Methods For Stimulating Hydrocarbon-Bearing Formations

Abstract

A process for the fracking or stimulation of a hydrocarbon-bearing formation, said process comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a location slightly beyond a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool form the wellbore; and initiating the fracking of the perforated area using a fracking fluid.

Claims

1. A process for the fracking or stimulation of a hydrocarbon-bearing formation, said process comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a location slightly beyond a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool form the wellbore; and initiating the fracking of the perforated area using a fracking fluid.

2. The process of claim 1, wherein the spearhead acid comprises a corrosion inhibitor adapted to prevent damaging corrosion to the tool during the period of exposure with said tool.

3. The process according to claim 1 or 2, wherein the tool is a perforating gun.

4. The process according to any one of claims 1 to 3, wherein the spearhead acid is selected from the group consisting of: mineral acids; organic acids; modified acids; synthetic acids; and combinations thereof.

5. The process according to any one of claims 1 to 4, wherein the spearhead acid further comprises a corrosion inhibitor.

6. The process according to any one of claims 1 to 5, wherein the spearhead acid is selected from the group consisting of: methanesulphonic acid; HCl:amino acid; HCI:alkanolamine.

7. The process according to claim 6, wherein the amino acid is selected from the group consisting of: lysine; lysine monohydrochloride; alanine; asparagine; aspartic acid; cysteine; glutamic acid; histidine; leucine; methionine; proline; serine; threonine; valine; and combinations thereof.

8. The process according to claim 6, wherein the alkanolamine is selected from the group consisting of: monoethanolamine; diethanolamine; triethanolamina and combinations thereof.

9. A corrosion inhibiting composition for use with an acid, said composition comprising: citral and cinnamaldehyde.

10. A corrosion inhibiting composition comprising: an alkyne alcohol; a terpene selected from the group consisting of: citral; carvone; ionone; ocimene; cymene; and combinations thereof; an amphoteric surfactant selected from the group consisting of: a betaine and a sultaine cinnamaldehyde or a derivative thereof; and a solvent.

11. The corrosion inhibiting composition according to claim 10, further comprising at least one anionic surfactant.

12. The composition according to claim 10 or 11, wherein the alkyne is propargyl alcohol.

13. The composition according to any one of claims 10 to 12, wherein the solvent is isopropanol.

14. The composition according to any one of claims 10 to 13, wherein the terpene is citral.

15. The composition according to any one of claims 10 to 14, wherein the alkyne is present in an amount ranging from 10-40% v/v of the composition.

16. The composition according to any one of claims 10 to 15, wherein the citral is present in an amount ranging from 5-15% v/v of the composition.

17. The composition according to any one of claims 10 to 16, wherein the cinnamaldehyde or a derivative thereof is present in an amount ranging from 7.5-20% v/v of the composition.

18. The composition according to any one of claims 10 to 17, wherein the solvent is present in an amount ranging from 10-40% v/v of the composition.

19. The composition according to any one of claims 10 to 18, wherein the amphoteric surfactant is present in an amount ranging from 10-40% v/v of the composition.

20. The composition according to any one of claims 11 to 19, wherein the anionic surfactant is present in an amount ranging from 10-40% v/v of the composition.

21. The composition according to any one of claims 10 to 20 wherein the amphoteric surfactant comprises a betaine or a sultaine.

22. The composition according to any one of claims 11 to 20, wherein the anionic surfactant comprises a betaine and β-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1).

23. The composition according to any one of claims 10 to 22 further comprises a metal iodide or iodate selected from the group consisting of: cuprous iodide; potassium iodide and sodium iodide.

24. The composition according to claim 23, wherein the metal iodide or iodate is potassium iodide.

25. The composition according to claim 23, wherein the metal iodide or iodate is sodium iodide.

26. The composition according to claim 23, wherein the metal iodide or iodate is cuprous iodide.

27. A process for spotting acid in a wellbore, said process comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a location slightly beyond a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; and allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation,

Description

BRIEF DESCRIPTION OF THE FIGURES

[0044] Features and advantages of embodiments of the present application will become apparent from the following detailed description and the appended figures, in which:

[0045] FIG. 1 is a schematic diagram illustrating the general steps according to a preferred method of the present invention;

[0046] FIG. 2 illustrates a side-by-side comparison of the injection procedure in pre-fracking and fracking operations, the left graph showing the conventional method and the right graph showing a preferred embodiment of the method according to the present invention; and

[0047] FIG. 3 illustrates a side-by-side bar graph comparison of the various stage times in the pre-fracking and fracking operations, the left graph showing a preferred embodiment of the method according to the present invention, the right graph showing the conventional process.

DESCRIPTION OF THE INVENTION

[0048] The description that follows, and the embodiments described therein, is provided by way of illustration of an example, or examples, of particular embodiments of the principles of the present invention. These examples are provided for the purposes of explanation, and not limitation, of those principles and of the invention.

[0049] In a conventional plug and perf operation, the plug is set in the well, it is perforated by a tool (guns), then the tool is pulled out of the hole and then acid is pumped and circulated to the perforations (this process can take hours sometimes) and once a feed rate is reached they begin the frac for that stage. The process is then repeated up to the number of stages (over 40 in many wells).

[0050] According to a preferred embodiment of the present invention, the method allows for an operator to pump the tools down with the spearhead acid to perforate the zone and let the acid sit over the perforations. This is followed by the removal of the tool from the wellbore and initiating of the fracturing immediately.

