hydrofluoric acid injection. This clay stabilizing 
compound added to the 70% weight solution of aqueous hydrofluoric acid in 
quantities of from about 0.003 gallons to about 0.5 gallons of clay 
stabilizing compound per gallon of 70% by weight hydrofluoric acid with a 
rate of about 0.1 to about 0.30 gal. of clay stabilizing compound per 
gallon being preferred. The acid stable organic clay stabilization 
compound will attach itself to these very fine clay particles and render 
them immobile; thus, preventing their migration and subsequent plugging. 
Of course, once the clay particles have been cleaned of the 
hydrocarbonaceous coating the stabilizing additive can be used. One 
particularly useful clay stabilizer is "Cla-Sta B" sold by the Halliburton 
Company which is an aqueous solution of ammonium chloride containing 30% 
weight of a quaternary polymer. 
In accordance with the inventive method, after the well 11 and surrounding 
strata have been sufficiently heated and cleaned and the permeability has 
been increased by the treatment described hereinabove, injection of the 
thermal vapors is continued directly into the formation at the maximum 
injection rate possible as described in the aforementioned patents. 
Formation injection is then continued until sufficient thermal vapor has 
been injected to raise the formation temperature sufficiently to permit 
the heated petroleum to flow to the well bore 14 for recovery to the 
surface by the employment of conventional production means. The injection 
necessary depends upon formation permeability, crude viscosity, formation 
fluid composition and the like, all well-known to those having ordinary 
skill in the art. 
In carrying out the inventive method, the thermal vapors are continuously 
injected into the formation until it has sufficiently heated the 
formation, usually about 150 million BTUs. It is preferred to establish 
and maintain a formation injection rate averaging at least 50 million BTU 
per day and at least 500,000 scfd thermal vapor in order to permit 
petroleum recovery as rapidly as practicable. However, often times such 
injection rates are not obtained at initial formation injection and 
oftentimes the formation injection rate diminishes below such levels 
before the formation has been heated to the desired extent due to blockage 
problems caused by condensed liquids forming and collecting in the well 
bore and adjacent injection zone of the formation. It is believed that 
this is caused by the well and surrounding strata being insufficiently 
heated. However, it has been discovered that this problem can be overcome 
by discontinuing direct formation injection and further heating the well 
11 and surrounding strata by injecting and simultaneously venting the 
steam-gas mixture through the well as described above. By alternating the 
well bearing injection and direct formation injection, the direct 
formation injection rate is increased and stabilized. Also, the injection 
can be halted and the formation allowed to "soak" with the injected 
thermal vapors further improving permeability to accept additional thermal 
vapor injection. 
Therefore, whenever the formation injection rate diminishes or is initially 
established at a rate below about 20 million BUT per day heat, preferably 
below about 50 million BTU per day heat, the alternate injection procedure 
may be employed. 
After the formation 10 has been heated to the desired extent, direct 
formation injection is discontinued at the surface and the heated, now 
mobile petroleum is withdrawn and collected at the surface through the 
well 11 by the techniques, such as natural flow, pumping, and the like, 
all well-known in the art. If desired, the formation may be allowed to 
"soak" for a desired length of time prior to petroleum withdrawal to allow 
the thermal vapor to dissipate through the formation interstices, impart 
heat to the formation strata and petroleum and to allow the petroleum, in 
its heated, more mobile state, to be easily removed from the formation 10 
through the well 11. 
Into a well in southwestern Missouri containing a 21.degree. API gravity 
crude was injected a thermal vapor stream prepared as described in U.S. 
Pat. No. 4,118,923. A total amount of about 300 million BTU were injected. 
Upon entering the production cycle, only about 6 barrels of oil was 
recovered per day for five days and the production dropped to near zero. 
It was attempted to acidize the well by cleaning clay particles at normal 
reservoir temperatures (70.degree.-80.degree. F.) with diesel oil followed 
by injection of liquid 70% HF to which Cla-Sta B (The Halliburton Co.) had 
been added. Attempts to stimulate the formation followed by the injection 
of thermal vapors but no production of crude oil resulted. 
The well was then treated by injecting sufficient thermal vapors, carrying 
approximately 50 million BTUs of heat at a temperature of from about 
550.degree.-650.degree. F. and about 300 psig. Without ceasing the heat 
injection, over the next two hour period, 55 gallons of 35% (wt) aqueous 
hydrochloric acid was added to the thermal vapors. Then, over a two hour 
period 55 gallons of 70% (wt) aqueous hydrofluoric acid was added to the 
thermal vapor stream. One quart of Halliburton Cla-Sta B was added to the 
hydrofluoric acid. After the addition of the hydrofluoric acid was 
complete additional thermal vapors were injected until a total of about 
150 million BTU had been put into the formation. The well then began 
production at a rate of about 35 barrels of oil per day. Another well in 
the same field and pay zone was similarly treated and had a production 
rate as high as 60 barrels per day. Of course, in fields of this nature it 
is well known that production falls off as the formation cools and 
requires more heat injection. The period of time however can be as long as 
4-6 months. 
From the foregoing description, those skilled in the art will be able to 
arrive at many variations of the same without departing from the scope of 
the claimed invention.