Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 BACXGROU~D ~ THE I~ TION
2 1. Field of the Invention
3 ` The present invention relates to the treatment of subterranean
4 formations penetrated by wellbores, and relates more particularly to
methods for treatment of subterranean siliceous formations with acid.
6 2. Prior Art
7 Often the cause of low productivity of oil and gas in sub-
8 terranean sandstone formations is reduc~d formation permeability near
9 the wellbore. This condition, called "formation damage" has been
related to a variety of completion and drilling practices. For example,
11 the perforating of casing may reduce permeability around the perforation
12 by matrix crushing and compaction caused by the shaped charge or by gun
13 debris. The loss of completion fluids, filtrates from drilling mud, or
14 drilling mud particles may cause clay swelling, particle plugging by
dispersed formation fines, particle invasion, or adverse change in fluid
16 saturation.
17 Many of the adverse permeability effects relate directly to
18 the clay fraction of the matrix. It is well known that certain effects
19 such as clay swelling, clay dispersion, and particle plugging can be
reduced by solubilizing the clay with mineral acid solutions of hydrogen
21 fluoride. Commonly, aqueous solutions containing from about 2 to 6
22 weight percent hydrofluoric acid and from 5 to 15 weight percent hydro-
23 chloric acid (generally called "Mud Acid") are employed to treat the
24 damaged formations. The low pH conditions provided by the hydrochloric
acid is beneficial in solubilizing the products formed by the reaction
26 between hydrofluoric and the formation material. This HF-HC1 treating
27 solution .eacts most rapidly with calcite, rapidly with clay, less
28 rapidly with other silicates, and slowest with the silica of natural
29 sands. The precise rates of these reactions are largely controlled by
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1 the concentration of hydrofluoric acid in ~he treating solution. The
2 higher the hydrofluoric acid concentration the more rapid the reaction
3 rate.
4 Because the reaction of hydrofluoric acid on silica and clay
is generally rapid at formation temperatures (120-220F), a majority of
6 the acid solution becomes spent within a radius of about 24 inches from
7 the wellbore and a lesser amount of active acid solution penetrates
8 beyond this distance. Moreover, because the majority of the reaction
9 occurs within a small volume of the formation matrix, the concentration
of reaction products (some of which may precipitate) and fines liberated
11 by the reaction may cause permeability impairment if the hydrofluoric
12 acid concentration is too high.
13 Because the materials plugging the porous formation of rock
14 are only removed for a short distance around the well, invasion of the
treated region by new fine particles can occur after a short period of
16 time. These fine particles are believed to originate deeper in the
17 formation and are carried toward the wellbore by the flowing fluid
18 during production. A method for achieving deeper acid penetration would
19 remove these particles to a greater radius from the wellbore, thereby
lengthening the time required for fines to migrate back to the well.
21 Localized spending of hydrofluoric acid near the wellbore may
22 also result in increased water production. Hydrofluoric acid injected
23 into the wellbore reacts readily at the interface between the formation
24 rock and the cement used to set the wellbore casing. A channel may be
formed along this interface which can allow water from the nearby strata
26 to reach the producing well. Elimination of this problem requires that
27 the concentration of hydrofluoric acid in solution be low as fluids are
28 injected into the formation past the formation-cement interface.
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1 A plastic consolidation of incompetent sands is strongly
2 effected by the quality of any preceding acid treatment. The compressive
3 strength of a plastic consolidation decreases as the clay content of the
4 sand increases. It is observed that the strength profile of the consoli-
5 dation parallels the clay removal profile by the acid. To have high
6 consolidation strengths over the formation volume to be consolidated,
7 clay should be thoroughly and evenly removed from that volume.
8 Numerous procedures have been suggested to obtain substantial
9 penetration of hydrofluoric acid into the formation. One method comprises
10 contacting an oil-containing sandstone formation with a surface-active
11 compound to render the surfaces of the formation sands oil-wet, thereby
12 imparting hydrophobic properties to the formation. As a result of the
13 formation having hydrophobic properties, the reaction rate of hydrofluoric
14 acid within the formation is retarded, thereby enhancing acid penetration
15 into the formation.
16 Another method, as described in U.S. 3,828,854, issued to
17 Templeton et al on August 13, 1974, generates hydrofluoric acid in situ.
18 In this method, an aqueous solution of a water soluble fluoride salt is 3
19 mixed with a relatively slowly-reactive acid-yielding material that
20 subsequently converts the fluoride salt solution to a hydrofluoric acid
21 solution that has a relatively high pH (at least about 2), but is capable
22 of dissolving siliceous materials. In the preferred embodiment, the
23 fluoride salt is an ammonium salt of hydrofluoric acid and the acid-
24 yielding material is a formic acid ester. One problem with this method
25 is that the formic acid formed from the ester hydrolysis is a weak acid
26 so that the pH of the treating solution formed is relatively high. In
27 this relatively high pH solution, the hydrofluoric acid concentration is
28 relatively low so that the rate and the extent of the reaction with the
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1 formation matrix is consequently low. For any fluoride ion concentration,
2 the pH should be reduced to at least about 1 to maximize hydrofluoric
3 acid generation from fluoride ion and to effectively solubilize reaction
4 products. This process is further limited by the solubility of the
formic acid ester in ammonium fluoride solutions. The total amount of
6 hydrofluoric acid which can be formed by this process is limited by the
7 amounts of formic acid and ammonium fluoride which can be combined in
8 solution.
