METHOD FOR ENHANCING ACIDIZING TREATMENT OF A FORMATION HAVING A HIGH BOTTOM HOLE TEMPERATURE

Abstract

An injection process to treat sandstone or limestone subterranean formations using carboxylic acids, dicarboxylic acids and/or aminocarboxylic acids (e.g. glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA), etc.), further involves at least a two step injection process which may include, in one non-limiting embodiment, injecting a relatively higher concentration of organic acid to create wormholes accompanied by a relatively lower concentration of the same or different organic acid to enhance the permeability of the formation.

Description

TECHNICAL FIELD

The present invention relates to methods and compositions for enhancing the acidizing treatment of subterranean formations, and more particularly to methods and compositions for using carboxylic acids and/or aminocarboxylic acids to create wormholes.

TECHNICAL BACKGROUND

It is well known that the production of oil and gas is often controlled by the rate at which oil and gas can be extracted from the subterranean formations containing them. No matter how much oil and gas is present, unless the oil and gas can flow to a well bore for removal at a commercially practical rate, it has no value. One means for improving the rate at which oil and gas may be removed from a subterranean formation is the use of acidizing and fracturing treatments.

Such treatments use aqueous acidic solutions and are commonly carried out in hydrocarbon-containing subterranean formations to accomplish a number of purposes, one of which is to increase the permeability of the formation or by-pass near well bore damage. The increase in formation permeability normally results in an increase in the recovery of hydrocarbons from the formation.

In acidizing treatments, aqueous acidic solutions are introduced into the subterranean formation under pressure so that the acidic solution flows into the pore spaces of the formation. One common type of subterranean formation is sandstone formations, which contain siliceous materials like quartz as the major constituent and which in addition may contain various amounts of clays (aluminosilicates such as kaolinite or illite) or alkaline aluminosilicates such as feldspars, and zeolites, as well as carbonates (calcite, dolomite, ankerite) and iron-based minerals (hematite and pyrite). In sandstone there normally is an amount of calcium carbonate and one way to make sandstone more permeable is to perform a so-called acidizing step, wherein an acid solution is pumped into the formation.

The acidic solution reacts with acid-soluble materials contained in the sandstone or limestone formation which results in an increase in the size of the pore spaces and an increase in the permeability of the formation. Similarly, in fracture-acidizing treatments, one or more fractures are produced in the formation and the acidic solution is introduced into the fracture to etch flow channels in the fracture face. The acid also enlarges the pore spaces in the fracture face and in the formation.

The rate at which acidizing fluids react with reactive materials in the subterranean formation is a function of various factors including but not limited to acid concentration, temperature, fluid velocity and the type of reactive material encountered. Whatever the rate of reaction of the acidic solution, the solution can be introduced into the formation only a certain distance before it becomes spent. It is desirable to maintain the acidic solution in a reactive condition for as long a period of time as possible to maximize the permeability enhancement produced by the acidic solution.

The use of acids downhole is not without problems. One such problem is that the acids, in addition to increasing the permeability of a hydrocarbon bearing formation, may also cause excessive corrosion of the downhole metal equipment. Anything made of metal in contact with the acid may be subject to such excessive corrosion.

It would be desirable in the art to use acids that limit or minimize the corrosion of metal downhole during acid stimulation treatments of oil and gas wells, while still increasing the local permeability.

SUMMARY

There is provided, in one non-limiting embodiment a method for acidizing a subterranean formation, where the method involves injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume. The method further involves subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume. The steps are modified by the first step differing from the second step by at least one of the following parameters:

• • the first concentration is greater than the second concentration;
  • the second volume is greater than the first volume,
  • the first volume is greater than the second volume, where the first concentration is less than the second concentration;
  • the second acid is at least partially neutralized by the addition of a base;
  • the first acid is a carboxylic acid or its salt with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and
  • combinations thereof.
    The bottom hole temperature of the wellbore are at least 150° F. (65.5° C.).