[0051] According to a preferred embodiment of the present invention, this method can save up to an average of about 1 hr per stage (up to 5 in the case of some tight formations) at an average cost of up $20,000/hr (for the crew) and about 30-50m.sup.3 of water per stage. In a 50-stage well, this can translate into savings of over $1,000,000 in time plus the saved water of up to 800,000 gallons. The potential savings from the implementation of this method in operations in the United States alone could reach upwards of several hundreds of millions of dollars per year.

[0052] HCl is the most commonly used acid in fracking. With this in mind, one must understand that perforation tools are mostly made of stainless steel to ensure longevity. Conventional plug and perforation processes require the removal of the perforation guns immediately after the perforation stage otherwise the spearhead acid would destroy the perforating guns because of their propensity to attack stainless steel. A critical factor in allowing a process to have stainless steel exposed to strong acids such as HCl is the ability to control, minimize or eliminate corrosion to a level below which would render a stainless-steel tool unusable after only a few uses (or even less).

[0053] According to a preferred embodiment of the present invention, the method can be carried out with a novel corrosion inhibitor which affords protection of stainless steel from damage from exposure to hydrochloric acid (HCl), this affords a never-seen-before possibility of removing a step of the pre-fracking process, thereby saving substantial time, money and water resources.

[0054] Preferably, the surfactant is selected from the group consisting of: a sultaine surfactant; a betaine surfactant; and combinations thereof. More preferably, the sultaine surfactant and betaine surfactant are selected from the group consisting of: an amido betaine surfactant; an amido sultaine surfactant; and combinations thereof. Yet even more preferably, the amido betaine surfactant and is selected from the group consisting of: an amido betaine comprising a hydrophobic tail from C8 to C16. Most preferably, the amido betaine comprising a hydrophobic tail from C8 to C16 is cocamidobetaine.

[0055] Preferably also, the corrosion inhibition package further comprises an anionic surfactant. Preferably, the anionic surfactant is a carboxylic surfactant. More preferably, the carboxylic surfactant is a dicarboxylic surfactant. Even more preferably, the dicarboxylic surfactant comprises a hydrophobic tail ranging from C8 to C16. Most preferably, the dicarboxylic surfactant is sodium lauriminodipropionate.

[0056] Most preferred are embodiments of a corrosion inhibition package comprising cocamidopropyl betaine and β-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1).

[0057] According to a preferred embodiment of the present invention, when preparing an acidic composition comprising a corrosion inhibition package, metal iodides or iodates such as potassium iodide, sodium iodide, cuprous iodide and lithium iodide can be added as corrosion inhibitor intensifier. The iodide or iodate is preferably present in a weight/volume percentage ranging from 0.1 to 1.5%, more preferably from 0.25 to 1.25%, yet even more preferably 1% by weight/volume of the acidic composition. Most preferably, the iodide used is potassium iodide.

[0058] According to a preferred embodiment of the present invention, the corrosion package comprises:

[0059] 2-Propyn-1-ol, compd. with methyloxirane; β-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1); cocamidopropyl betaine; (±)-3,7-Dimethyl-2,6-octadienal (Citral); cinnamaldehyde; and isopropanol.

[0060] More preferably, the composition comprises 20% of 2-Propyn-1-ol, compd. with methyloxirane; 20% of β-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1); 20% of cocamidopropyl betaine; 7.5% of (±)-3,7-Dimethyl-2,6-octadienal (Citral); 12.5% cinnamaldehyde; and 20% of Isopropanol (all percentages are volume percentages). A point of note, the surfactant molecules comprise only roughly ⅓of the actual content of the entire surfactant blend as the balance, roughly ⅔, is comprised of water so as to control the viscosity of the surfactant when admixed with the other components. This is typical of surfactant blends in this and other industries.

[0061] According to a preferred embodiment of the present the corrosion inhibitor composition comprises cinnamaldehyde or a derivative thereof selected from the group consisting of: cinnamaldehyde; dicinnamaldehyde p-hydroxycinnamaldehyde; p-methylcinnamaldehyde; p-ethylcinnamaldehyde; p-methoxycinnamaldehyde; p-dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde; p-nitrocinnamaldehyde; o-nitrocinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde p-trimethylammoniumcinnamaldehyde sulfate; p-trimethylammoniumcinnamaldehyde o-methylsulfate; p-thiocyanocinnamaldehyde; p-(S-acetyl)thiocinnamaldehyde; p-(S-N,N-dimethylcarbamoylthio)cinnamaldehyde; p-chlorocinnamaldehyde; α-methylcinnamaldehyde; β-methylcinnamaldehyde; α-chlorocinnamaldehyde α-bromocinnamaldehyde; α-butylcinnamaldehyde; α-amylcinnamaldehyde; α-hexylcinnamaldehyde; α-bromo-p-cyanocinnamaldehyde; α-ethyl-p-methylcinnamaldehyde and p-methyl-α-pentylcinnamaldehyde.

[0062] According to a preferred embodiment, the acid is an aqueous modified acid composition comprising: a mineral acid and an alkanolamine in a molar ratio of not more than 15:1.

[0063] According to another preferred embodiment, the acid is an aqueous modified acid composition comprising: hydrochloric acid and an alkanolamine in a molar ratio of not more than 15:1.

[0064] According to a preferred embodiment, the acid is an aqueous modified acid composition according to claim 2, wherein the hydrochloric acid and alkanolamine are present in a molar ratio of not more than 10:1.