9 Another hydrofluoric acid generation method (as described in
SPE Paper No. 6512 entitled "A New Technique for Generating In-Situ
11 Hydrofluoric Acid for Deep Clay Damage Removal" by B. E. Hall, presented
12 at the 47th Annual California Regional Meeting of the SPE on April 13-
13 15, 1977) is multi sequential injection of fluoride ion solution followed
14 by a hydrochloric acid solution. The beneficial effect of this pro-
cedure is ascribed to the adsorption of fluoride ions on the anion
16 exchange sites of the clay minerals followed by activation of the
17 adsorbed fluoride ions by a pursuing hydrochloric acid solution. The
18 effectiveness of this process is limited by the anion exchange capacity
19 of the resident clay. Since most clays have a small anion exchange
capacity, the amount of hydrogen fluoride produced by this method is
21 also small.
22 A need still exists for an improved technique for generating
23 hydrofluoric acid in a formation which overcomes the problems associated
24 with rapid spending of the acid solution within a short radial distance
from the wellbore.
26 SUMMARY OF THE INVENTION
27 In accordance with the present invention, the hydrofluoric
28 acid is formed by combining an aqueous solution of a fluoride salt and
29 an aqueous solution of an acid in the pore spaces O r the formation.
This is accomplished by immobilizing one of the aqueous solutions, in
31 the pore spaces of the formation by displacing solution with a liquid
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phase that is substantially immiscible with said aqueous phase, thereby
driving said aqueous solution to a saturation at or below its residual
saturation. The second aqueous solution is then injected into the formation.
More particularly, the present invention provides a method for
acidizing a subterranean siliceous formation surrounding a wellbore
wherein at least two aqueous solutions are injected into the formation, one
of the aqueous solutions containing a fluoride salt and the other aqueous
solution containing an acid, the improvement comprising the steps of
~ (a) injecting into the formation one of said aqueous solutions,
(b) injecting into the formation a liquid that is substantially
immiscible with said injected aqueous solution in an amount
sufficient to substantially reduce the saturation of the
injected aqueous solution in a substantial portion of the
formation invaded by said aqueous solution in step (a); and
- (c) injecting into the formation the other aqueous solution,
said acid in one of said aqueous solutions combining with
fluoride salts in the other aqueous solution to form
hydrofluoric acid which is capable of dissolving siliceous
material.
In a preferred embodiment, water containing an ammonium salt of
hydrofluoric acid is injected into the formation to be treated. The salt
solution is then followed by a hydrocarbon liquid such as diesel oil to
reduce the saturation of the salt solution to residual saturation. After
the hydrocarbon liquid has been injected, hydrochloric acid solution is
injected into the formation. The acid solution contacts the ammonium fluoride
salts to form hydrofluoric acid which is capable of dissolving siliceous
material in the formation.
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Other embodiments of this invention include adding various
additives such as viscosifiers, surface active compounds and corrosion
- inhibitors to the aqueous fluoride-containing solution and/or the
injected hydrocarbon liquid and/or the aqueous acid-containing solution.
It is particularly preferred in the practice of this invention to inject
into the formation an aqueous fluoride-containing solution which also
contains a viscosifier such as a salt of poly 2-acrylamido-2-methyl
propyl sulfonate and to inject into the formation a hydrocarbon which
also contains one or more preferentially oil soluble surface-active
compounds such as ethylene glycol monobutyl ether and/or sorbitan
monooleate
It is also particularly preferred in the practice of this
invention to follow the aqueous fluoride containing solution with two
sequential volumes of diesel oil; the first volume containing surface
active compounds and the second volume being substantially free of
surface-active compounds.
The practice of this invention provides an improved process
for generating hydrofluoric acid in a formation. By this process,
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1 hydrofluoric acid is continuously generated at and behind the advancing
2 hydrochloric acid front as it displaces the hydrocarbon liquid which
3 immobilized the fluoride salt solution from the pore spaces. In this
4 way hydrofluoric acid is generated at deeper radial depths into the
formation than practicable prior to this invention. This invention sub-
6 stantially alleviates the problems associated with rapid spending of
7 hydrofluoric acid within a short radial distance from the wellbore.
8 BRIEF DESCRIPTION OF THE DRAWINGS
9 FIGURES 1 A-E are graphic illustrations of a formation showing
the percentage saturations of fluids in the formation at various stages
11 in the processes of this invention.
12 FIGURE l-A shows the formation oil and water saturations prior
13 to the practice of this invention.
14 FIGURE l-B shows the formation fluids saturations as an
aqueous fluid containing fluoride salts is injected into the formation.
16 FIGURE l-C shows the formation fluid saturations as a hydro-
17 carbon fluid such as diesel oil is injected into the formation.