BRIEF DESCRIPTION OF THE DRAWINGS

The following Figures are part of the present specification, included to demonstrate certain aspects of various embodiments of this disclosure and referenced in the detailed description herein:

FIG. 1 is a schematic, cross-section illustration of a wellbore and stimulation zones around the wellbore after acid injection;

FIG. 2 is a theoretical graph of skin factor as a function of damaged zone permeability illustrating the effect of increasing the permeability in the damaged zone on the skin factor, where the original formation permeability is 100 md, while the damaged permeability is 5 md;

FIG. 3 is a theoretical graph of skin factor as a function of zone radius illustrating the effect of increasing the damaged zone radius on the skin factor, where the original formation permeability is 100 md, where the damaged permeability is originally 5 md but has been stimulated to be 1000 md;

FIG. 4 is a series of photographs of limestone cores before and after injection of GLDA;

FIG. 5 is a graph of pressure drop across the core as a function of cumulative pore volume at an injection rate of 1 cc/min, 300° F. (149° C.), and 5 gpt (or liters per thousand liters) of CI-111 corrosion inhibitor;

FIG. 6 is a plot of calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARB™-GLDA (20 wt % active) compared to 25% vol/vol STIMCARB™-GLDA (10 wt % active);

FIG. 7 is a plot of cumulative calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARB™-GLDA (20 wt % active) compared to 25% vol/vol StimCarb-GLDA (10 wt % active);

FIG. 8 are CT-Scan images showing worm-hole distribution for a limestone core treated with 25% vol/vol STIMCARB™-GLDA; and

FIG. 9 are CT-Scan images showing worm-hole distribution for a limestone core treated with 50% vol/vol STIMCARB™-GLDA.

It will be appreciated that FIG. 1 is a schematic illustration which is not necessarily to scale and that certain features are exaggerated for clarity, and thus the methods and apparatus described herein should not be limited by the drawings.

DETAILED DESCRIPTION

Recently there has been a growing interest in utilizing glutamic acid N,N-diacetic acid (GLDA) for the treatment of limestone or sandstone formations which have high bottom hole temperatures. One of the main benefits of utilizing GLDA for matrix acidizing is lowered reactivity compared to hydrochloric acid (HCl) or some other organic acids, making it ideal for high temperature conditions. Other benefits include the incorporation of chelation chemistry, enabling it to function as an effective iron control agent (that is, the GLDA also functions as a chelant), and provide better tubular protection even at higher temperatures (is less corrosive), compared to conventional acid systems, as well as biodegradability.

Several existing patents disclose some of the benefits of GLDA described and are mainly limited to the chemistry or composition of the fluid or field applicability of the fluid. New research work has unexpectedly led to the discovery that GLDA (and other carboxylic acids, dicarboxylic acids and amino carboxylic acids) may be used in optimized application engineering designs to maximize GLDA's stimulation efficiency and reduce overall treatment cost.

As defined herein, “carboxylic acid” encompasses monocarboxylic acids, dicarboxylic acids and polycarboxylic acids. Further, as defined herein, “aminocarboxylic acid” encompasses aminomonocarboxylic acids, aminodicarboxylic acids and aminopolycarboxylic acids

Carboxylic or aminocarboxylic acid are retarded acids. Recent experimental work discovered that reducing concentration or pH of dicarboxylic or aminocarboxylic acid can result in local permeability enhancement rather than the wormhole creation. Also, it has been discovered that reducing the active material concentration and injecting a larger volume of diluted dicarboxylic or aminocarboxylic acid results in a lower skin factor because of increased unreacted acid in the flushed zone; for instance, see zone 3 in FIG. 1.

“Skin factor” is a dimensionless numerical value used to analytically model the difference from the pressure drop predicted by Darcy's law due to skin (zone of reduced permeability immediately around a wellbore). Typical skin factor values range from −6 for an infinite conductivity massive hydraulic fracture to more than 100 for a poorly executed gravel pack.

As used herein “skin” refers to a damaged zone, which is zone 2 in FIG. 1, and may include zone 3. The initial skin factor is positive for zone 2, while it is zero for zone 3. After injection of acid according to the method herein, the skin factor will be negative for both zones (zones 2 and 3). This will improve production as compared to previous techniques where only the skin factor of zone 2 was reduced. Thus, one advantage of the method described herein is that the permeability may be increased and the skin in zone 3 is reduced, in addition to which production is increased.

