Corrosion inhibitor for wellbore applications

Abstract

This invention concerns a corrosion-inhibitor nominally comprised of a phenolic compound and a hydroxide-bearing compound capable of imparting a pH of 9 to water, the inclusion thereof in aerated water-based fluids and foams, and the use of these fluids in wellbore applications; particularly applications conducted at elevated temperatures.

Description

BACKGROUND OF THE INVENTION

This invention relates to a corrosion inhibitor and the use thereof in wellbore applications.

Aerated liquids and foams are frequently employed as wellbore fluids during drilling, completion, workover and production operations. Aerated as used herein refers to the existence of distinct gas and liquid phases. Aerated liquids are distinguishable from foams by the absence or the presence in de minimis amounts of surface active agents which promote gas-liquid interphase dispersibility.

Aerated liquids and foams are particularly useful when reduced hydrostatic pressures in wellbores are desired. The reduced hydrostatic pressure or head is made possible by the lower bulk densities of aerated liquids and foams when compared to their liquid counterparts. Examples wherein reduced hydrostatic heads are favored include (1) situations where the wellbore fluids are exposed to under-pressured geological strata and minimum invasion of the strata by the wellbore fluid is desired and (2) during the perforation of a geological strata at underbalanced conditions (i.e., wellbore pressure less than fluid pressure in exposed strata) wherein the reduced head helps to minimize plugging of the perforation caused by movement of fines into the perforation from the wellbore.

Aerated liquids are nominally comprised of a gas and a liquid and may additionally contain additives such as corrosion inhibitors and suspended solids such as mud and sand. Aerated fluids useful in drilling, completion, workover and production operations are typically prepared by the downhole combination of a gas and a liquid. In drilling, one means of combining these components downhole is by the use of dual drill strings and dual swivels. Another means frequently used in downhole applications is to employ parasitic tubing for transporting the gas downhole to an injection point where it is combined with liquid and returned to the surface. Injection of gas at any downhole location serves to reduce the bottomhole hydrostatic head from that of a 100% liquid head. Downhole gas injection is also practiced when gas lift is used to facilitate fluids production in a well.

Foams are highly dispersed gas in liquid two-phase systems. A foam is physically composed of gas bubbles surrounded by a surfactant-bearing aqueous film and is nominally comprised of a gas, at least one surfactant which functions as a foaming agent, and water. The quality of the foam or foam quality is defined to be the volume percent of gas in the two-phase mixture. The water used in foams may be chemically pure, fresh, or contain varying degrees of salinity and/or hardness. The foam may additionally be comprised of other additives which alter the properties of the foam. Such additives include selected polymers and/or bentonite which increase film strength thereby forming stiff or gel foams and corrosion inhibitors which function to decrease foam corrositivity in metal-bearing systems.

The rheological properties of foam are complex and provide a separate and distinct basis for distinguishing foam from aerated and non-aerated liquids. The rheological properties are dependent upon many parameters such as bubble size and distribution, fluid viscosity, foam quality, and the concentration and type of foaming agent used. The use of foam in place of conventional fluids generally reduces the degree of fluid invasion from the wellbore into the surrounding strata. Furthermore, the foam which does invade the strata generally contains a high volume percentage of gas which upon pressurization possesses significant energy. Upon depressurization, the stored energy which is released causes a significant portion of this fluid to be returned to the wellbore. Compared to conventional fluids, foam also possesses at low linear flow velocities excellent carrying capacities, particularly for water and solids. These properties are particularly useful when conducting drilling, completion and workover operations on vertical and horizontal wells and even more so when low pressure, semi-depleted or water sensitive formations are encountered. The unique properties of foam also enable the use of coiled tubing units during workover operations. The use of such units results in significant savings of time and money because downhole operations can be performed without removal of the wellbore tubing.

Historically, a major problem associated with the use of aerated liquids and foams has been metal corrosion attributed to the presence of oxidizing agents such as oxygen, hydrogen sulfide and carbon dioxide in the gas phase. Oxygen generally originates from air. Carbon dioxide and hydrogen sulfide are generally produced from the geological strata of interest. Corrosion problems generally become more sever as wellbore temperatures increase. Because of cost and availability, air is the preferred gaseous species when downhole corrosion is not a problem. However, because of the lack of suitable corrosion inhibitors when downhole conditions become severe (i.e., high temperatures and the presence of significant quantities of oxidizing agents), inert gases which are expensive, most notably nitrogen, are frequently used.

SUMMARY OF THE INVENTION

It is an object of this invention to develop a corrosion inhibitor suitable for use in gas-liquid systems as oxidative conditions.

It is a further object of this invention to develop a corrosion-inhibited gas-liquid mixture suitable for use under oxidative conditions.

It is a still further object of this invention to develop a corrosion-inhibited foam suitable for use under oxidative conditions.