18 FIGURE l-D shows the formation fluid saturations wherein the
19 oil has reduced the saturation of the fluoride-containing fluid tG
residual saturation.
21 FIGURE l-E shows the formation fluid saturations as an aqueous
22 solution containing an acid is injected into the formation.
23 FIGURE 2 is a graph of laboratory tests on several sand samples
24 showing the relation between clay content in percent and distance in
inches from the ends of the samples into which fluids were injected.
26 The results illustrated in this FIGURE show the improvement of the
27 present invention over several prior ar-t processes.
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1 DESCRIPTION OF THE PREFERRED EMBODI~IENTS
2 The present invention is particularly useful for treating a
3 subterranean sandstone formation to improve effective permeability by
4 dissolving siliceous materials. These materials may comprise fine
particles of sand, clay, silica or other silicate minerals, as well as
6 intergranular cementing material in the pores of a subterranean formation,
7 or a sand or gravel pack in the borehole of the well.
8 The present invention is an improved technique for generating
- 9 hydrogen fluoride in a subterranean sandstone formation. In a preferred
embodiment of this invention fluoride ion-containing salt solution is
11 injected into the formation and then immobilized in the pore spaces of
12 the formation by injection of a hydrocarbon liquid. An aqueous solution
13 containing an acid is then injected into this formation to generate
14 hydrofluoric acid. The method effectively produces hydrofluoric acid
uniformly over the entire region containing immobile fluoride compounds.
16 Substantial penetration of the formation can therefore be achieved with
17 the active acid solution of hydrochloric and hydrofluoric acids.
18 The practice of a preferred embodiment of this invention may
19 be explained more clearly by referring to FIGS. lA, B, C, D, and E.
FIGURE l-A illustrates the oil and brine saturation in the subterranean
21 formation prior to the practice of this invention. In this portion of
22 the formation, the oil saturation is considered to be at residual oil
23 saturation. This condition which will exist after brine is injected
24 into an oil-bearing reservoir. FIGS. l B-E show the formation fluid
saturations as the formation is being flooded with fluids in accordance
26 with this invention. Advancing fluid fronts are shown by vertical
27 lines, but it is understood that such interfaces are usually irregular
28 and are not well defined.
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1 The first step in this embodiment is to inject into the forma-
2 tion by means of a well an aqueous solution containing a fluoride salt.
3 As shown in FIGURE l-B, the fluoride-containing solution drives the
4 brine away from the wellbore and bypasses the residual oil in the forma-
tion pore spaces. After a suitable amount of the aqueous liquid has
6 been injected, a hydrocarbon solution such as diesel oil is injected
7 into the formation. As shown in FIGURE l-C, the injected oil drives the
8 mobile aqueous fluoride-containing solution away from the wellbore
9 leaving an immobile residual saturation of the fluoride-containing
solution. If a sufficient amount of oil is injected into the formation,
11 the oil will reduce essentially all the fluoride-containing solution to
12 its residual saturation (as depicted in FIG. l-D). By definition when
13 the fluoride-containing solution is at or below its residual saturation,
14 it cannot flow (it is immobiliæed) as oil phase flows through the pore
space around it. After a suitable amount of hydrocarbon has been injected,
16 an aqueous solution containing an acid is injected in the formation.
17 The acid solution drives the mobile hydrocarbon away from the wellbore,
18 replaces the displaced oil with aqueous acid and reduces the oil satura-
19 tion in the formation to its residual saturation. The aqueous fluoride-
containing solution is not displaced ahead of the acid solution. Rather,
21 the acid solution mixes with the previously residual fluoride ion-
22 containing solution as it is encountered to continuously form hydrogen
23 fluoride at the advancing acid front. The generation of hydrogen fluoride24 continues for some distance behind the acid front as fluoride ions
diffuse out of the smaller pore spaces and acid diffuses into them. The
26 hydrogen fluoride thus generated can dissolve siliceous materials in the
27 formation. Since the clay minerals react with hydrogen fluoride several
28 orders of magnitude faster than other siliceous materials, clay is
29 preferentially removed.
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1 The aqueous fluid containing fluoride salt is preferably
2 formed from water which is substantially free of metal ions because many
3 metal ions complex or precipitate fluoride ions or reaction products
4 thereof.
The amount of fluoride-containing fluid injected will vary
6 depending on the extent of formation damage, the formation porosity, and
7 the permeability of the formation to flow of aqueous fluoride-containing
8 solution. Generally about l barrel to about 20 barrels of liquid are
9 injected per foot of formation interval to be treated.
The water-soluble fluoride salts used in the present invention
11 can comprise one or more of substantially any fluoride salt that is
12 water soluble. Ammonium salts of hydrofluoric acid, i.e. ammonium
13 fluoride or ammonium bifluoride, are preferred fluoride salts for use in
14 the present process. In using ammonium bifluoride (NH4HF2) it may be
desirable to add enough ammonia or ammonium hydroxide to provide sub-
16 stantially equimolar amounts of ammonium and fluoride ions.