The general method may be described with reference to a variety of particular embodiments, a few of which are briefly summarized as follows:

• • 1. Injection of a high concentration of carboxylic and/or aminocarboxylic acid (e.g. from about 10 to about 40 wt %) to create wormholes (for instance, wormholes 10 in zone 2 in FIG. 1), followed by injection of low active material concentration of dicarboxylic and/or aminocarboxylic acid (e.g. from about 0.01 to about 10 wt %) to improve the permeability of the flushed zone (zone 3 in FIG. 1).
  • 2. Injection of larger volume of relatively low concentration carboxylic and/or aminocarboxylic acid after the injection of relatively high concentration with less volume of the same acid to enlarge the stimulated matrix area (zones 2 and 3 in FIG. 1), in one non-limiting embodiment to enlarge zone 3.
  • 3. Injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid followed by a relatively lower concentration of the same acid in wells with bottom hole temperatures greater than 200° F. (93° C.).
  • 4. Alternatively, injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid accompanied by a relatively lower concentration (e.g. of about 5 to about 10 wt %) of a carboxylic and/or aminocarboxylic acid with neutralized pH in wells with bottom hole in a temperature range of about 250 to about 350° F. (about 121 to about 177° C.).
  • 5. In another optional embodiment, injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid followed by a relatively lower concentration, e.g. <5% of dicarboxylic and/or aminocarboxylic acid with neutralized pH in wells with a bottom hole temperature of greater than about 300° F. (about 149° C.).
  • 6. Injection of a carboxylic acid or its salt with a pH range of about 4 to 12 about followed by injection of a carboxylic acid with a pH range of about 1 to about 4.
  • 7. Optionally, the above embodiments may also include subsequent injection of a relatively low concentration of a carboxylic and/or an aminocarboxylic acid (e.g. from about 0.01 to about 10 wt %) to enlarge the pore radius and remove any scale from the entire formation, not necessarily to create wormholes to bypass the damage zone.

Hypothesis Leading to Method

Conventional hydrochloric acid (HCl) is used to stimulate subterranean carbonate formations by creating wormholes (long channels with infinite permeability) that bypass the damage near the wellbore as shown in zone 2 of FIG. 1. This near wellbore damage is generally the result of drilling mud or cement-filtrate invasion. This damage can significantly affect productivity adversely, and is typically easier to prevent than to cure. Nevertheless, there is a need to cure damage that sometimes is inevitable.

Zone 2 of FIG. 1 schematically indicates the wormholes 10 stimulated in the zone by the HCl. However, HCl does not stimulate the rest of the formation since typically all of the HCl is consumed (spent) to create the wormholes 10. Therefore, even in zone 1, the matrix around the wormholes 10 still has damaged permeability.

Zone 3 represents the flushed zone containing neutralized HCl utilized for wormhole 10 creation. The permeability of the flushed zone is dependent on the wormhole 10 length. If the wormhole 10 length is greater than the damaged radius then the flushed zone permeability is equal to the reservoir permeability. However, if wormhole 10 length is smaller than damaged radius then the flushed zone permeability will be less than the reservoir permeability depending on the flushed zone length. Typically for HCl acid, the stimulated matrix area is only Zone 2. However, for organic acids (like carboxylic or aminocarboxylic acids) the stimulated matrix area will be a combination of Zone 2 and 3 because the flushed zone will have some unreacted acid.

FIG. 2 shows the effect of increasing the permeability in the damaged zone on the skin factor. The following values were assigned as an example: Original formation permeability is 100 md, damaged radius is 1.5 ft (0.46 m), well bore radius is 0.5 ft (15 cm), and damaged permeability is 5 md. Based on these values, the initial skin factor will be 20.9; as the permeability increased toward the original value, the skin factor is reduced dramatically. However, after damaged zone improves to the original permeability value, the reduction in the skin factor becomes small. And based on the data in FIG. 2, increasing the permeability 10 times above the original value will not result in a significant reduction in the skin factor value.

FIG. 3 is a graph showing the effect of increasing the damaged zone radius on the skin factor. The following values were assigned as an example: Original formation permeability is 100 md and improved damaged formation permeability after stimulation is 1000 md. Based on these values, the initial skin factor will be −1 when the permeability enhancement covers the original damaged zone radius. However, if acid is stimulated further deep inside the formation, the skin factor will be reduced even more (FIG. 3). Based on results shown in FIGS. 2 and 3, enhancing the permeability deeply into the formation will result in much better well production than that from created wormholes.