It is yet a still further object of this invention to develop a corrosion-inhibited oxygen-bearing gas/liquid mixture suitable for use in wellbore applications including drilling, workover, completion and production.

It is still yet a further object of this invention to develop a corrosion-inhibited air/liquid mixture suitable for use at temperatures of at least about 200.degree. F.

Still a further object of this invention to develop a corrosion inhibited oxygen-bearing gas/liquid mixture wherein the chemicals imparting the corrosion-inhibition properties are relatively inexpensive commodity chemicals.

A yet still further object is to develop a process employing foam suitable for use under highly oxidative conditions in the drilling, completion, workover and production of wells.

In accordance with this invention, a formulation for a corrosion inhibitor comprised of a phenolic compound and a hydroxide-bearing compound capable of imparting basicity to water has been developed.

In a second embodiment, a corrosion-inhibited gas-liquid mixture nominally comprised of a gas, water, a phenolic compound and a hydroxide-bearing compound capable of imparting basicity to water has been discovered.

In a third embodiment, a novel corrosion-inhibited gas foam nominally comprised of gas, water, foaming agent, and a corrosion inhibitor comprised of a phenolic compound and a hydroxide-bearing compound capable of imparting basicity to water has been discovered.

In a fourth embodiment, a process utilizing the inventive gas-liquid mixture under oxidative conditions such as those existing in wellbore applications has been discovered.

And in a fifth embodiment, a process utilizing the inventive foam under oxidative conditions such as those existing in wellbore applications has been discovered.

DESCRIPTION OF THE INVENTION

In its multiple embodiments, this invention concerns a unique formulation for a corrosion inhibitor, a formulation for corrosion-inhibited aerated liquids, a formulation for corrosion-inhibited foams, and the use thereof of the aerated liquids or foams in wellbore applications which include drilling, workover, completion and production operations.

Corrosion Inhibitor

The inventive corrosion inhibitor is nominally comprised of at least one phenolic compound including the salts thereof and at least one hydroxide-bearing compound capable of imparting a pH of at least 9 to an aqueous phase. The hydroxy-bearing hydrocarbon compound is preferably a phenolic compound of the formula ##STR1## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO.sub.2, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohols, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water dispersible or soluble.

Another group of compounds included within the term phenolic compound are the flavotannins. Flavotannins are polyphenolic materials which are extracted from the bark and wood of trees. Quebracho is an example of a suitable flavotannin.

Representative examples of suitable phenolic compounds are those selected from the group consisting of monohydroxy phenols, polyhydroxy phenols, monohydroxy naphthols, polyhydroxy naphthols, o-cresol, m-cresol, p-cresol, o-fluorophenol, m-fluorophenol, p-fluorophenol, o-chlorophenol, m-chlorophenol, p-chlorophenol, o-bromophenol, m-bromophenol, p-bromophenol, o-iodophenol, m-iodophenol, p-iodophenol, o-nitrophenol, m-nitrophenol, p-nitrophenol, flavotannins, phenol, resorcinol, catechol, hydroquinone, phloroglucinol, pyrogallol, 1,3-dihydroxynaphthalene, o-methoxyphenol, p-methoxyphenol, o-methoxyphenol, o-hydroxybenzoic acid, p-hydroxybenzoic acid, m-hydroxybenzoic acid, o-phenolsulfonic acid, p-phenolsulfonic acid, m-phenolsulfonic acid, dichlorophenols, 4,4-biphenol, salicylaldehyde, guaiacol and the salts of the preceding acids and alcohols or mixtures thereof selected from the preceding group.

The phenolic compound is more preferably phenol, o-cresol, o-fluorophenol, o-chlorophenol, o-bromophenol, o-iodophenol, o-nitrophenol, catechol, resorcinol, guaiacol, hydroquinone, salicylaldehyde, phloroglucinol, pyrogallol, 4,4-biphenol, 1,3-dihydroxy naphthalene or o-allylphenol or any of the salts of the preceding or mixtures thereof of the preceding. Still more preferred are those selected from the group consisting of phenol, o-cresol, salicylaldehyde, o-nitrophenol and the ammonium, sodium and potassium salts thereof or mixtures of the preceding. The most preferred phenolate salts are those of sodium and potassium. Based on performance, cost, and commercial availability, the most preferred phenolic compounds are phenol and the sodium and potassium salts thereof which are sodium phenolate and potassium phenolate.

The hydroxide-bearing compound must be a compound capable of imparting a pH of 9 to an aqueous phase. Preferred hydroxide-bearing compounds are the alkali metal hydroxides, ammonium hydroxide or mixtures thereof. More preferred are those selected from the group consisting of ammonium hydroxide, sodium hydroxide and potassium hydroxide. Of these, sodium hydroxide and potassium hydroxide are still more preferred. Most preferred is potassium hydroxide.