17 The concentration of fluoride salt in the aqueous solution can
18 vary widely depending on the degree of damage to be removed and porosity
19 of the formation. As is well known, the amount of siliceous material
that will be dissolved can be increased by increasing the concentration
21 of the hydrofluoric acid. Therefore, it is generally preferred to
22 contact the siliceous material with a strong solution. In many prior
23 art processes, strong HF solutions cause permeability damage due to
24 reaction generated pricipitates and fines. For example, permeability
damage frequently occurs when a high HF concentration is injected at the
26 formation face because a majority of the reaction with the formation
27 matrix occurs in the small formation volume near the face. In the
28 present invention permeability damage is alleviated because hydrogen
29 fluoride is generated over the entire region containing fluoride salts
so that the concentration of reaction generated precipitates and fines
31 remains low and uniformly distributed.
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1 The liquid injected into the formation after injection of the
2 aqueous liquid-containing fluoride salts may be any liquid which is
3 substantially immiscible with the aqueous fluoride-containing solution
4 and will immiscibly displace aqueous liquids in a porous medium. Examples
of suitable liquids include perflurohexane, perflurooctane, cyclohexanone,
6 dioctyl ether, decanol, and hydrocarbons including kerosene, light
7 crude oil, diesel oil, and xylene. For economic reasons, the aqueous
8 immiscible liquid will most frequently be a hydrocarbon. The use of
9 diesel fuel or similar low viscosity petroleum fraction is generally
preferred.
11 The amount of hydrocarbon or other liquid immiscible with the
12 aqueous solution injected into the formation will vary depending on the
13 amount of fluoride-containing solution injected into the formation.
14 Preferably, a sufficient volume of liquid is injected to reduce sub~
stantially all of the fluoride-containing solution to residual fluid
16 saturation. Generally the volume of injected hydrocarbon will be about
17 the same as the volume of the injected aqueous solution containing
18 fluoride salts.
19 In the most preferred embodiment, two hydrocarbon-volumes will
be injected sequentially. In this embodiment, the first volume will
21 contain a low molecular weight preferentially oil soluble surface-active
22 agent such as ethylene glycol monobutyl ether and/or a higher molecular
23 weight preferentially oil soluble surface-active agent such as sorbitan
24 monooleate. The second volume will contain no surface active agent.
The object of this two-volume sequence is to reduce the fluoride salt
26 containing solution to a saturation substantially below the residual
27 satuation obtainable with the untreated hydrocarbon fluid. This lower
28 saturation will further assure immobilization of the fluoride solution
29 after injection of the untreated hydrocarbon fluid and will minimize the
volume of any subsequent mixing zone between fluoride solution and
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1 pursuing acid solution. Each hydrocarbon volume may be about the same
2 as the volume of injected aqueous fluoride solution.
3 Any water soluble acid generally employed in acidizing treat-
4 ments may be utilized in the practice of this invention. Suitable acids
include, for example, halogen acids such as HCl, HI, and HBr; mineral
6 acids such as sulfuric, nitric, and phosphoric; organic acids such as
7 acetic, proponic acid, and formic acid; modified organic acids such as
8 mono-, di-, and trichloroacetic acids; and, various mixtures thereof.
9 Hydrochloric acid (HCl) is generally preferred. The acid solution can
contain up to about 38% by weight of these acids.
11 Viscosity increasing agents may be added to any of the injected
12 fluids in the practice of this invention. Preferably the aqueous fluoride-
13 containing solution has a higher viscosity than the injected hydrocarbon
14 fluid and this hydrocarbon fluid preferably has a higher viscosity than
the aqueous solution containing acid. This viscosity relationship
16 allows the fluoride-containing solution to efficiently displace the
17 resident aqueous fluids from the pore space. It also reduces fluoride
18 displacement by the aqueous solution containing acid. A suitable visco-
19 sifier for use in the aqueous fluoride-containing solution may include a
salt of poly-2-acrylamido-2-methyl propyl sulfonate, or other polymeric
21 sulfonate salt.
22 A sufficient amount of acid is preferably injected into the
23 formation to react with all of the fluoride salts injected in the forma
24 tion. It is particularly preferred to inject acid in a significant
stoichiometric excess relative to the amount of the fluoride salts in
26 the formation. High concentrations of acid are preferred so as to
27 maximize the concentration of hydrofluoric acid formed at the acid front
28 as it displaces the hydrocarbon bank and assure penetration into the
29 formation of hydrochloric acid to the same radial extent to which the
fluoride salt solution has been immobilized. Acid concentrations in
31 excess of 2 molar are preferred.
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1 Various additives such as corrosion inhibitors, demulsifying
2 agents, surfactants, and viscosifiers, may be added to the aqueous fluid
3 containing fluoride salts, to the hydrocarbon fluid and/or the acid
4 solution. Suitable inhibltors include the inorganic arsenic compounds,
acetylenic alcohols, thiophenols, quaternary ammonia compounds and
6 similar organic agents. Almost any of the surfactants capable of reducing
7 interfacial tension between oil and water may be used in this invention.