[0065] According to a preferred embodiment, the acid is an aqueous modified acid composition according to claim 2, wherein the hydrochloric acid and alkanolamine are present in a molar ratio of not more than 7.0:1. More preferably, hydrochloric acid and alkanolamine are present in a molar ratio of not more than 4:1. Even more preferably, hydrochloric acid and alkanolamine are present in a molar ratio of not more than 3:1.

[0066] According to a preferred embodiment, the alkanolamine is selected from the group consisting of: monoethanolamine; diethanolamine; triethanolamine and combinations thereof. Preferably, the alkanolamine is monoethanolamine.

[0067] According to a preferred embodiment of the present invention, the method uses a synthetic acid composition comprising: a strong acid and an alkanolamine in a molar ratio of not more than 15:1; preferably in a molar ratio not more than 10:1, more preferably in a molar ratio of not more than 8:1; even more preferably in a molar ratio of not more than 5:1; yet even more preferably in a molar ratio of not more than 3.5:1; and yet even more preferably in a molar ratio of not more than 2.5:1.

[0068] Preferably, the main components in terms of volume and weight percent of the composition set out above comprise an alkanolamine and a strong acid, such as HCl, nitric acid, sulfuric acid, sulfonic acid.

[0069] An alkanolamine, as per the above, contains at least one amino group, —NH.sub.2, and one alcohol group, —OH. Preferred alkanolamines include.sub.; but are not limited to, monoethanolamine, diethanolamine and triethanolamine, More preferred are monoethanolamine, diethanolamine. Most preferred is monoethanolamine. When added to hydrochloric acid a Lewis acid/base adduct is formed where the primary amino group acts as a Lewis base and the proton of the HCl as Lewis acid. The formed adduct greatly reduces the hazardous effects of the hydrochloric acid on its own, such as the fuming or vapor pressure effect, the hygroscopicity, and the highly corrosive nature.

[0070] The molar ratio of the two main components can be adjusted or determined depending on the intended application and the desired solubilizing ability. According to a preferred embodiment where the strong acid is HCl, one can increase the ratio of the HCl component to increase the solubilizing ability of the composition while still providing at least one of the following advantages: health; safety; environmental; and operational advantages over hydrochloric acid.

[0071] Various corrosion inhibitors can be incorporated into an acid composition used in a preferred embodiment of the method according to the present invention, such composition comprises a strong acid and an alkanolamine to reduce corrosion on the steel which is contacted.

[0072] Preferably, the composition may further comprise organic compounds which may act as corrosion inhibitors selected from the group consisting of: acetylenic alcohols, aromatic or aliphatic aldehydes (e.g. α,β-unsaturated aldehydes), alkylphenones, amines, amides, nitrogen-containing heterocycles (e.g. imidazoline-based), iminium salts, triazoles, pyridine and its derivatives or salts, quinoline derivatives, thiourea derivatives, thiosemicarbazides, thiocyanates, quaternary amine salts, and condensation products of carbonyls and amines. Intensifiers which can be incorporated into compositions according to the present invention are selected from the group consisting of: formic acid, potassium iodide, antimony oxide, copper iodide, sodium iodide, lithium iodide, aluminium chloride, bismuth oxide, calcium chloride, magnesium chloride and combinations of these. Preferably, an iodide compound such as potassium iodide is used. Other additives can be optionally added to a composition according to a preferred embodiment of the present invention. A non-limiting list of such common additives includes iron control agents (e.g. reducing agents), water-wetting surfactants, non-emulsifiers, deemulsifiers, foaming agents, antisludging agents, clay and/or fines stabilizer, scale inhibitors, mutual solvents, friction reducer. Alcohols and derivatives thereof, such as alkyne alcohols and derivatives and preferably propargyl alcohol and derivatives thereof can be used as corrosion inhibitors. Propargyl alcohol itself is traditionally used as a corrosion inhibitor which works well at low concentrations. It is however a very toxic/flammable chemical to handle as a concentrate, so care must be taken when exposed to the concentrate. One preferred compound to use 2-Propyn-1-ol, complexed with methyloxirane, as this is a much safer derivative to handle. Basocorr® PP is an example of such a compound. Metal iodides or iodates such as potassium iodide, sodium iodide, cuprous iodide and lithium iodide can potentially be used as corrosion inhibitor intensifier along with the composition according to preferred embodiments of the present invention. In fact, potassium iodide is a metal iodide traditionally used as corrosion inhibitor intensifier, however it is expensive, but works extremely well. It is non-regulated and safe to handle. The iodide or iodate is preferably present in a weight percentage ranging from 0.05 to 10 wt %, more preferably, 0.1 to 5 wt %, more preferably from 0.2 to 3 wt %, yet even more preferably from 0.25 to 2 wt %.

[0073] According to a preferred embodiment of the present invention, there is provided a method of matrix acidizing a hydrocarbon-containing limestone formation, said method comprising: [0074] providing a composition comprising a HCl and lysine mixture and water; wherein the molar ratio between the HCl and the lysine ranges from 4.5:1 to 8.5:1, [0075] injecting said composition downhole into said formation at a pressure below the fracking pressure of the formation; and [0076] allowing a sufficient period of time for the composition to contact said formation to create wormholes in said formation.

[0077] Lysine & hydrogen chloride are present in a molar ratio ranging from 1:3 to 1:12.5; preferably in a molar ratio ranging from 1:4.5 to 1:9, and more preferably in a molar ratio ranging from more than 1:5 to 1:8.5.