The hydroxide-bearing compound must be present in an amount effective to insure appreciable dissociation of the hydrogen atoms associated with the hydroxyl group or groups on the phenolic compound. On a molar basis, a mole ratio of hydroxide-bearing compound to phenolic compound of 5 to 1000 is preferred. A mole ratio of about 10 to about 500 more preferred. A ratio of about 20 to about 350 is most preferred. When using the preferred hydroxide-bearing compounds consisting of ammonium hydroxide, potassium hydroxide or sodium hydroxide or mixtures thereof and the most preferred phenolic compound, phenol, a hydroxide compound to phenol weight ratio of about 10 to about 70 is preferred. When using the more preferred sodium hydroxide and potassium hydroxide species, a weight ratio of about 10 to about 40 is preferred.

The corrosion inhibitor may additionally be comprised of water in an amount effective to function as a dispersing or carrying agent for the phenolic compound and the hydroxide-bearing compound thereby simplifying the mixing of these components with other components when preparing aerated liquids or foams. The water may be chemically pure, fresh or contain appreciable salinity and/or hardness and may contain dissolved gases which favor oxidation.

The inventive corrosion inhibitor is distinguished from many other inhibitors, particularly scavengers, by its ability to effectively function when the molar ratio of a key active component, the phenolic compound, to the oxidizing agent or agents in the system is significantly less than 1. The corrosion inhibitor is effective at both ambient and elevated temperatures. The inventive inhibitor is also distinguishable from many commercially available inhibitors by its effectiveness at temperatures of at least about 200.degree. F. and is further distinguished by its superior corrosion inhibition properties at temperatures of at least about 350.degree. F. The corrosion inhibitor is particularly effective when the oxidizing agent is oxygen or the oxidation-related compounds thereof.

Corrosion-Inhibited Aerated Liquid

A corrosion-inhibited aerated liquid possessing various utilities as a wellbore fluid has been discovered. The aerated liquid is nominally comprised of a gas which contains an oxidizing agent, water, and the inventive corrosion inhibitor described in the previous section. As previously noted, the corrosion inhibitor is particularly effective when the oxidizing agents are hydrogen sulfide, carbon dioxide, and oxygen or oxidation-related compounds to these agents. Treatment of aerated liquids containing oxygen as the oxidizing agent is preferred. The water may be chemically pure, fresh, or contain appreciable salinity and/or hardness and may contain dissolved gases, some of which may favor oxidation. The aerated liquid may additionally be comprised of solids such as sand and dirt or a separate organic phase.

Aerated liquids are particularly useful when a reduction in the bulk density of the base liquid is desired. Such a need frequently occurs in wellbore applications when a reduction in hydrostatic head is desired.

An aerated liquid is prepared by combining a gas containing at least one oxidizing agent, a water-based liquid, and the corrosion inhibitor using ordinary skill in the art. Preferably, the water-based liquid and corrosion inhibitor are first combined to form a corrosion inhibited liquid. The gas is then added via contacting the liquid and gas phases. In the drilling, completion, workover, or production of a well, the latter contacting step is usually conducted downhole in a borehole using ordinary skill in the art.

The corrosion inhibitor may also be used in well production wherein gas lift technology is used. In such an application, the corrosion inhibitor may be combined downhole with the gas used for gas lift and the produced fluids which contain water. In such an application, the reduced hydrostatic head allows the reservoir fluids, which may also include a separate gas phase, to flow to the surface using the existing reservoir pressure as the driving force thereby avoiding the use of more complicated and expensive means of production such as pumpjacks, submersible pumps, etc. In such an operation, gaseous oxidizing agents such as hydrogen sulfide, carbon dioxide, or oxygen and oxidation-related compounds of these agents may be present in either the gas used for the gas lift or in the fluids produced from the reservoir.

The required concentration of corrosion inhibitor in the aerated fluid is that amount effective to insure corrosion inhibition over the time frame of interest at the conditions of interest. These concentrations may be readily ascertained by one skilled in the art via routine test procedures. Generally, the preferred weight percent of hydroxide-bearing compound and phenolic compound based on the combined weight of water and corrosion inhibitor are about 0.1 to about 40 wt % and about 0.005 to about 4.0 wt %, respectively. More preferred are respective weight percent ranges of about 1 to about 20 wt % and about 0.01 to about 0.50 wt %, respectively. Still more preferred are respective weight percent ranges of about 1 to about 10 and about 0.05 to about 0.30. The most preferred weight percent ranges are about 5 to about 10 and about 0.10 to about 0.30, respectively.