8 The surface-active agents selected, of course, should be compatible with
9 the injected hydrocarbon, the fluoride salts, and the acid solution. In
the preferred case, they should be preferentially oil soluble and be
11 placed in the injected hydrocarbon. Specific surface active materials
12 which may be employed include, for example, ethylene glycol monobutyl
13 ether and sorbitan monooleate.
14 In performing the matrix acidizing treatment in accordance
with this invention, it is desirable to inject all fluids without
16 fracturing the formation. The formation fracture pressure can be de-
17 termined by conventional computation techniques employing known or
18 estimated properties of the formation. This pressure limitation de-
19 termines the rate at which the acid solution can be injected. Normally
from l to 20 barrels of fluoride salt solution per foot of formation,
21 internal to be treated is injected at a rate ranging between about 0.25
22 barrels to 5 barrels per minute.
23 Another embodiment of the present invention is to inject into
24 the formation by means of a well an aqueous solution containing an acid
preferably hydrochloric acid. This acid solution is then immobilized by
26 injecting into the formation a liquid, preferably a hydrocarbon, which
27 is substantially immiscible with the acid solution. An aqueous solution
28 containing a fluoride salt, preferably an ammonium salt of hydrofluoric
29 acid, is then injected into the formation. The fluoride salt will
contact the acid to form hydrofluoric acid.
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1 A further embodimen. of this invention is to inject a liquid
2 preflush into the formation prior to injection of the fluoride-
3 containing solution. In this embodiment an acid solution is injected
4 into the formation. This acid may be intended to react with calcite and
other carbonate materials in the formation and thus alleviate undesirable
6 dissipation of the hydrogen fluoride generated at a later stage of the
7 process. In this case the acid solution is preferably hydrochloric
8 acid. The acid so]ution may also be intended to break down the perfora-
9 tions in the casing and thereby establish good communication between the
well bore and the siliceous formation. In this case the acid solution
11 is preferably a mixture of hydrochloric and hydrGfluoric acids known as
12 mud acid. This acid solution should then be followed with an aqueous
13 solution, preferably an ammonium chloride solution, neutralized with
14 ammonium hydroxide, or ammonium carbonate or ammonium bicarbonate. This
aqueous solution serves to displace acid from the formation pore space
16 to be treated so as to prevent premature activation of the fluoride ion
17 containing solution of this invention which may limit its penetration
18 into the formation.
19 In still another embodiment of this invention, the steps in
carrying out this invention may be repeated at least once. For example,
21 two or more cycles of the following steps may be carried out in the
22 practice of this invention (a) injecting into the formation an aqueous ;~
23 solution containing fluoride salts, (b) injecting into the formation a
24 hydrocarbon liquid, and (c) injecting into the formation an aqueous
solution containing an acid.
26 Laboratory Tests
27 In order to demonstrate the effectiveness of this invention,
28 laboratory tests were run comparing various embodiments of this invention
29 with treatments typical of the prior state-of-the-art. The tests will
be referred herein as Tests A, B, C, D, E, F, and G. Tests A and B
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1 comprised alternately injecting solutions containing ammonium fluoride
2 and hydrochloric acid. Tests C, D, and E comprised embodiments of the
3 present invention. Test F comprised injecting common mud acid. Test G
4 comprised injecting a solution of ammonium fluoride and methyl formate.
All the tests used sand samples consisting of sand from the
6 bank of the Brazos River packed into rubber sleeves 48 inches long. In
7 tests A, B, C, F, and G the sleeve was 1 inch in diameter and in tests D
8 and E the sleeve was 1-1/2 inch in diameter. The rubber sleeves were
9 then encased in a steel cylinder and compressed with hydraulic fluid to
maintain a dense pack during the test. The tests were conducted at a
11 temperature of 150F. After treatment, the sand packs were removed from
12 the steel cylinders and the rubber sleeves were opened. The clay
13 content was determined on the sand samples collected along the length of
14 the sand pack. Clay content was determined by its cation exchange
capacity from a methylene blue titration according to the method described
16 in Bulletin API RP 13B entitled, "Standard Procedure for Testing Drilling
17 Fluids", published in February, 1974 by the American Petroleum Institute.
18 The following describes the treatment steps on the sand samples
19 for Tests A, B, C, D, E, F, and G. The hydrochloric acid solutions used
in these tests typically contained a commercial corrosion inhibitor,
21 Corexit 8503, sold by Exxon Chemical Company.
22 Test A
23 The sand pack used for this test was l-inch in diameter and 48-
24 inches in length. The pore volume (PV) was 205 cubic centimeters (cc).
During the acidizing test sequence, all fluids were pumped at a flow
26 rate of 7cc per minute.
