1. Field of the Invention
This invention pertains to the stimulation of wells to improve the permeability of such wells to the flow of fluids. The invention is especially useful in improving the flow of hydrocarbons from wells which have suffered from formation damage due to clay deposits.
2. Description of the Prior Art
It is well known that oil production in siliceous subterranean formations, over the useful life of a well, usually decreases with time. To reestablish a higher flow of oil, one of the first methods usually employed is pumping. Frequently, however, after a period of time, even pumping will not make the well economical. Unfortunately in many wells such flow reduction occurs long before the oil, or other fluid in the reservoir reached by the wellbore, has become depleted. Low permeability frequently results from the deposition of clay and other finely divided material in the pore structure or flow passages of the formation. Clay particles, capable of forming such undesirable deposits, generally exist throughout the formation and are carried by the oil and deposited in the flow passages leading to the wellbore. Formation damage can also be caused by the swelling of the clay upon contact with foreign liquids injected for well development or stimulation purposes. Formation damage of the above types is often referred to as clay deposits, clay dispersions, particle plugging, clay swelling, etc., which hereinafter will simply be referred to collectively as "pore deposits."
It is known that pore deposits can be solubilized more or less by treatment with mineral acid solutions, for example, hydrochloric acid and hydrofluoric acid. Aqueous solutions containing about 2 to 6 weight percent hydrofluoric acid and 5 to 15 weight percent hydrochloric acid, sometimes referred to as "mud acids" have been used to treat damaged formations in hopes of restoring to the formation its initial permeability. Mud acids have also been used to treat formations which are naturally tight.
Unfortunately, hydrochloric acid is usually not effective in solubilizing the more tenuous pore deposits such as those deposits that are mainly siliceous in composition. By the term "siliceous" as used herein is meant silica and/or silicate. By the term "siliceous material" as used herein is meant silica-containing and/or silicate-containing materials. Examples of siliceous materials are sandstone and certain clays. Non-limiting example of clays which are silicates, usually aluminosilicates are attapulgite, bentonite, chlorite, halloysite, illite, kaolinite, montmorillonite, and various mixtures of the aforementioned substances. It is known that hydrofluoric acid will solubilize siliceous material readily; however, because of its high reactivity hydrofluoric acid, unmixed with other mineral acids such as hydrochloric acid, generally is not used to increase oil production. Other serious problems also exist with the use of hydrofluoric acid. For example, since the rate of reaction of hydrofluoric acid with siliceous materials is very rapid, most of the acid is spent within a zone of about one or two feet or less radially from the wellbore. In formations having high formation temperatures the acid becomes spent at even shorter distances from the wellbore thereby causing the acidizing operation to be even less effective.
Since the mineral content of the matrix of many formations is usually sandstone or silica or a similar siliceous material, hydrofluoric acid can dissolve the matrix itself as well as the undesirable pore deposits in the matrix. As a consequence hydrofluoric acid can cause permanent damage to the formation by the dissolving of the pore structure or matrix itself, or by allowing the precipitation of reaction products and/or creation of fines within the pores of the formation. To prevent permanent damage from occurring the concentration of hydrofluoric acid is usually adjusted so that no more than minor damage to the formation can occur. As a consequence, clay deposits distant from the wellbore do not come in contact with hydrofluoric acid-containing acidizing compositions generally used for dissolving siliceous matter and thus such distant deposits are not dissolved. It is well recognized in the oil producing industry that it is difficult to dissolve only the pore deposits and especially those deposits more than two feet from the wellbore. Nonetheless even utilizing hydrofluoric acid concentrations as low as 0.1%, permanent damage to some formations can occur.
As mentioned earlier another problem associated with acidizing with formations containing hydrofluoric acid is that since the cleaned-out area is usually within a two-foot radius or less of the wellbore, loss of permeability can reoccur within a very short period of time after the treated well is put back on production since the deeper pore deposits are not removed. Thus, it is generally accepted that if deep pore deposits are to be solubilized by hydrofluoric acid, a large quantity and flow rate of acid must be used and since the acid can react with all siliceous material, there is a very high risk that permanent damage will result to the formation.