One factor distinguishing the inventive corrosion inhibitor from other inhibitors, particularly scavengers, when incorporated into aerated liquid, is the ability of the inhibitor to effectively function when the molar ratio of a key active component, the phenolic compound, to the oxidizing agent or agents in the system is significantly less that 1. The corrosion-inhibited aerated liquid may be used in metal-bearing systems at both ambient and elevated temperatures. An additional factor distinguishing the inventive inhibitor from the many commercially available inhibitors is its effectiveness at temperatures of about or greater than 200.degree. F. and even more so, its effectiveness at temperatures of about or greater than 350.degree. F. The corrosion inhibitor when incorporated into an aerated liquid is particularly effective when the oxidizing agent is oxygen or the oxidation-related compounds thereof.

Corrosion-Inhibited Foam

The inventive corrosion-inhibited foam is nominally comprised of a dispersed gas phase wherein the gas contains an oxidizing agent and a continuous liquid phase nominally comprised of a foaming agent, water in a major portion, and the inventive corrosion inhibitor. The water may be chemically pure, fresh, or contain appreciable salinity and/or hardness, and may contain dissolved gases, some of which may favor oxidation. At the discretion of one skilled in the art, the liquid phase may contain other additives which function to produce a better performing foam at the conditions of use. Foam stabilizers are one such example. The foam may additionally contain solids such as sand and dirt and/or a separate organic phase.

The volume percentage of the combined gaseous and liquid phase which is gas is defined to be the foam quality. The quality of the foam is preferably about 60 to about 99.75% and more preferably about 75 to about 99.5 volume percent at wellbore conditions. The properties of the foam may be altered by the use of various additives known to those skilled in the art. As an example, a stiffer foam may be prepared by adding guar gum or other organic polymers and solids such as bentonite to the base components.

The gaseous phase may initially contain an oxidizing agent or the phase may be inert and absorb oxidizing agents such as oxygen, hydrogen sulfide or carbon dioxide or oxidation-related compounds during the course of process operation. Because of the effectiveness of the inventive corrosion inhibitor, when oxygen is the oxidizing species, inhibited foams containing oxygen are particularly favored. Because of cost and availability, a gaseous phase comprised in major portion of air is preferred.

As previously discussed for the aerated liquid, corrosion inhibitor in an amount effective to insure corrosion inhibition over the time frame of interest at the conditions of interest is required. These concentrations may be readily ascertained by one skilled in the art via routine test procedures. Specific ranges of preference based on the combined weight percentage of water, corrosion inhibitor and foaming agent are identical to those reported for the aerated liquid wherein said weight percentage was based on water and corrosion inhibitor.

One factor distinguishing the inventive corrosion inhibitor from other inhibitors, particularly scavengers, when incorporated into foam is the ability of the inhibitor to effectively function when the molar ratio of a key active component, the phenolic compound, to the oxidizing agent or agents in the system is significantly less than 1. The corrosion-inhibited foam may be used in metal-bearing systems at both ambient and elevated temperatures. An additional factor distinguishing the inventive corrosion-inhibited foam from many foams using commercially available inhibitors are the corrosion inhibition properties exhibited at temperatures of about and greater than 200.degree. F. and more so, the superior corrosion inhibition properties exhibited at temperatures of about and greater than 350.degree. F. The corrosion inhibitor is particularly effective when the oxidizing agent is oxygen or oxidation-related compounds thereof.

Foaming agent in an amount effective to obtain the desired foam quality is required. The concentration will be dependent on water salinity and hardness, foaming agent, and anticipated exposure conditions in the wellbore. The selection of an appropriate agent and the concentration of said agent is readily within the capability of one possessing ordinary skill in the art. Test methods routinely used by one skilled in the art include the Ross-Miles foam analysis method discussed in Oil and Soap, Vol. 18, 1941, pages 99-102 and Synthetic Detergent, J. W. McCutcheon-author, McNair-Dorland Co., New York, N.Y., 1950, specifically page 435; both of which are hereby incorporated by reference in their entirety. One class of preferred foaming agents are those possessing a Ross-Miles initial foam height of at least 10 cm and a cumulative foam height of at least 30 cm at test conditions where cumulative foam height is the sum of foam heights at 0, 1, 2, 5 and 10 min obtained using the Ross-Miles methods. Typical foaming agent concentrations, based on active foaming agent concentration, are about 0.005 to about 4.0 wt % based upon the weight of water, corrosion inhibitor and foaming agent in the liquid phase. More preferred foaming agent concentrations are about 0.01 to about 1.0 wt % based on the liquid phase. Still more preferred foaming agent concentrations are about 0.1 to about 0.3 wt % also based on the liquid phase.

A wide variety of compounds referred to as surfactants possess foam-forming properties. The propensity of these compounds to function as foaming agents is discussed in the section entitled "Surfactants and Distersive Systems", Kirk-Othmer Encyclopedia of Chemical Technology, 3rd Edition, Volume 22, pages 332-387 which is hereby incorporated by reference in its entirety.