The following examples describe certain specific embodiments of the invention. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the specification or practice of the methods as disclosed herein. It is intended that the specification, together with the examples, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow the examples. In the examples, all percentages are given on a weight basis unless otherwise indicated.

EXPERIMENTAL RESULTS AND DISCUSSION

Investigation into the effect of STIMCARB™-GLDA acid strength was carried out by core flood testing (dynamic fluid flow) with 10% versus 20% active material of STIMCARB™-GLDA using carbonate cores. STIMCARB™-GLDA is GLDA available from Baker Hughes Incorporated. “10 wt % STIMCARB™-GLDA” means 10 wt % active GLDA and 90 wt % aqueous solvent.

The pictures of the limestone cores before and after injection are shown in FIG. 4. In FIG. 4, the limestone cores treated with 10% STIMCARB™-GLDA are shown at (1a), (1b), and (1c), where (1a) is a photo of the core before injection, and (1b) is a photo of the inlet of the core after injection, and (1c) is a photo of the outlet of the core after injection. Similarly, in FIG. 4, the limestone cores treated with 20% STIMCARB™-GLDA are shown at (1d), (1e), and (1f), where (1d) is a photo of the core before injection, and (1e) is a photo of the inlet of the core after injection, and (1f) is a photo of the outlet of the core after injection.

The plot of pressure drop across the core as a function of injected pore volumes is shown in FIG. 5. Pictures of the core after injection do indicate that wormholes could be created by 10% STIMCARB™-GLDA but it takes more than twice the acid volume required for injection than with 20% STIMCARB™-GLDA. The FIG. 5 data involved pressure drop across the core as a function of cumulative pore volume (PV) at an injection rate of 1 cc/min at 300° F. (149° C.), with five gpt (gallons per thousand gallons, or in SI units liters per thousand liters) of CI-111. CI-111 is a quaternary ammonium based corrosion inhibitor product available from Baker Hughes Incorporated.

The effluent fluids from both cores was collected over time in both experiments and were subsequently analyzed for calcium content by inductively coupled plasma-optical emission spectrometry (ICP-OES). The calcium content was plotted against the cumulative pore volume as shown in FIG. 6 while in FIG. 7 the cumulative calcium content (mg) versus cumulative pore volume (PV) was plotted. Analysis of the total calcium content in the eluent does show that 10% STIMCARB™-GLDA contained more calcium content (538.8 mg) than 20% STIMCARB™-GLDA (451.2 mg). However, 10% STIMCARB™-GLDA required a higher pore volume of the acid to react and chelate calcium carbonate compare to 20% STIMCARB™-GLDA (see FIG. 5). On the other hand, the CT-scan images of the 20% STIMCARB™-GLDA treated core demonstrated a better network of wormholes than the 10% STIMCARB™-GLDA treated core. Please see FIGS. 8 and 9, where the left side of each image is a CT scan of the entire limestone core, while the right side of each image models the wormhole created by the acid. However, the cumulative amount of calcium dissolved by the latter acid was more than the former. These results confirm that 10% STIMCARB™-GLDA improves the permeability of the matrix rather than developing wormhole as the 20% STIMCARB™-GLDA does.

One of the major problems in acidizing is the creation of wormholes in the fracture face. The wormholes can increase the reactive surface area, resulting in excessive leakoff and rapid spending of the acid (that is, the etched length will be too short). To some extent, this problem can be overcome by, for example, using viscosified acids. Viscosified acids can also be used in relatively high permeability formations. Acid can be viscosified with polymers (e.g. crosslinked or uncrosslinked polysaccharides), viscoelastic surfactants (VESs), nitrogen and foaming agents, or acid-in-oil emulsions. To come back to the topic of the GLDA tests, the 20% active STIMCARB™-GLDA may be replaced with the viscosified acid (such as viscosified 10% vol/vol STIMCARB™-GLDA). In one non-limiting embodiment, the acids described herein may be viscosified using any of the techniques known in the art or yet to be developed including, but not necessarily limited to, crosslinked or uncrosslinked polymers, VESs, nitrogen and foaming agents, and/or acid-in-oil emulsions.