For these reasons, there have been various attempts to slow up the rate of reaction of hydrofluoric acid so that it can penetrate deeper into the formation and solubilize deeper pore deposits without causing serious damage to the formation adjacent to the wellbore. Unfortunately, many of these attempts, as will be described and further discussed below, still fall short of effectively increasing the permeability of the formation in those zones much farther than the usual two feet from the wellbore.
U.S. Pat. No. 990,969 discloses a well stimulation process which produces hydrofluoric acid directly in the subterranean formation. In particular, a quantity of hydrochloric acid is first pumped into the well which is then followed by a quantity of sodium fluoride. The hydrochloric acid and the sodium fluoride react in the formation to produce hydrofluoric acid and sodium chloride. The hydrofluoric acid reacts with the silica material in the pores to dissolve it thereby increasing the permeability of the formation to the flow of oil. The patentee alleges that in his process the hydrofluoric acid is not required to be handled at the surface or continuously in the tubing of the wellbore, but rather produced from precursor reagents within the subterranean formation itself. The "alternate and separate slug" or "two slug" method as disclosed in U.S. Pat. No. 1,990,969 also has disadvantages. First damage to the wellbore can occur because at the interface of the alternate slugs, hydrofluoric acid can be generated and can attack the well tubing itself, thereby decreasing the useful life of such tubing. Secondly, mixing of the reactants within the porous formation is not always uniform and hence not always complete, thereby causing some regions to have high hydrochloric acid concentrations and other regions to have high sodium fluoride concentration. Such regions will not be exposed to effective hydrofluoric acid concentrations and consequently will be largely unaffected by the treatment. Thirdly, the permeability tends to be increased only in a region very close to the wellbore due to the high reactivity of the treating solution. Consequently, deep pore deposits will not be solubilized to the extent desired. Thus, any improvement in oil production will be most likely for only a relatively small period of time.
Others have attempted to improve the distribution of the reactants into the formation over a greater distance by slowing the rate of reaction between hydrofluoric acid and the formation. U.S. Pat. No. 3,889,753 discloses a well stimulation method for dissolving silica or clay around the wellbore. The method involves contacting the siliceous material with an aqueous solution of a fluoride salt, a weak acid, and a weak acid salt in proportions that form in situ a significant but low concentration of hydrogen fluoride. However, while such acidizing mixtures may provide some improvement they still are too reactive to reach and solubilize deep pore deposits.
Ostensibly in order to overcome this difficulty some have returned to the alternate but separate slugs approach discussed earlier. U.S. Pat. No. 4,056,146 discloses a well stimulation method in which alternate slugs of hydrochloric acid and ammonium bifluoride or ammonium fluoride, or mixtures thereof, are alternately and separately introduced into the wellbore. The reagents react and produce hydrofluoric acid. Unfortunately these reagents still react too fast and the hydrofluoric acid produced is spent before it can penetrate deeply into the formation.
In order to obtain deeper penetration of the reagents into the formation, U.S. Pat. No. 4,136,739 varied the injection sequence by injecting, between the two alternate and separate reagent slugs, a hydrocarbon liquid such as diesel oil. In particular, an aqueous solution of an ammonium salt of hydrofluoric acid such as ammonium fluoride is injected in a first slug into the formation. This is then followed by a separate slug of diesel oil, which in turn is followed by a third and separate slug of hydrochloric acid. The patentee contends that in this way hydrofluoric acid is generated at a deeper distance from the wellbore than with the usual two slug method. The problem with this method is that mixing of the reagents in situ, because of the interdisposed diesel oil, becomes even more difficult and less effective. Furthermore, the reactants, when they are mixed, react quickly and produce a relative high concentration of hydrofluoric acid which is too reactive to penetrate deeply into the formation.