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1 1. To prepare the sand sample for the test, calcium carbonate was
2 removed from the sand by pumping:
3 (a) 1.0 PV 8 wt% NaCl brine
4 (b) 7.3 PV 3 wt% HC1
2. The acidizing test was conducted by pumping 6 cyles of treating
6 chemicals. Each cycle consisted of:
7 (a) 0.13 PV 5 wt% HCl with 0.1 volume percent Corexit 8503
8 (b) 0.13 PV 0.8 molar NH4F in water (pH 8.5)
9 3. To prepare the sand for clay analysis, it was necessary to
remove all resident fluid from the sand pack. This was
11 accomplished by pumping:
12 (a) 1.0 PV 5 wt% HCl with 0.1 vol% Corexit 8503
13 (b) 0.5 PV ethylene glycol isopropyl ether
14 (c) 1.20 PV pentane
The sand pack was then blown dry with nitrogen
16 TEST B
17 This test was conducted in essentially the same manner as described
18 for test A except that in step number two, 16 cycles of treating chemicals
19 were used.
TEST C
21 The sand pack used for this test was l-inch in diameter and 48-
22 inches in length. The pore volume was l90cc. During the acidizing test
23 sequence, all fluids were pumped at a flow rate of 7cc per minute.
24 (a) 1.0 PV 8 wt% NaCl brine
(b) 7.5 PV 3 wt% HCl
26 (c) 0.25 PV 15 wt% HCl with 0.4 vol% Corexit 8503
27 (d) 0.50 PV 4 wt% NH4Cl brine
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1 2. The acidizing test was conducted by pumping:
2 ; (a) 0.25 PV 6 molar NH4F in water (pH 8.5)
3 (b) 0.25 PV diesel oil
4 (c) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503
3. To prepare the sand for clay analysis, it was necessary to
6 remove all resident fluid from the sand pack. This was
7 accomplished by pumping:
8 (a) l.0 PV l wt% HCl
9 (b) O.S PV ethylene glycol mono isopropyl ether
(c) 1.2 PV pentane
11 The sand pack was then blown dry with nitrogen gas.
12 Test D
13 The sand pack used for this test was 1-1/2 inches in diameter
14 and 48 inches in length. The pore volume was 435cc. During the
acidizing test sequence, all fluids were pumped at a flow rate of 15cc
16 per minute.
17 1. To prepare the sand for the test, calcium carbonate
18 was removed from the sand by pumping:
l9 (a) 1.0 PV 8 wt% NaCl brine
(b) 7.5 PV 3 wt% HCl plus 4 wt% N~4Cl
21 (c) 0.25 PV 15 wt% HCl with 0.5 vol % Corexit 8503
22 (d) 1.5 PV 4 wt% NH4Cl brine
23 2. The acidizing test was conducted by pumping:
24 (a) 0.25 PV 10 molar NH4F in water (pH 8.5)
(b) O.S0 PV diesel oil
26 (c) 0.50 PV diesel oil containing 15 vol % ethylene glycol
27 monobutyl ether (a surface-active compound)
28 (d) 1.25 PV diesel oil
29 (e) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503
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3. To prepare the sand for clay analysis, it was necessary to
2 remove all of the resident fluid from the sand pack. This
3 was accomplished by pumping:
4 (a) l.0 PV l wt% HCl
(b) 0.50 PV isopropyl alcohol
6 (c) 1.5 PV pentane
7 The sand pack was then blown dry with nitrogen gas.
8 TEST E
9 The sand pack used for this test was l-l/2 inches in diameter and
48 inches in length. The pore volume was 455cc. During the acidizing
11 test sequence, all fluids were pumped at a flow rate of 15cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was
13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine
(b) 7.5 PV 3 wt% HCl plus 4 wt% NH4Cl
16 (c) 0.25 PV 15 wt% HCl with 0.5 vol% Corexit 8503
17 (d) 1.5 PV 4 wt% NH4Cl brine
18 2. The acidizing test was conducted by pumping:
19 (a) 0.35 PV 10.3 molar NH4F in water (pH 8.5)
containing 0.3 wt% poly 2-acrylamido-2-methyl
21 propyl sulfonate (a viscosifier)
22 (b) 0.50 PV diesel oil
23 (c) 0.50 PV diesel oil containing 10 vol% ethylene glycol
24 monobutyl ether (a surface-active compound) and
containing 0.2 vol% sorbitan monooleate (a
26 surface-active compound)
27 (d) 0.50 PV diesel oil
28 (e) l.0 PV 30 wt% HCl with 0.6 vol% Corexit 8503
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1 3. To prepare the sand for clay analysis, it was necessary to
2 remove all of the resident fluid from the sand pack. This
3 was accomplished by pumping:
4 (a) l.0 PV 1 wt% HCl
(b) 0.50 PV isopropyl alcohol
6 (c) 1.5 PV pentane
7 The sand pack was then blown dry with nitrogen gas.
8 TEST F
9 The sand pack used for this test was l inch in diameter and
48 inches in length. The pore volume was 200cc. During the acidizing
11 test sequence, all fluids were pumped at a flow rate of 7cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was
13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine
tb) 7.5 PV 3 wt% HCl
16 2. The acidizing test was conducted by pumping: -
17 (a) 1.0 PV 3 wt% HF plus 12 wt% HCl containing 0.5 vol%
18 Corexit 8503
19 3. To prepare the sand for clay analysis it was necessary to
remove all the resident fluid from the sand pack. This was
21 accomplished by pumping:
22 (a) 0.50 PV ethylene glycol mono isopropy]. ether
23 (b) 1.20 PV pentane
24 The sand pack was then blown dry with nitrogen gas.
TEST G
26 The sand pack used for this test was 1 inch in diameter and
27 48 inches in length. The pore volume was 170cc. During the acidizing
28 test sequence, all fluids were pumped a~ a flow rate of 7cc per minute.