[0078] According to a preferred embodiment of the present invention, the acid used is neat HCl.

[0079] The corrosion inhibitor composition further comprises a metal iodide or iodate selected from the group consisting of: cuprous iodide; potassium iodide and sodium iodide. Preferably, the metal iodide or iodate is potassium iodide. According to another preferred embodiment of the present invention, the metal iodide or iodate is sodium iodide. According to yet another preferred embodiment of the present invention, the metal iodide or iodate is cuprous iodide.

[0080] Table 1 includes a prior composition (CI-5) and a composition according to a preferred embodiment of the present invention (CI-5SS).

TABLE-US-00001 TABLE 1 Composition of various tested corrosion inhibitor packages CI-5 CI-5SS 2-Propyn-l-ol, compd. with methyloxirane Vol % 45 20 .beta.-Alanine, N-(2-carboxyethyl)- Vol % 11.7 20 N-dodecyl-, sodium salt (1:1) Cocamidopropyl betaine Vol % 11.7 20 (±)-3,7-Dimethyl-2,6-octadienal (Citral) Vol % 7 7.5 Cinnamaldehyde Vol % 0 12.5 Isopropanol Vol % 24.6 20 Total 100 100 Vol %

Corrosion Testing

[0081] Corrosion inhibitor compositions according to preferred embodiments of the present invention were exposed to corrosion testing. The results of the corrosion tests and comparative corrosion testing are reported in Tables 2 through 5. Various steel grades (stainless steel and carbon steel) were subjected to acid compositions comprising corrosion inhibitors according to the present invention against known corrosion inhibitors to the listed compositions for various periods of time at varying temperatures. A desirable corrosion inhibition result was one where the lb/ft2 corrosion number is at or below 0.05. More preferably, that number is at or below 0.02.

[0082] 33% HCl:MEA in a 5.5:1 ratio and 50% HCl:MEA in a 5.5:1 ratio indicate the volume amount of the original concentration of a stock solution containing HCl and Monoethanolamine in a ratio of 5.5:1. The HCl loading of a 33% HCl:MEA in a 5.5:1 ratio is approximately 6.5% HCl. The HCl loading of 50% HCl:MEA in a 5.5:1 ratio is approximately 10% HCl.

TABLE-US-00002 TABLE 2 Corrosion testing of 316 steel coupons with various acidic fluid at various temperature run of 12 hours at a temperature of 90° C. Surface Steel Corrosion Loss wt area Density type Fluid inhibitor (g) (cm2) (g/cc) Mils/yr Mm/year Lb/ft2 316 33% 1.0% CI-5 1.2899 20.968 7.92 2232.38 56.702 0.126 HCl:MEA in 0.75% CI-1A a ratio of 0.1% NE-1 5.5:1 316 50% 1.0% CI-5 1.3647 20.968 7.92 2361.83 59.991 0.133 HCl:MEA in 0.75% CI-1A a ratio of 0.1% NE-1 5.5:1 *33% and 50% indicate the level of the original concentration of a stock solution containing HCl and Monoethanolamine in a ratio of 5.5:1. ** All percentages are given in volume/volume % of the total volume of the fluid.

TABLE-US-00003 TABLE 3 Corrosion testing of various steel coupons with various acidic fluid at various temperature run time of 6 hours Surface Steel Temp Corrosion Loss wt area Density type Fluid (° C.) inhibitor (g) (cm2) (g/cc) Mils/yr Mm/year Lb/ft2 316 33% 90 1.0% CI-5 0.2706 20.968 7.92 936.63 23.79 0.026 HCl:MEA incl 0.1% ZA in a ratio 0.75% CI-1A of 5.5:1 0.1% NE-1 316 33% 90 2.0% CI-5 0.5990 20.968 7.92 2073.33 52.66 0.058 HCl:MEA 0.75% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 0.75% CI-2 0.8117 20.968 7.92 2809.56 71.36 0.079 HCl:Urea 0.5% CI-4A in a ratio 0.5% CI-1A of 1:0.7 0.1% NE-1 316 33% 90 2.0% CI-5 1.1770 20.968 7.92 4073.98 103.48 0.115 HCl:MEA 0.75% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 0.75% CI-2 1.1348 20.968 7.92 3927.91 99.77 0.110 HCl:MEA 0.5% CI-4A in a ratio 0.5% CI-1A of 5.5:1 0.1% NE-1 316 33% 90 1.50% CI-5SS 0.1422 20.968 7.92 492.20 12.50 0.014 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 1.50% CI-5SS 0.3277 20.968 7.92 756.18 19.21 0.032 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 50% 90 1.50% CI-5SS 0.1974 20.968 7.92 683.27 17.36 0.019 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of5.5:l 316 33% 90 1.50% CI-5SS 0.6878 20.968 7.92 1587.13 40.31 0.067 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 50% 90 1.50% CI-5SS 0.2246 20.968 7.92 777.41 19.75 0.022 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 33% 90 1.50% CI-5SS 0.147 28.922 7.86 370.68 9.42 0.010 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 P110 33% 90 1.50% CI-5SS 0.112 34.839 7.86 236.15 5.998 0.007 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 1.50% CI-5SS 0.0593 20.968 7.92 205.26 5.214 0.006 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 110 1.50% CI-5SS 0.2499 20.968 7.92 864.98 21.971 0.024 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 33% 110 1.50% CI-5SS 0.134 28.922 7.86 338.06 8.587 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 P110 33% 110 1.50% CI-5SS 0.150 34.839 7.86 315.49 8.014 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 QT900 33% 110 1.50% CI-5SS 0.082 34.839 7.86 171.50 4.356 0.005 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 50% 110 1.50% CI-5SS 0.1675 20.968 7.92 579.77 14.726 0.016 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 50% 110 1.50% CI-5SS 0.123 28.922 7.86 312.02 7.925 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 P110 50% 110 1.50% CI-5SS 0.132 34.839 7.86 277.71 7.054 0.008 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 QT900 50% 110 1.50% CI-5SS 0.084 34.839 7.86 176.11 4.473 0.005 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 7.5% HCl 90 1.50% CI-5SS 0.0729 20.968 7.92 252.33 6.409 0.007 1.0% CI-1A 0.1% NE-1 316 10% HCl 90 1.50% CI-5SS 0.0406 20.968 7.92 140.53 3.569 0.004 1.0% CI-1A 0.1% NE-1 316 15% HCl 90 1.50% CI-5SS 0.0254 20.968 7.92 87.92 2.233 0.002 1.0% CI-1A 0.1% NE-1 316 10% HCl 90 1.50% CI-5 0.0309 20.968 7.92 106.95 2.717 0.003 1.0% CA 0.1% NE-1 Notes: CI-2 is a commercially available corrosion inhibitor (ASP 560) NE-1 is a non-emulsifier. CI-4A is propargyl alcohol with methyloxirane. CI-1A is potassium iodide ZA refers to cinnamaldehyde