Preferred foaming agents include one or more of the following:

(a) One or more N-acylsarcosinates, more preferably one or more possessing the formula of: ##STR2## where R is cocoyl, lauryl, or oleoyl and M is H or Na;

(b) One or more sodium N-acyl-N-alkyltaurates, more preferably one or more possessing the formula of ##STR3## where R is cocoyl, palmitoyl, or tall oil;

(c) One or more alkyl sulfates, more preferably one or more possessing the formula of

R--O--SO.sub.3 M where R is lauryl and M is an ammonium-containing or an alkali metal cation, more preferably Na, Mg, K, NH.sub.4, MEA (monoethanolammonium), DEA (diethanolammonium) or TEA (triethanolammonium);

(d) One or more ethoxylated and sulfated alcohols, more preferably one or more possessing the formula of

R.paren open-st.OCH.sub.2 CH.sub.2 .paren close-st..sub.n OSO.sub.3 M where n is 1-5, M is an ammonium-containing or alkali metal cation, more preferably NH.sub.4 or Na, and R is linear C.sub.12-14, linear C.sub.12-15, lauryl, tridecyl, myristyl, or capryl-capryl;

(e) One or more ethoxylated and sulfated phenols, more preferably one or more possessing the formula of

R.paren open-st.C.sub.6 H.sub.4 .paren close-st..paren open-st.OCH.sub.2 CH.sub.2 .paren close-st..sub.n OSO.sub.3 M where n is 1-5, M is an ammonium-containing or alkali metal cation, more preferably Na or NH.sub.4, and R is nonyl, octyl, or decyl;

(f) One or more alcohol ethoxylates, more preferably one or more of the formula

R.paren open-st.OCH.sub.2 CH.sub.2 .paren close-st..sub.n OH where R is selected from the group consisting of the linear and branch alkyl groups of C.sub.6, C.sub.8, C.sub.9-11, C.sub.10, C.sub.10-12, C.sub.12, C.sub.12-14, C.sub.14, C.sub.12-15, C.sub.16, and C.sub.18, or isosteryl, lauryl, cetyl, stearyl, oleyl, tridecyl, tallow, trimethylnonyl, or isodecyl and n is 2 to 100;

(g) One or more amine oxides, more preferably amine oxides possessing the formula of ##STR4## where R is cetyl, lauryl, myristyl, stearyl, coco, hydrogenated tallow, hexadecyl, tallow, octadecyl, decyl, C.sub.8-10, oxypropyl, C.sub.9-11 oxypropyl, or C.sub.12-15 oxypropyl and R' is CH.sub.3 or CH.sub.2 CH.sub.2 OH and may be the same or different;

(h) One or more alkyl betaines, more preferably possessing the formula of ##STR5## where R is coco, decyl, cetyl, lauryl, or oleyl;

(i) One or more amido propylbetaines, more preferably amido propylbetaines possessing the formula of ##STR6## where R is cocyl, lauroyl, isostearoyl, myristoyl, palmitoyl, and most preferably R is cocyl; or

(j) One or more fluorochemical surfactants, more preferably a fluoroprotein or a fluoroaliphatic surfactant.

When the foam is to be exposed to a temperature greater than 200.degree. F. and particularly greater than 300.degree. F., the preferred foaming agent is comprised of one or more amidopropylbetaines and more preferably comprised of one or more amidopropylbetaines and one or more ethoxylated, sulfated alcohols or one or more aliphatic or alkyl aryl hydrocarbon sulfonates of formula

R--SO.sub.3 M wherein R is an oleophilic group having from 10 to 18 carbon atoms and M is an alkali metal or ammonium cation. The most preferred foaming agent is comprised of cocoamidopropyl betaine and a sulfated ethylene glycol ether, the active ingredients is Homco SF-1009. The preferred concentrations for the preceeding two component forming agent systems are about 0.0025 to about 2.0 wt % for each component based upon the weight of water, corrosion inhibitor and foaming agent in the liquid phase. More preferred are concentrations for each component of about 0.01 to about 2.0 wt %. Still more preferred are concentrations for each component of about 0.05 to about 0.15 wt %. Most preferred are concentrations for each component of about 0.08 wt %.

Foam is generally prepared using surface facilities wherein the gas which will become the dispersed phase and the liquid which will become the continuous phase are combined in a turbulent manner. Generally, this step is conducted by combining the gas and liquid components under turbulent conditions at a "mixing T". A second method of foam generation is to separately flow the liquid and gas down the wellbore using separate confining means and to then combine the gas and liquid downhole thereby creating foam in the wellbore. The confining means are those readily available to one skilled in the art and include wellbore tubing, drillsteam, the annular space between the tubing or drillstream and the wall or well casing, and parasitic tubing. In a third method, the foam is generated in the wellbore by the cocurrent flow of gas and liquid down and back up the wellbore. A good foam will generally have the consistency of shaving cream.