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1 1. To prepare the sand for the test, calcium carbonate
2 was removed from the sand by pumping: -
3 (a) 1.0 PV 8 wt% NaCl brine
4 (b) 7.5 PV 3 wt% HCl plus 6 wt% NaCl
(c) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03
6 (d) 1.3 PV 4 wt% NH4Cl brine
7- 2. The acidizing test was conducted by pumping:
8 1.1 PV 1 molar NH4F plus 2 molar methyl
9 formate in water
3. To prepare the sand for clay analysis, it was necessary to
11 remove all resident fluid from the sand pack. This was
12 accomplished by pumping:
13 (a) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03
14 (b) 0.5 PV ethylene glycol mono isopropyl ether
(c) 1.20 PV pentane
16 The sand pack was then blown dry with nitrogen gas.
17 Results of tests A, B, C, D, E, F, and G are set forth in
18 FIGURE 2 which shows the relation between the clay content in percent of
19 the sand in the test samples and the distance in inches from the injection
ends of the samples. The Brazos River sand used in these tests had an
21 initial clay content of 6.0 to 6.5 weight percent. This clay had an
22 ion exchange capacity of 0.58 milliequivalents per gram.
23 Curve F in FIGURE 2 is typical of the results obtained when
24 conventional mud acid (3 wt% HE, 12 wt% HCl) is used for clay removal.
Near the injection face, the remaining clay content is less than one-
26 half of one percent. The clay content rises slowly to 1% at 24 inches
27 from the injection face, and then rises more rapidly approaching 6% clay
28 at 48 inches from the injection face. Examination of the sand after the
29 acid treatment revealed a large loss of silica within 2 to 3 inches of
the injection face. It is this localized reaction zone that can break
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1 down the interface between the rock and the cement used to set the
2 wellbore casing thereby forming a path for undesirable water or gas to
3 reach the producing interval.
4 Curve G shows the results obtained with one prior art method
for generating hydrofluoric acid in the formation pore spaces. A mixture
6 of ammonium fluoride and methyl formate was injected into the pore
7 space. The methyl formate hydrolyzed in the pore space to form formic
8 acid which in the presence of ammonium fluoride generated hydrofluoric
9 acid. As shown in FIGURE 2, the amount of clay dissolved by this tech-
nique was small. Clay dissolution did occur fairly uniformly throughout
11 the entire sand volume with no obvious silica dissolution at the injection
12 face.
13 Curves A and B in FIGURE 2 represent another prior art process
14 to generate hydrofluoric acid in the pore space. In this method, alter-
nate volumes of aqueous ammonium fluoride and hydrochloric acid are
16 pumped through the sand. There is no attempt to immobilize the liquids
17 containing fluoride or acid. The reported mechanism for hydrofluoric
18 acid generation is the attachment of fluorine ions to the anion exchange
19 sites of the clay minerals. Subsequent contact with hydrochloric acid
generates hydrofluoric acid in the pore space. To achieve significant
21 clay removal, it is recommended to use multiple cycles of the NH4F-HCl
22 injection sequence. Curve A is the result from injecting 6 cyles of
23 treating fluids into a sand pack. About 50% of the clay in the sand
24 pack was removed by this treatment.
Increasing the number of NH4~-HCl cycles to 16 gives curve B
26 in FIGURE 2. Clay removal by this treatment was only slightly better
27 than the 6 cycle case, even though almost 3 times as much fluoride ion
28 was injected. Apparently, most of the fluoride ions are flowing through
29 the sand without encountering hydrochloric acid or generating hydro-
fluoric acid.
.,
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1086637
1 Curve C in FIGURE 2 is the result obtained by treating the
2 sand with one of the embodiments of the current invention. The injection
3 sequence consisted of an ammonium fluoride solution followed by diesel
4 oil and finally a strong hydrochloric acid solution. This test shows
this treatment sequence is an improvement over the prior art techniques
6 discussed above. This improvement is attributed to the immobilization
7 of the ammonium fluoride solution by the diesel oil. The diesel oil
8 drives the fluoride solution to a saturation approaching residual water
9 saturation leaving the sand pack substantially free of mobile aqueous
liquid.
ll At residual water saturation, the aqueous fluoride solution
12 primarily occupies the smaller pore spaces while diesel occupies the
13 larger pore spaces. When hydrochloric acid is injected, it can readily
14 displace diesel from the interior of the large pore spaces with only a
small amount of fluoride displacement from the smaller pore spaces.
