Wells – Processes – Placing fluid into the formation
Reexamination Certificate
2002-08-19
2004-10-19
Walker, Zakiya (Department: 3672)
Wells
Processes
Placing fluid into the formation
C166S304000
Reexamination Certificate
active
06805198
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates to acidizing treatment fluids used during hydrocarbon recovery operations, and more particularly relates, in one embodiment, to methods of using acidizing methods during hydrocarbon recovery operations that have reduced corrosivity of equipment.
BACKGROUND OF THE INVENTION
Hydrocarbons sometimes exist in a formation but cannot flow readily into the well because the formation has very low permeability. Acidizing wells is a conventional process for increasing or restoring the permeability of subterranean formations so as to facilitate the flow of oil and gas from the formation into the well. This process involves treating the formation with an acid to dissolve fines and carbonate scale plugging or clogging the pores, thereby opening the pores and other flow channels and increasing the permeability of the formation. Continued pumping forces the acid into the formation, where it etches channels or wormholes. These channels provide ways for the formation hydrocarbons to enter the well bore.
Conventional acidizing fluids, such as hydrochloric acid or a mixture of hydrofluoric and hydrochloric acids, have high acid strength and quick reaction with fines and scale nearest the well bore, and have a tendency to corrode tubing, casing and down hole equipment, such as gravel pack screens and down hole pumps, especially at elevated temperatures. In addition, above 200° F. (92° C.), HCl is not recommended because of its destructive effect on the rock matrix. Due to the type of metallurgy, long acid contact times and high acid sensitivity of the formations, removal of the scale with hydrochloric acid and hydrochloric acid mixtures has been largely unsuccessful. There is a need to find an acid fluid system to dissolve the scale and remove the source of the fines through acidizing the surrounding formation and not damage the down hole equipment, particularly for high temperature wells.
It would be desirable if a composition and method could be devised to overcome some of the problems in the conventional acidizing methods and fluids.
SUMMARY OF THE INVENTION
Accordingly, it is an object of the present invention to provide a system and method for acidizing a subterranean formation that would have reduced corrosivity of the iron-alloy and other metal equipment used in connection with the system, as compared with conventional systems using hydrochloric acid.
It is another object of the present invention to provide a system and method for acidizing a subterranean formation that would acidize a formation at relatively high temperatures with reduced corrosion of iron-alloy equipment, as compared with conventional systems using hydrochloric acid, and which would acidize the formation more uniformly, rather than predominantly near the well bore.
In carrying out these and other objects of the invention, there is provided, in one form, a method for increasing the permeability of a subterranean formation involving injecting an acid composition into the subterranean formation where the acid composition comprises at least one dicarboxylic acid; and contacting the subterranean formation with the acid composition for a period of time effective to improve the permeability of the formation.
DETAILED DESCRIPTION OF THE INVENTION
The present invention provides an organic acid fluid system and method for matrix acidization of subterranean formations penetrated by a well bore at temperatures in excess of about 200° F. (92° C.). It has been discovered that a particularly useful organic acid fluid contains at least one water-soluble dicarboxylic acid. In one non-limiting embodiment of the invention, the dicarboxylic acid is of relatively low molecular weight, that is, has a formula weight of 175 or less. Suitable dicarboxylic acids therefore include, but are not necessarily limited to, oxalic acid (ethanedioic acid), malonic acid (propanedioic acid), succinic acid (butanedioic acid), glutaric acid (pentanedioic acid), adipic acid (hexanedioic acid), pimelic acid (heptanedioic acid), and mixtures thereof. In another, preferred embodiment of the invention, the dicarboxylic acids are selected from the group consisting of succinic acid, glutaric acid, adipic acid, and mixtures thereof. Interestingly, glutaric acid, succinic acid, and adipic acid have been used as components for corrosion inhibitors for ferrous metals, according to U.S. Pat. No. 4,512,552. Mixtures of succinic acid, glutaric acid, and adipic acid are generally available as a by-product stream.
The organic acid fluid systems of the invention can effectively generate wormholes to stimulate production in subterranean carbonate formations and dissolve carbonate scale, and these organic acids mixed with hydrofluoric acid can effectively remove fines to recover production in sandstone formations at elevated temperatures. This fluid has very low corrosion on the tubing, casing and down hole equipment.
Based on the properties of glutaric acid, succinic acid and adipic acid, this composition of dicarboxylic acids and other combinations of dicarboxylic acids (or dicarboxylic acids used alone) can be used as acid compositions to stimulate high temperature wells, according to the methods of the invention. A series of tests done on screens and clay-rich cores show that this organic acid system, which is advantageously highly biodegradable, can successfully remove the calcium carbonate scale and fines to stimulate production. Core flood testing demonstrates that this organic acid system can effectively remove calcium carbonate scales and fines at temperatures up to 400° F. (204° C.). In addition to its reactivity, the acid system, when combined with corrosion inhibitor, exhibits very low corrosion at high temperatures. Corrosion tests show that at 350° F. (177° C.) the corrosion rate caused by this organic acid is 0.001 lbs/ft
2
(0.005 kg/m
2
) on 22-Cr for 16 hours. Acid soaking to completely remove scale prior to removal of fines is now possible at temperatures in excess of 200° F. (92° C.). In one non-limiting embodiment of the invention, a preferred operating temperature range is between about 300° F. (149° C.) and about 350° F. (177° C.). Successive removal of plugging fines from screens can then proceed without further damage to the integrity of the screen.
In some non-limiting embodiments of the invention, hydrofluoric acid may be used together with the dicarboxylic acids of the invention. Hydrofluoric acid may be used to aid in dissolving silicates. Alternatively, the invention may employ a substance that hydrolyzes to hydrofluoric acid. Suitable substances include, but are not necessarily limited to, ammonium bifluoride and ammonium fluoride, alkali metal fluorides and bifluorides (where the alkali metal is typically sodium, potassium or the like) as well as transition metal fluorides (for instance hexafluorotitanate salts and the like) and mixtures thereof.
In one non-limiting embodiment of the invention however, the acid composition involves an absence of excess fluoride.
It will be appreciated that it is difficult to specify with precision the amount of dicarboxylic acid that must be used to effectively acidize a particular subterranean formation. A number of complex, interrelated factors must be taken into account that would affect such a proportion, including but not necessarily limited to, the temperature of the formation, the pressure of the formation, the particular fines and scales present in the formation (e.g. calcium carbonate, silicates, and the like), the particular dicarboxylic acid(s) used, the expected contact time of the acid composition with the formation, etc.
For stimulation treatments, contact times are determined from the maximum pumping rate that does not cause the down hole pressure to exceed the fracturing pressure. This type of treatment is called a “matrix” acid job.
For scale/fines removal procedures, contact times are based on laboratory tests, but usually range from about 0.5 hour to about 2 hour with the most common time being about 0.5 hour.
Suitable solvents or diluents fo
Gabrysch Allen D.
Huang Tianping
McElfresh Paul M.
Baker Hughes Incorporated
Madan, Mossman & Sirram P.C.
Walker Zakiya
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