In the preferred method, the foam is generated at the surface by intimately mixing the gas and liquid thereby forming foam and injecting the foam into either the tubular or annular space in the wellbore. The wellbore fluid is produced via the non-injected tubular or annular space. Foam velocity is dependent upon the type of wellbore operation being performed and the designation of said operating conditions is readily within the capabilities of one possessing ordinary skill in the art.

EXAMPLES

Control Test Series #1

These laboratory screening tests indicated that two commercially available corrosion inhibitors identified for possible use in air/foam wellbore operations are ineffective at the conditions herein studied. These tests employed air as the gas phase and a process temperature of 120.degree. F. Corrosivity was observed to increase as the concentration of inhibitor or foamer (i.e., foaming agent) increased.

Unless otherwise noted, the test were conducted using the Wheel Test Method as detailed in NACE Publication 1D182. The test solutions were prepared from 2% potassium chloride field brine, a designated foaming agent, air, and one of two designated and commercially available corrosion inhibitors. The test vessels were constructed of Hastelloy C Steel and each vessel contained two 21/2 inch.times.1/2 inch carbon steel coupons. The coupons were accurately weighed prior to the test. Each vessel possessing a volume of approximately 45 ml was charged with 30 ml of total fluid consisting of 2% KCl brine and a designated amount of chemical. The vapor space above the liquid in each vessel was purged with air and the vessel subsequently pressurized with air to a pressure of 3 psig. The test vessels were then attached to the wheel and rotated for a period of one day at a test temperature of 120.degree. F.

Each test vessel was then cooled to ambient temperature, the pressure released, and the vessel opened. The test coupons were retrieved and first cleaned using a corrosion-inhibited acid wash. The coupons were further cleaned by contacting with a steel wool pad to remove residual corrosion by-products. The coupons were then weighed and based on the difference between initial and final coupon weights, the corrosion rate was calculated. The reported corrosion rate in mils per year is an averaged rate based on the two test coupons used in each test.

As shown in Table I, Inhibitors A and B and the Foamer which are marketed commercially as Homco MC-21, Homco MC-117 and Homco SF-1009 respectively, failed to inhibit oxygen corrosion at the test conditions. The active components for some of these inhibitors and their respective sources are identified in Table X. The former two chemicals are routinely used in the field as corrosion inhibitors and the latter chemical is used in the field as a foaming agent. For each of these chemicals, the corrosion rate was observed to increase with increasing chemical composition and the corrosion rates were greater than the observed rate without chemical. All test coupons showed some pitting.

TABLE I__________________________________________________________________________Wheel Test Results at 120.degree. F. for Two Commercial Inhibitors.sup.a Inhibitor.sup.1 Inhibitor.sup.2Run A B Foamer.sup.3 Air Temperature Time Corrosion RateNo. (wt \%) (wt \%) (wt \%) (psig) (.degree.F.) (hrs.) (mph)__________________________________________________________________________1 0 0 0 0 68 24 17.42 0 0 0 3 120 24 51.23 0.01 0 0 3 120 24 53.24 0.03 0 0 120 24 54.65 0.05 0 0 3 120 24 56.46 0 0.01 0 3 120 24 53.37 0 0.03 0 3 120 24 55.7.sup.b8 0 0.05 0 3 120 24 58.6.sup.b9 0 90 0.01 3 120 24 55.210 0 0 0.03 3 120 24 53.011 0 0 0.05 3 120 24 70.7__________________________________________________________________________ .sup.a 30 ml of total fluid used in each test. System volume of approximately 45 ml. Fluid consisted of 2% KCl brine plus additives. Vapo spaces purged with air and then pressurized to 3 psig, except for Test No 1. .sup.b All coupons showed some pitting but pitting for these was quite severe. .sup.1 Homco MC21 .sup.2 Homco MC117 .sup.3 Homco SF1009 Control Test Series #2

These control tests demonstrate the complexity of formulating a foam which possesses corrosion inhibition properties. These control tests specifically examine the unique interactions between Inhibitor A (Homco MC-21), Inhibitor C (Homco AC-105-C) and Foamer (Homco SF-1009). The active components for some of these inhibitors and their respective sources are identified in Table X.

The tests were conducted using the general procedure described for Control Test Series #1. The observed corrosion rate for Run #4 which contained the two corrosion inhibitors and the foamer at designated concentrations was 4.77 mpy. However, when the concentration of Inhibitors A and C and the foamer were increased 21/2-fold and 5-fold as in Runs #5 and #6, the corrosion rates were respectively increased by at least 3-fold and 7-fold. When the respective chemical compositions were reduced by 50% from that of Run #4, the corrosion rates increased by nearly 15-fold. This latter corrosion rate was similar to that obtained during Runs #1 and #2 wherein the samples did not contain Inhibitor C but did contain the other two chemicals. These results are presented in Table II.