16 Owing to diffusion and mixing, the coexistence of fluoride ion and
17 hydrochloric acid in the pore space leads to the rapid generation of
18 hydrofluorice acid.
19 As shown by Curve C, the clay removal capability of this
treatment is better than any of the prior art techniques for generating
21 hydrofluoric acid in the pore space. In addition, no apparent silica
22 dissolution occured near the injection face using the treatment designed
23 in accordance with this invention. This feature overcomes one of the
24 primary drawbacks to conventional mud acid treatments.
Another embodiment of the current invention is to employ a
26 surface active material in the diesel oil. The result of employing
27 ethylene glycol monobutyl ether (EGMBE) as a surface active material in
28 the diesel is shown as Curve D in FIGURE 2. The ammonium fluoride
29 solution was followed by diesel oil which drove the NH4F solution to a
residual saturation of 37% by volume. Following this with diesel oil
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containing 15 volume percent EGMBE lowered the fluoride solution satura-
_ - 2 tion to 30%. Injection of untreated diesel oil completed the fluoride
3 immobilization sequence. With untreated diesel in the pore space, the
4 aqueous phase becomes mobile when the aqueous saturation Eeaches or
e~ceeds 37%. Since the fluoride solution saturation had been reduced to
6 30% by the diesel-EGMBE mixture, the fluoride solution is not mobilized
7 by untreated diesel oil injected into the pore spaces.
8 Injecting hydrochloric acid into a sand prepared in the manner
9 described for Test D results in less displacement of the fluoride con-
taining solution and consequently greater clay removal than Curve C.
11 Once again, silica dissolution at the injection face was avoided by the
12 use of this invention.
13 As previously described, another emboidment of this invention
14 is the use of an agent to increase the viscosity of the aqueous fluoride
solution. The addition of 0.3 wt% of the potassium salt of poly-2-
16 acrylamido-2-methyl propyl sulfonate (PAMPS) can increase the viscosity
17 of a 10-molar NH4F solution from 3 centipoises to 5 centipoises. Curve
18 E in FIGURE 2 was generated in a manner similar to curve D except that
19 0.3 wt~o PAMPS was included in the fluoride solution. The increased
viscosity of the fluoride solution allowed it (l) to more efficiently
21 displace the resident aqueous fluid from the sand, and (2) to resist
22 being displaced itself by the aqueous hydrochloric acid solution.
23 Comparison of Curve E with the other clay removal data in
24 FIGURE 2 shows it to be clearly superior to other techniques for gener-
ating hydrofluoric acid in the pore spaces. In fact, the clay removal
26 capability of this treatment approaches that for conventional mud acid
27 over the first 18 inches of the sand and is superior to mud acid in the
28 region beyond 18 inches. It is important to emphasize that unlike
29 conventional mud acid, silica dissolution was not observed at the
injection face with the current invention.
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1 Field Example
2 This example is provided to show how one embodiment of this
3 invention may be practiced in a field application. The sandstone
4 formation treated in this example is penetrated by a well. The forma- ;
tion has a porosity of 35 percent. The treatment ror this well is
6 designed to penetrate a 4-foot radius surrounding the well over any
7 desired formation interval. The formation has a pore volume of 130
8 gallons per foot of the formation interval. If the formation contains
g carbonate minerals or it is desired to break down the perforations in
the casing, a mixture containing 12 weight percent HCL and 3 weight
11 percent HF acids may be injected as a preflush liquid. All fluid injec-
12 tion should be at a rate which maintains the injection pressure below
13 the formation fracture pressure. After the preflush, if carried out, 50
14 gallons per fcot of formation interval of an aqueous solution containing
4 weight percent NH4Cl is injected into the formation by means of the
16 well. This amount of ammonium chloride is injected into the formation
17 because generally about 1/3 pore volume is required to displace resident
18 aqueous fluids from the zone to be treated. About 40 gallons of an
19 aqueous solution containing 10.5 molar ammonium fluoride which contains
3000 parts per million potassium salt of poly 2-acrylamido-2-methyl
21 propyl sulfonate (PAMPS) is injected into the formation per foot of
22 formation interval. The amount of ammonium fluoride solution injected is
23 slightly more than the actual residual volume for the formation being
24 treated. The PAMPS is included in the ammonium fluoride solution to
increase the solution viscosity to about 5 centipoises. After injection
26 of the ammonium fluoride solution, 50 gallons of diesel oil with 10% by
27 volume of ethylene glycol monobutyl ether (EGMBE) is injected into the
28 formation per foot of interval. Thereafter, 50 gallons per foot of
29 diesel oil without EGMBE is injected into the formation. After the
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1 diesel oil is injected, 100 gallons per foot of an aqueous solution
2 containing 28 weight percent of HCl is injected into the formation. The
3 well is then returned to production.
4 It should be apparent that the foregoing method of the present
invention offers significant advantages over sandstone acidizing methods
6 previously known in the art. It will be appreciated that while the
7 present invention has been primarily described with regard to the
8 foregoing embodiments, it should be understood that several variations
9 and modifications may be made in the embodiments described herein
without departing from the broad inventive concept disclosed herein.