The flushed zone is the zone between the reservoir fluid and the wormhole zone developed by the carboxylic or aminocarboxylic acid (zone 3 in FIG. 1). Carboxylic acids or aminocarboxylic acids are retarded acids that initiate some permeability enhancement in the flushed zone. Ignoring any permeability enhancement in the flushed zone, and assuming equivalent amount of active components in both acid concentrations, both acids (10 and 20 wt % active GLDA) should give the same skin factor because they have same wormhole length. However 20 wt % GLDA will require less volume compare to 10%.

On the other hand, consider the enhancement in the flushed zone as it should be, the overall skin reduction of 10 wt % active material will be lower than 20% as shown S2 and S3 (skin factor calculations in Table I). The values of skin factor shown in Table I can be more significant when wormhole length is less than damage zone where any enhancement of the flushed zone will give a significant reduction in skin. K in Table I refers to the matrix permeability in the flushed zone area (zone 3).

TABLE I
The Skin Factor Calculations when Considering
the Enhancement in the Flushed Zone
		S1 (ignore		S3 (10X increase
	Injected	permeability in	S2 (4X increase in	in K in flushed
GLDA	acid, PV	flushed zone)	K in flushed zone)	zone)
20%	2.38	−1.79	−2.12	−2.2
10%	5.90	−1.79	−2.45	−2.63

Turning to a more detailed discussion of the various embodiments, the method for acidizing a subterranean formation may include first injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume, and subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume. Within these at least two injecting steps, the first step differs from the second step by a parameter. The different parameters may include, but not necessarily limited to, one or more of the following: (1) the first concentration is greater than the second concentration, (2) the second volume is greater than the first volume (increased volume in the flush zone enhances the permeability of the matrix), (3) the first volume is greater than the second volume, where the first concentration is less than the second concentration, (4) the second acid is at least partially neutralized by the addition of a base, and/or (5) the first acid is a carboxylic acid with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4, where the pH of the first acid and the pH of the second acid are different.

The methods described herein are particularly applicable for improving (enhancing) acidizing treatments of formations having high bottom hole temperatures (BHTs). In one non-limiting embodiment, a high BHT is defined as at least 200° F. (93° C.); alternatively above about 250° F. (about 121° C.), and in a different non-limiting embodiment greater than about 300° F. (about 149° C.). Alternatively, the high BHT may be defined as between about 250 and about 350° F. (about 121 and about 177° C.). An alternative lower threshold for these ranges may be 150° F. (65.5° C.).

In one non-limiting embodiment herein, there are two steps and the first concentration ranges from about 10 independently to about 40 wt % acid (high concentration), and the second concentration ranges from about 0.01 to about 10 wt % acid (low concentration), less than the first concentration. Alternatively, a high or first concentration may range from about 20 independently to about 40 wt % acid. As used herein with respect to a range, the term “independently” means that any lower threshold may be combined with any upper threshold to form a suitable, alternative range. Alternatively, a low or second concentration may range from about 0.01 independently to about 10 wt % acid.

In another non-limiting version, in the two step method described herein, the second volume of acid is greater than the first volume of acid by an amount ranging from about 5 independently to about 200 times more; alternatively from about 10 independently to about 100 times more.

There may be one or more subsequent acid injections besides the initial two. For instance, after the second injecting, the method may include injecting through the wellbore a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third acid concentration ranging between about 0.01 independently to about 40 wt %; alternatively between about 0.01 independently to about 10 wt %.

The acids used in the two or more injecting steps may be the same or different from one another. More than one of the suitable acids may be used in each injecting step.

In a different non-limiting embodiment, the first concentration ranges from about 11 independently to about 40 wt %, alternatively from about 20 independently to about 40 wt %, and the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1 and/or 2 of the Periodic Table and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof. Suitable bases in this group include, but are not necessarily limited to, sodium hydroxide, calcium oxide or hydroxide, magnesium oxide or hydroxide, potassium hydroxide, and the like, and combinations thereof. By “at least partially neutralized” is meant that while it is acceptable to add sufficient base to completely neutralize the acid present that it is acceptable if the amount of base added is less than the amount sufficient of base to completely neutralize the acid present. In this non-limiting embodiment, the high bottom hole temperature is between about 250 and about 350° F. (about 121 and about 177° C.).