TABLE II__________________________________________________________________________Wheel Test Results at 120.degree. F. for Identified CommercialInhibitors.sup.aControl Inhibitor.sup.1 Inhibitor.sup.2Test A C Foamer.sup.3 Air Temperature Time Corrosion RateNo. (wt \%) (wt \%) (wt \%) (psig) (.degree.F.) (hrs.) (mph)__________________________________________________________________________1 0.10 0 0.25 2.5 120 24 65.7.sup.b2 0.10 0 0.25 2.5 120 24 67.9.sup.b3 0.01.01 0.025 2.5 120 24 67.0.sup.b4 0.02 0.02 0.050 2.5 120 24 4.775 0.05 0.05 0.125 2.5 120 24 15.68.sup.c6 0.10 0.10 0.250 2.5 120 24 36.1.sup.c__________________________________________________________________________ .sup.a 180 ml of total fluid used in each test consisting of 10 vol % kerosene and 90 vol % of 2% KCl solution to which was added the identifie concentrations of chemicals. Total system volume was approximately 215 ml .sup.b Pitting .sup.c Slight Pitting .sup.1 Homco MC21 .sup.2 Homco AC105-C .sup.3 Homco SF1009 Control Test Series #3

The test results for Control Test Series #3 were obtained using the Corrator.RTM. test method. The results are consistent with the observations reported for Control Test #2. Below and above an apparently narrow concentration range, the inhibitors at 120.degree. F. were found to be ineffective.

The tests were carried out in a 1-liter Erlenmeyer flasks equipped with magnetic stirring bars under laboratory conditions designed to simulate the corrosive oil-water environment frequently encountered in field operation. The rate of corrosion and the relative effectiveness of the treatment process was determined using a Corrator.RTM. monitoring system (Rohrback Instruments). Each test consisted of fastening two one-inch long carbon-steel electrodes to a probe and suspending the probe in a stirred inhibitor/foamer bearing solutions of the composition provided in Table III. The process temperature was 120.degree. F.

Consistent with the observations for Control Test Series #2, Run #2 containing 0.02 wt % Inhibitor A (Homco MC-21), 0.02 wt % Inhibitor C (Homco AC-105-C) and 0.05 wt % Foamer (Homco SF-1009) produced the lowest observed corrosion rate. Test results for Runs #1 presented in Table III for Control Test Series #3 are similar to the results for Runs #1 and #2 and for Run #6 presented in Table II for Control Test Series #2. The active components for some of the identified inhibitors and their respective sources are provided in Table X.

TABLE III______________________________________Results for Corrosion Test Series #3 Conducted at120.degree. F. Using Corrator Test Method.sup.a Inhibitor.sup.1 Inhibitor.sup.2 Temper- Corrosion RateRun A C Foamer.sup.3 ature (mpy)No. (wt %) (wt %) (wt %) (.degree.F.) Average Final______________________________________1 0.10 0 0.25 120 47.3 51.12 0.02 0.02 0.05 120 6.9 1.73 0.10 0.10 0.25 120 23.9 20.0______________________________________ .sup.a Test fluids were 900 ml 2% KCl field brine, 100 ml Kerosene and th designated weight percentage of additives. Fluids were air saturated at ambient pressure. Tests lasted 24 hours. .sup.1 Homco MC21 .sup.2 Homco AC105-C .sup.3 Homco SF1009 Control Test Series #4

Run Numbers 1-24 in Control Test Series #4 established Inhibitor D (Amtech MC-1) to be ineffective as a corrosion inhibitor at the conditions studied. Runs 25-42 wherein Inhibitor E (Amtech B-1) was used demonstrated relatively low corrosion rates at the test conditions. The inhibitors may be obtained from the source identified in Table X.

All tests were conducted at 120.degree. F. using the procedures previously presented in Control Test Series #1. Test results for this test series are presented in Table IV.