TABLE-US-00004 TABLE 4 Corrosion testing carried out at 110° C. for a duration of 6 hours on various types of steel Surface Steel Corrosion Loss wt. area Density type Fluid inhibitor (g) (cm2) (g/cc) Mils/yr Mm/year Lb/ft2 316 50% 1.50% CI-5SS 0.1675 20.968 7.92 579.77 14.726 0.016 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 50% 1.50% CI-5SS 0.123 28.922 7.86 312.02 7.925 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 P110 50% 1.50% CI-5SS 0.132 34.839 7.86 277.71 7.054 0.008 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 QT900 50% 1.50% CI-5SS 0.084 34.839 7.86 176.11 4.473 0.005 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1

TABLE-US-00005 TABLE 5 Corrosion testing at 90° C. for a duration of 6 hours for stainless steel 316 coupons having a density of 7.92 g.cc and surface area of 20.968 cm2 Corrosion Wt loss Fluid inhibitor (g) Mils/yr Mm/year Lb/ft2 7.5% HCl 0.50% CI-5SS 0.0970  335.75  8.528 0.009 0.33% CI-1A 0.033% NE-1 10% HCl 0.50% CI-5SS 0.0838  290.09  7.368 0.008 0.33% CI-1A 0.033% NE-1 15% HCl 0.50% CI-5SS 0.0967  334.71  8.502 0.009 0.33% CI-1A 0.033% NE-1 10% HCl 0.50% CI-5 0.1729  598.46  15.201 0.017 0.33% CI-1A 0.033% NE-1 33% HCl: 1.50% CI-5SS 0.7512 2600.15  66.044 0.073 Urea in 1.0% CI-1A a ratio 0.1% NE-1 of 1:0.7 10% HCl No CI 2.4590 8511.40 216.189 0.239

[0083] The corrosion testing results obtained indicate, in the preferred corrosion inhibitor developed, CI-5SS, the need for both an alkyne alcohol (propargyl alcohol) and cinnamaldehyde. Separately, they did not provide corrosion protection sufficient to allow the novel method disclosed herein to be implemented. The difficulty with the use of cinnamaldehyde is to maintain it dispersed at higher temperatures such as 90° C. to 110° C. The surfactant package used according to a preferred embodiment of the present invention is capable of providing such cinnamaldehyde dispersion but requires higher loadings than usual. Citral has shown some effectiveness for the prevention of pitting at higher temperatures (even 110° C. to 120° C.). The cinnamaldehyde is an effective film former at these temperatures and by was able to protect the stainless steel.

[0084] The testing results confirms the feasibility of a widespread implementation of the method according to a preferred embodiment of the present invention where the step of removing a perforating tool prior to injection of the spearhead acid composition. The inventors have also noted that by carefully balancing the acidic composition % content of active acid (for example HCl) with an appropriate corrosion inhibitor or blend of several components to obtain a good performance corrosion inhibitor one may apply this type of method to various other oilfield downhole operations where the acidic composition comprises a corrosion inhibitor and is sufficiently balanced to complete said operations within a reasonable time period which will leave the tool with minimal corrosion damage from exposure to the acidic composition.

[0085] The inventors have also noted that by diluting an initial concentrated acidic composition (whether it is HCl or a modified acid comprising an HCl component therein) and where said initial concentrated acidic composition already comprises a corrosion inhibitor package, the corrosion protection performance can be noticeably worse in a diluted composition as the CI components are fewer for a similar volume of acid. This surprising result has been more noticeable at elevated temperatures but should be understood to be part of the acidic composition blending strategy when “balancing” the acidic composition and its CI content. One way to balance the diluted acidic composition is to add one or more or even all of the CI components originally present in the CI package in the undiluted acidic composition. Another component to consider when balancing the acidic composition is to determine the downhole materials encountered as well as the casing and the tools (which are typically made of stainless steel.