In another non-limiting embodiment, the first acid has a pH adjusted by the presence of a base to be in the range of from about 4 independently to about 12; alternatively from about 4 independently to about 14. The pH in of the second acid or its salt is in the range of from about 1 independently to about 4; alternatively from about 1 independently to about 14. The pHs in the two steps are different from one another.

In still another non-restrictive embodiment, the first concentration ranges from about 5 independently to about 40 wt %; alternatively from about 20 independently to about 40 wt %, where the second concentration is less than 5 wt %, or alternatively about 38 wt % or less. In this optional embodiment, the second acid is at least partially neutralized by the addition of a base to form its salt selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof. Optionally, the bottom hole temperature is between greater than about 300° F. (about 149° C.).

While it is expected that carboxylic acids will be the acids used, dicarboxylic acids and aminocarboxylic acids are particularly suitable. Suitable organic acids include, but are not necessarily limited to, glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA); nitrilotriacetic acid (NTA); ethylene diamine tetraacetic acid (EDTA); hydroxyethyl ethylene diamine triacetic acid (HEDTA); diethylene triamine pentaacetic acid (DTPA); propylene diamine tetraacetic acid (PDTA); ethylene diamine-N,N″-di(hydroxyphenyl acetic) acid (EDDHA); ethylene diamine-N,N″-di(hydroxy-methylphenyl acetic) acid (EDDHMA); ethanol diglycine (EDG); trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA); glucoheptonic acid; gluconic acid; sodium citrate; acetic acid; formic acid; lactic acid; citric acid; malonic acid; succinic acid; adipic acid; glutaric acid; malic acid; tartaric acid; alkali metal salts of these acids; amine salts of these acids; and combinations thereof.

It will be appreciated that mineral acids may be used in conjunction with or together with the carboxylic acids and/or aminocarboxylic acids as described herein, in alternative embodiments. The mineral acids may include, but are not necessarily limited to, hydrochloric acids, phosphoric acid, sulfuric acid, hydrobromic acid, hydrofluoric acid, nitric acid and/or boric acid, and chemical equivalents of these acids.

Suitable subterranean formations for the methods and compositions described herein include, but are not necessarily limited to, formations selected from the group consisting of sandstone formations, limestone formations, and combinations thereof.

It will be appreciated that in the present method the permeability of the subterranean formation is increased compared to a method that consists of only injecting the first acid or only injecting the second acid. In one non-limiting embodiment, this permeability increase is quantified by an increase in production from about 5 independently to about 90 vol %; alternatively from about 10 independently to about 95 vol %.

It will be additionally appreciated that in the acid injecting steps herein, it will be acceptable to include common and/or conventional additives present in acidizing treatments including, but not necessarily limited to, corrosion inhibitors, surfactants, demulsifiers, solvents, scale control, iron control, clay control, bacteria control, viscosifying agents such as VES surfactants, polyacrylamides, crosslinked guar, as well as other synthetic polymers, breakers, and diverting agents.

In the foregoing specification, the invention has been described with reference to specific embodiments thereof. It has been demonstrated as effective in providing methods and compositions for acidizing subterranean formations, particularly to improve or enhance the acidizing, such as by creating wormholes, and/or increasing the permeability of the zones near the wellbore, alone or together with also being able to use reduced concentrations and/or reduced volumes of acids, both of which would lower costs. However, it will be evident that various modifications and changes can be made thereto without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific combinations of carboxylic acids, dicarboxylic acids, aminocarboxylic acids, bases, and other components falling within the claimed parameters, but not specifically identified or tried in a particular composition or under specific conditions, are anticipated to be within the scope of this invention.

As used herein, the word “comprising” as used throughout the claims is to be interpreted to mean “including but not limited to”.

The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. For instance, there may be provided a method for acidizing a subterranean formation, where the method consists essentially of or consists of injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, dicarboxylic acids, and/or aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume; and injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, dicarboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume; where the first step differs from the second step by a parameter selected from the group consisting of: the first concentration is greater than the second concentration; the second volume is greater than the first volume; the first volume is greater than the second volume, where the first concentration is less than the second concentration; the second acid is at least partially neutralized by the addition of a base; the first acid is a carboxylic acid with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and combinations thereof.