In many of the alternate and separate slug methods, the steps are repeated a number of times in order to better distribute the reagents on a more uniform basis into the formation. This switching back and forth can lead to operator error which in turn can result in regions in the formation having a higher concentration of one reagent and little, if any, of the other reagent, thereby providing no solubilization of the pore deposits in such regions. Unfortunately, the difficulty with the alternate and separate slug methods is that it is difficult to provide an equal distribution of each reagent to all parts of the formation zone unless the amount of each slug is very small. As can be appreciated, the smaller the slug amount the greater the number of slug cycles required to introduce the required quantity of reagents into the formation. As slug amount is decreased and the number of cycles increased, the more apt the reagents are to react and form hydrofluoric acid before penetrating deeply into the formation thereby increasing the possibility of both formation damage and well casing damage, and producing little, if any, solubilization of the deeper pore deposits.
The difficulty of mixing reagents in situ was avoided in U.S. Pat. No. 418,118 by mixing the acidizing composition at the surface prior to injecting into the formation. The reaction rate of hydrofluoric acid on silica and silicates is said to be retarded. The method relies on the reaction of a mineral acid other than hydrofluoric acid with certain fluoride compounds to produce hydrofluoric acid. The fluoride compounds disclosed have the formula: EQU (T.sup.+3).sub.n (M.sup.+1).sub.z (F.sup.a).sub.y
and include their hydrates. The cation T is zirconium, cobalt or chromium. M is either hydrogen or ammonium, and z is 0 to 4. The constants satisfy the formula: EQU 3n+z=ay.
The only fluoride compounds disclosed are chromium fluoride, cobalt fluoride, ammonium zirconium hexafluoride or (NH.sub.4).sub.2 ZrF.sub.6, and hydrogen zirconium hexafluoride or H.sub.2 Zr.sub.4 F.sub.6. In order to produce hydrofluoric acid it is taught that sufficient mineral acid, other than hydrofluoric acid, is required to produce an acidic composition with a pH no greater than 2. It is further taught that the actual pH is ordinarily much less than 2 and is often expressed in negative values. It is stressed that the only real limitation on the operability with respect to acidity caused by the mineral acid is the upper pH limit of 2 and that this can be achieved with an acid (ostensibly a mineral acid other than hydrofluoric acid) concentration of about 0.1 percent acid by weight of acidic composition. This method has the disadvantage of requiring a reaction between a mineral acid and a fluoride compound to produce hydrofluoric acid while requiring a strongly acidic solution since the upper limit of the pH is 2 and ostensibly in actual practice a pH much less than 2 or even negative values must be utilized if the treatment is to have any real effect on increasing the permeability of the formation.
Another known method depends upon the hydrolysis of fluoboric acid (HBF.sub.4) to produce hydrofluoric acid in situ in the formation. While some improvement in dissolving deeper pore deposits may occur in some subterranean formations the reaction rate is still too high for the more sensitive formations; see Journal of Petroleum Technology, August 1981, pages 1491 to 1500.
In all of these prior art methods, the reactants are still ostensibly too reactive to penetrate deeply into the formation and solubilize the deeper pore deposits. Accordingly, there remains a need for a process which retards the rate of reaction of hydrofluoric acid in the formation but at the same time provides sufficient hydrofluoric acid to the various parts of the formation without a dependence on mixing of the reagents within the formation as the hydrofluoric acid is consumed. What is therefore needed is to have a very small amount of the reactant, hydrofluoric acid, present at all times without the need to rely on its formation in situ by the mixing of alternate and separate slugs of precursors, or even by the mixing within a single slug of reagents the interreaction of which might be altered by mineral matter and/or brine in the formation. In general, it is believed that the prior art acidizing solutions utilizing hydrofluoric acid have too high a reactivity and hydrofluoric acid concentration to effect solubilization of the deeper pore deposits. The present invention offers a solution to these problems by the very slow in situ formation of very small amounts of hydrofluoric acid, by hydroysis of a fluoride compound without the necessity to react the fluoride compound with a mineral acid or any other reagent thereby minimizing the uncontrollable effect of varying mineral matter and brine encountered in the subterranean formation being acidized. The present invention therefore allows deeper penetration of the treating fluid into the formation to solubilize deeper pore deposits without causing significant damage to the matrix structure of the formation.