[0086] Balancing comprises, among other things, altering the pH constantly as the dissolved cement raises the pH of the system as it is drilled out. It is desirable to maintain the minimal pH required “only” so as to increase the rate of penetration (ROP) to the optimal rate. Usually, the cement is not drilled out with pure acid (unless very tough drilling or maybe only to initiate the job) so as to control costs, reduce corrosion concerns etc. 10. The method according to claim 8, wherein the acid comprises an HCl component.

[0087] According to a preferred embodiment, the balancing of the acidic composition is done by adding more of at least one of the components present in the corrosion inhibitor package itself present in the undiluted acidic composition.

[0088] According to a preferred embodiment, the balancing of the acidic composition is done by altering the pH constantly as the dissolved cement raises the pH of the system as it is being dissolved by the acidic composition.

[0089] Typically, to perform and plug and perf operation, the concentration of the acid can vary from 4% (equivalent HCl content) to 15% (eq. HCl). One can perform at higher % but would not get much additional benefit and may cause some unwanted damage or unnecessary corrosion. Preferably, an acidic composition comprising a 7.5% (equivalent HCl content) is most often used to perform plug and perf operations. According to a preferred embodiment, the CI package and content is determined in accordance in order to optimize the financial aspect of the operation. This involves balancing the acidic composition (HCl eq. content), the CI package (price and performance) and value of the damage to the bottom hole assembly tool as well as the coil tubing or wireline or slickline used during the operation.

[0090] The inventors have noted that, surprisingly, modified acids containing urea are not desirable as they have a stability upper limit of approximately 80° C. Above this temperature, the urea component starts to decompose yielding CO.sub.2 and ammonia, thereby neutralizing the acidic component and therefore, it would not be the ideal candidate for spearhead or wireline deployed spearhead operations as most operations are performed at temperatures close to or above 80° C. Corrosion inhibitor compositions according to preferred embodiment of the present invention have shown excellent versatility and stability at high temperature (up to 190° C.) between conventional acids (HCl) and modified acids (HCl:MEA) as well as steel types (QT900 (stainless steel); P110 (carbon steel); L80 (carbon steel); 316 (stainless steel).

[0091] As illustrated in FIG. 1, pumping acid downhole while the wireline and perforating tool is present downhole has been shown in the field to save, in some instances 15 minutes per perforation operation. Moreover, the savings of water are equally staggering. The following is but a list of substantial advantages of performing such a process: combining pumping down the plug with displacing the ball and acid; reducing pumpdown cycle time; reducing fluid volumes required. The concerns noted by the operators were the following: defining fluid bypass around the plug; the method was dependent on the rate the plug was being pumped; and the rate achieved for pumpdown was variable from stage to stage.

EXAMPLE 1—WIRELINE TESTING EXPERIMENTS

[0092] Specific tests for a modified acid composition comprising an alkanolamine:HCl blend (present in a molar ratio of 1:6.4 also containing a corrosion inhibitor package) (diluted to one third of its stock solution, i.e. 33%) and a commercialised 7.5% HCl acid blend (containing a CI package) spearhead blend were performed on wire line samples to simulate long term field exposure conditions under extreme conditions at the request of a global oil company. Due to cool down effect and limited real world exposure times, these tests would be indicative of a long-term duty cycle.

[0093] The tensile strength and corrosion tests were executed on wire line samples provided by Company B. One sample was exposed to 33% alkanolamine:HCl composition and another sample was exposed to the 7.5% HCl acid blend for 96 and 120 consecutive hours at 90° C. (194° F.) at 600psi. The weight loss of the wire line samples is expected to be attributed not only the corrosion of the steel but also the degradation of the binding material. After the corrosion test cycle, tensile strength testing was conducted on two strands pulled from the wire line exposed to the 33% alkanolamine:HCl composition. The tensile strength values for each strand were equal to control samples that were not exposed to the acid. Tensile strength testing was not performed on the wire line exposed to the 7.5% HCl acid blend due to excessive corrosion.

EXAMPLE 2—P110 COUPON CORROSION TESTS

[0094] Long term corrosion tests on P110 coupons with a 33% alkanolamine:HCl composition and the 7.5% HCl acid blend at 90° C. (194° F.) were also carried out. The corrosion properties of the 33% % alkanolamine:HCl composition was observed to provide superior protection in comparison to the 7.5% HCl acid blend over a long time period. The testing allows to select an ideal composition which will minimize corrosion to the wireline over a number of plug and perf operations. However, it should be noted that a less than optimal acidic composition (comprising a corrosion inhibitor) may be employed in order to substantially reduce time spent on pre-frac operations, minimize water volumes used and therefore, provide a financial advantage of performing this method as well as a substantial water usage reduction over the conventional approach used prior to this novel process.

[0095] Procedure: To determine the corrosion properties of unspent 33% alkanolamine:HCl composition and the 7.5% HCl acid blend (containing a CI package), the acid blends were evaluated at 90° C. (194° F.) on P110 coupons for 96 hours (4 days) at ambient pressure. The corrosion tests were executed in samples jars in a water bath. The corrosion rates were determined from the weight loss after the coupons were washed and dried.

[0096] Results: The testing results confirms the feasibility of a widespread implementation of the method according to a preferred embodiment of the present invention where the step of removing a perforating tool prior to injection of the spearhead acid composition is removed and the tool remains downhole during the acid breakdown step.