Claims

1. A method for acidizing a subterranean formation, the method comprising: where:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume; and

injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume;

the first step differs from the second step by a parameter selected from the group consisting of: the first concentration is greater than the second concentration; the first concentration is greater than the second concentration and the first volume is less than the second volume; the first volume is greater than the second volume, where the first concentration is less than the second concentration; the second acid is at least partially neutralized by the addition of a base; the first acid is a carboxylic acid or its salt with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and combinations thereof; and

the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).

2. The method of claim 1 where the first concentration ranges from about 10 to about 40 wt % acid, and the second concentration ranges from about 0.01 to about 10 wt % acid.

3. The method of claim 1 where the second volume of acid is greater than the first volume of acid by an amount ranging from about 5 times to about 200 times greater volume more.

4. The method of claim 1 where the first acid and the second acid are the same acid.

5. The method of claim 1 where:

the first concentration ranges from about 11 to about 40 wt %;

the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof; and

the bottom hole temperature is between about 150 and about 350° F. (about 65.5 and about 177° C.).

6. The method of claim 1 where:

the first concentration ranges from about 5 to about 40 wt %;

the second concentration is less than 5 wt %;

the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof; and

the bottom hole temperature is between greater than about 300° F. (about 149° C.).

7. The method of claim 1 further comprising injecting through the wellbore a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third concentration ranging between about 0.01 to about 10 wt %.

8. The method of claim 1 where the carboxylic acids and aminocarboxylic acids are selected from the group consisting of glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA); nitrilotriacetic acid (NTA); ethylene diamine tetraacetic acid (EDTA); hydroxyethyl ethylene diamine triacetic acid (HEDTA); diethylene triamine pentaacetic acid (DTPA); propylene diamine tetraacetic acid (PDTA); ethylene diamine-N,N″-di(hydroxyphenyl acetic) acid (EDDHA); ethylene diamine-N,N″-di(hydroxy-methylphenyl acetic) acid (EDDHMA); ethanol diglycine (EDG); trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA); glucoheptonic acid; gluconic acid; sodium citrate; acetic acid; formic acid; lactic acid; citric acid; malonic acid; succinic acid; adipic acid; glutaric acid; malic acid; tartaric acid; alkali metal salts of these acids; amine salts of these acids; and combinations thereof.

9. The method of claim 1 where the carboxylic acid is a dicarboxylic acid.

10. The method of claim 1 where the subterranean formation comprises formations selected from the group consisting of sandstone formations, limestone formations, and combinations thereof.

11. The method of claim 1 where the permeability of the subterranean formation is increased compared to a method that consists of only injecting the first acid or only injecting the second acid.

12. A method for acidizing a subterranean formation, the method comprising:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between 10 to about 40 wt % and a first volume;

followed by injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration between about 0.01 and less than 10 wt % and a second volume; and

the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).

13. A method for acidizing a subterranean formation, the method comprising:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration from about 10 to about 40 wt % acid, and a first volume; and

followed by injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 0.5 to about 38 wt % acid, and a second volume that is higher than the first volume of acid by an amount ranging from about 5 to about 200 times more; and

the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).

14. A method for acidizing a subterranean formation, the method comprising: where:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration from about 10 to about 40 wt % acid, and a first volume; and

injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 0.01 to about 10 wt % acid, and a second volume;

the first acid and the second acid are the same acid; and

the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).

15. A method for acidizing a subterranean formation, the method comprising: where:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between about 11 to about 40 wt %, and a first volume; and

injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 5 to about 10 wt %, and a second volume, the second acid at least partially neutralized by the addition of a base;

the bottom hole temperature of the wellbore is between about 150 and about 350° F. (about 65.5 and about 177° C.).

16. A method for acidizing a subterranean formation, the method comprising: where:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between 5 to about 40 wt %, and a first volume; and

injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration of less than 5 wt %, and a second volume, the second acid at least partially neutralized by the addition of a base;

the bottom hole temperature of the wellbore is greater than 300° F. (about 149° C.).

17. A method for acidizing a subterranean formation, the method comprising: where:

injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, alkali metal salts and amine salts of carboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume, the first acid having a pH adjusted by the presence of a base to be in the range of from about 4 to about 12; and

injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, alkali metal salts and amine salts of carboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume and a pH in the range of from about 1 to about 4;

the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).