EXAMPLE 3—FIELD TRIAL

[0097] A major E&P company operating in Western Canada performing horizontal multi-stage slickwater completions on multi well pads. Using plug and perf completion technique they were targeting the Duvernay and Montney formations. Reservoir temperatures were approximately 230° F. Historically 15% HCl acid was used to breakdown the formation and assist in fracture propagation.

[0098] Approximately 97,500 gals of a modified acid using an alkanolamine:HCl composition with a corrosion package was delivered to location. Dilutions ranged from a 2-1 water-acid ratio to yield a 33% modified acid concentration and 1-1 for a 50% dilution. The blended modified acid (1300 gal) was placed in the wellbore and then the wireline and pump-down crews continued to the next well. As the treatment commenced, crews displaced acid to perforations with frac water. Once the acid reached the perforations an immediate pressure drop was observed, all frac pumps were brought on-line to pre-engineered rates and operations commenced. FIG. 2 illustrates the time advantage of using an embodiment of the method of the present invention (right graph) in comparison to the conventional method (left graph).

[0099] A significant pressure drop was observed as the acid reached the perforations and it was noted that breakdowns looked very similar to that obtained with 15% HCl which had been previously pumped on the same pad. Both the service company and operator were very pleased with the performance, ease of use of the acid while utilizing a technically advanced, safer and more environmentally responsible product along with eliminating corrosion concerns was a major value add to the customer and all involved with the project. The modified acid composition allowed the company to have confidence that the casing metals were free from hydrogen embrittlement and any corrosion related issue that would have arisen by utilizing HCl. This time saving method would not be possible with any existing HCl blends offered in the market. Observations by the crew included the time savings. Moreover, the company and pumping crews on location had the opportunity to use an acid which has an inherent safety profile adapted to minimize or eliminate the extremely dangerous properties associated with 15% HCl. Some of the safety factors include: less-corrosive to dermal tissue; low-vapor pressure effect (fuming); low-toxicity (Calculated LD-50 Rat); lower bioaccumulative effect; and biodegradable.

[0100] Along with the safety aspect of the acid composition used, there is also the technical advantages it brought to the operations: low corrosion properties—<0.02 lb/ft.sup.2 for more than 24 hrs; pump acid with wireline BHA (save time and water); in the event of surface equipment failure occur, there is no need to flush acid out of wellbore; the composition is hauled as a concentrate and diluted on location; provides the ability to adjust acid strength for tougher breakdowns; fewer acid trucks on the road (landowner optics); it is a class one product (chemicals will not separate out over time); and it can be diluted with available water (produced/sea water/fresh). Additional benefits of the modified acid used in the example include: ultra-low long term corrosion effects (168 hrs); no precipitation of solubilized Ca post pH increase (eliminating risks of formation damage); clear: low fuming/vapor pressure; aggressive reaction rates on stimulations and workovers; custom blend allowing spotting of acid with perforating guns via wireline; compatible with typical elastomers used in oil and gas; allows to adjust concentrations on the fly to target optimal pay zones; and it has a high thermal stability up to ˜190° C.

EXAMPLE 4—FIELD TRIAL #2

[0101] Another large Oil and Gas company carried out wireline plug and perf operations and collected the below information in terms of performance. The average time from start of pumping to start of sand was determined to be 8.2 mins faster for wireline stages where the tools and wireline went downhole together, compared to the average of all other stages. The average stage pump times were determined to be 9.4 mins lower for the Wireline stages where acid was injected along with the perforating tool and wireline, compared to average of all other stages. See FIG. 3 which highlights the difference in time for each step.

[0102] The company using the method according to a preferred embodiment of the present invention, noted the following spearhead operational efficiencies: the ability to pump acid with wire line and BHA (guns and bridge plug); the elimination of the need to displace acid after wireline is out of the hole; the reduced water requirements; savings of at least one hole volume per frac (>10,000 gal water reduction per stage); allowing acid to be spotted over the entire perf interval cluster; more effective cluster breakdown; increased frac crew efficiency; and shorter time to initiate the frac and get to job rates.

EXAMPLE 5—CORROSION TESTING ON VARIOUS WIRELESS

[0103] Corrosion testing was carried out on various manufacturers' wirelines using an acidic composition comprising an alkanolamine:HCl blend with a corrosion inhibitor package. The wireline material of four different manufacturers were tested corrosion resistance at a temperature of 130° C. and at 400 psi for periods of time ranging up to 24 hours of exposure. Table 7 (below) provides a summary of the corrosion data from this testing series.

TABLE-US-00006 TABLE 7 Corrosion Test Results of 33% composition comprising MEA:HCl (in 1:4.1 molar ratio) at 130° C. (266° F.) at 400 psi over various time periods Cumulative Weight Loss 6 hrs 12 hrs 18 hrs 24 hrs Test Sample mm/yr lb/ft.sup.2 mm/yr lb/ft.sup.2 mm/yr lb/ft.sup.2 mm/yr lb/ft.sup.2 A #1 clear 19.727 0.022 22.121 0.024 25.423 0.028 28.146 0.031 wire B #2 clear 18.902 0.021 20.800 0.023 23.854 0.026 — — wire C #3 clear 19.810 0.022 23.772 0.026 27.651 0.030 — — wire D Sanded wire 17.334 0.019 20.470 0.022 23.277 0.026 28.229 0.031

[0104] The results support the applicability and feasibility of the method according to a preferred embodiment of the present invention. Moreover, more optimal compositions falling within the scope of the present invention can be developed in order to obtain better financial, water-savings and/or corrosion results over conventional processes.

[0105] According to another aspect of the present invention, there is provided a method to perform a downhole operation for drilling with acid to increase ROP (rate of penetration) through cement plugs, said method comprises the following steps: [0106] inserting a drilling tool inside a wellbore; [0107] injecting an acidic composition concurrently with the drilling tool; [0108] position the drilling tool within the wellbore at a point requiring drilling; [0109] contacting the surface requiring drilling with the acid and begin drilling; and [0110] continue the drilling operation until desired distance has been achieved;
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0111] According to another aspect of the present invention, there is provided a method to perform a downhole operation for coiled tubing deployed acid washes, said method comprises the following steps: [0112] inserting a coiled tubing inside a wellbore; [0113] injecting an acidic composition concurrently with the drilling tool; [0114] position the drilling tool within the wellbore at a point requiring drilling; [0115] contacting the surface requiring drilling with the acid and begin drilling; and [0116] continue the drilling operation until desired distance has been achieved,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0117] According to another aspect of the present invention, there is provided a method to perform a downhole operation for coiled tubing deployed filter cake treatments said method comprises the following steps: [0118] inserting a coiled tubing inside a wellbore; [0119] injecting an acidic composition concurrently with the coiled tubing [0120] position the coiled tubing within the wellbore at a point requiring a treatment on said filter cake; [0121] contacting the surface requiring treatment with the acidic composition; and [0122] allow contact between the acidic composition and the filter cake until the filter cake has been effectively treated or removed from the walls of the wellbore,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0123] It is often desirable to seal tubing or other pipe in the casing of the well, for example when cement or another type of slurry must be pumped down the tubing and force the slurry out into a formation. In such instances, one must be able to seal the tubing with respect to the well casing and to prevent the fluid pressure of the slurry from lifting the tubing out of the well. This can be accomplished by packers and bridge plugs as well as ball in cage valves.

[0124] According to another aspect of the present invention, there is provided a method to perform a downhole operation for dissolving plugs and balls; wherein said method comprises the following steps: [0125] injecting an acidic composition down the wellbore at a position proximate said ball; [0126] allowing sufficient contact time for the acidic composition to dissolve ball to allow further processing to occur,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0127] According to another aspect of the present invention, there is provided a method to perform a downhole operation for slower (matrix) rate isolated (thru coil) acid stimulations, wherein said method comprises the following steps: [0128] providing a wellbore comprising at least one area requiring matrix acidization; [0129] injecting an acidic composition down the wellbore at a position proximate said area requiring matrix acidization; [0130] allowing sufficient contact time for the acidic composition to perform the matrix acidization step; [0131] optionally, remove the tool; [0132] optionally, further process the acidized formation,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble formation within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0133] According to another aspect of the present invention, there is provided a method to perform a downhole operation for fishing tools in the presence of an acid to consume debris on top of the tool trying to be recovered, wherein said method comprises the following steps: [0134] injecting an acidic composition down the wellbore concurrently with a fishing tool at a position proximate a said ball; [0135] allowing sufficient contact time for the acidic composition to dissolve ball to allow further processing to occur,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0136] According to another aspect of the present invention, there is provided a method to perform a downhole operation for stuck coil or tools in casing, where the sticking is caused by an acid soluble debris, said method comprising the steps of: [0137] injecting an acidic composition in the wellbore; [0138] directing the acidic composition at a point within the wellbore where said coil is stuck [0139] allowing the acidic composition sufficient contact time at and near said area to allow the acid soluble debris to be dissolved by the acidic composition,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0140] Preferably, the following are some of the tools that may be used as part of a bottom hole assembly (BHA): drilling motors; washing tools; perforating guns; fishing tools; plugs; balls; any BHA with a high stainless steel metal content in general.

[0141] According to another aspect of the present invention, there is provided a method to perform a debris and scale management inside wellbores when having both a tool and an acid present at the same time. According to a preferred embodiment of a method of the present invention, one can perform spotting acid to dislodge stuck pipes inside a wellbore. Preferably, coiled tubing or a BHA (bottom hole assembly) injected into the wellbore can help free down-hole in situ items like chokes or flow-controls, safety valves, etc. According to a preferred embodiment of a method of the present invention, one can perform an operation to clean a wellbore with a reaming tool in the presence of an acid.

[0142] According to another aspect of the present invention, there is provided a method to perform a downhole operation for spotting acid in a wellbore, said method comprising the steps of: [0143] providing a wellbore in need of stimulation; [0144] inserting a plug in the wellbore at a location slightly beyond a predetermined location; [0145] inserting a perforating tool and a spearhead or breakdown acid into the wellbore; [0146] positioning the tool at said predetermined location; [0147] perforating the wellbore with the tool thereby creating a perforated area; and [0148] allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient,
where the acidic composition comprises a corrosion inhibitor package as described above and is sufficiently balanced to complete the operation of dissolving the acid soluble debris within a time period which will leave the tool with acceptable (in some cases, minimal) corrosion damage from exposure to the acidic composition.

[0149] While the foregoing invention has been described in some detail for purposes of clarity and understanding, it will be appreciated by those skilled in the relevant arts, once they have been made familiar with this disclosure that various changes in form and detail can be made without departing from the true scope of the invention in the appended claims.