TABLE IV__________________________________________________________________________Wheel Test Results at 120.degree. F. for Identified CommercialInhibitors.sup.a Inhibitor.sup.1 Inhibitor.sup.2Run A D Foamer.sup.3 Air Temperature Time Corrosion RateNo. (wt %) (wt %) (wt %) (psig) (.degree.F.) (hrs.) (mph)__________________________________________________________________________2 0 0 0 2.4 120 24 76.8.sup.b3 0 0 0 2.4 120 24 83.5.sup.b4 0 0 0 2.4 120 24 75.35 0 0 0 2.4 120 24 78.36 0.10 0 0.25 2.4 120 24 74.47 0 0.10 0.20 2.5 120 24 61.58 0.10 0.10 0.20 2.5 120 24 61.79 0.15 0.10 0.20 2.5 120 24 58.310 0 0.10 0.25 2.5 120 24 59.611 0.10 0.10 0.25 2.5 120 24 59.012 0.15 0.10 0.25 2.5 120 24 62.513 0 0.15 0.20 2.5 120 24 58.814 0.10 0.15 0.20 2.5 120 24 57.915 0.15 0.15 0.20 2.5 120 24 53.916 0 0.15 0.25 2.5 120 24 53.617 0.10 0.15 0.25 2.5 120 24 55.018 0.15 0.15 0.25 2.5 120 24 51.819 0 0.20 0.20 2.5 120 24 50.420 0.10 0.20 0.20 2.5 120 24 50.821 0.15 0.20 0.20 2.5 120 24 50.222 0 0.20 0.25 2.5 120 24 52.223- 23 0.10 0.20 0.25 2.5 120 24 50.824 0.15 0.20 0.25 2.5 120 24 49.925 0 0.10 0.20 2.5 120 24 4.9926 0.10 0.10 0.20 2.5 120 24 5.3627 0.15 0.10 0.20 2.5 120 24 5.0628 0 0.10 0.25 2.5 120 24 4.9529 0.10 0 0.25 2.5 120 24 5.8830 0.15 0.10 0.25 2.5 120 24 4.8231 0 0.15 0.20 2.5 120 24 4.8632 0.10 0.15 0.20 2.5 120 24 4.9533 0.15 0.15 0.20 2.5 120 24 4.2934 0 0.15 0.25 2.5 120 24 3.8635 0.10 0.15 0.25 2.5 120 24 4.6736 0.15 0.15 0.25 2.5 120 24 4.5037 0 0.20 0.20 2.5 120 24 5.0238 0.10 0.20 0.20 2.5 120 24 4.5939 0.15 0.20 0.20 2.5 120 24 5.0940 0 0.20 0.25 2.5 120 24 5.0141 0.10 0.20 0.25 2.5 120 24 4.5542 0.15 0.20 0.25 2.5 120 24 4.33__________________________________________________________________________ .sup.a Test liquid for each test was 135 ml of 2% KCl brine and 15 ml kerosene to which was added the identified inhibitors and foamer. Total system volume was approximately 215 ml. .sup.b Severe pitting observed. .sup.1 Homco MC21 .sup.2 Amtech MC1 .sup.3 Homco SF1009 .sup.4 Amtech B1 Control Test Series #5

Control Test Series #5 provides comparative data regarding the applicability of Inhibitor D (Amtech MC-1), Inhibitor E (Amtech B-1) and Inhibitor F (Baker Cronox C-617) as corrosion inhibitors at 120.degree. F. The test results indicated Inhibitor F (Run 15) to be superior to Inhibitor E (Runs 9-14) which is markedly superior to Inhibitor D (Runs 1-8). The results for the latter comparison are consistent with those reported for Control Series #4. The active components in some of these inhibitors and their respective sources are identified in Table X.

Test conditions and results are presented in Table V. All tests were conducted at 120.degree. F. using the Wheel Test procedures previously presented in Control Test Series #1.

Based on the corrosion inhibition results for Control Test Series #1 through #5 wherein 6 commercially available corrosion inhibitors were evaluated, the preferred corrosion inhibitor among the six tested at these test conditions is Inhibitor F.

TABLE V__________________________________________________________________________Wheel Test Results at 120.degree. F. for Identified CommercialInhibitors.sup.a Inhibitor.sup.1Test A Foamer.sup.3 Air Temperature Time Corrosion RateNo. (wt %) (wt %) (wt %) (psig) (.degree.F.) (hrs.) (mph)__________________________________________________________________________ Inhibitor.sup.2 D1 0 0 0 2.5 120 24 216.52 0.10 0 0.25 2.5 120 24 216.53 0 0.10 0.20 2.5 120 24 181.7.sup.b4 0.10 0.10 0.20 2.5 120 24 149.3.sup.b5 0.15 0.10 0.20 2.5 120 24 125.3.sup.b6 0 0.10 0.25 2.5 120 24 192.5.sup.b7 0.10 0.10 0.25 2.5 120 24 192.68 0.20 0.10 0.20.25 2.5 120 24 177.6 Inhibitor.sup.4 E9 0 0.10 0.20 2.5 120 24 8.88.sup.c10 0.10 0.10 0.20 2.5 120 24 10.2.sup.c11 0.15 0.10 0.20 2.5 120 24 10.4.sup.c12 0 0.10 0.25 2.5 120 24 9.25.sup.c13 10 0.10 0.25 2.5 120 24 9.78.sup.c14 0.15 0.10 0.25 2.5 120 24 9.49 Inhibitor.sup.5 F15 0.10 0.10.sup.5 0.25 2.5 120 24 5.49__________________________________________________________________________ .sup.a Test liquid was 135 ml of 2% KCl brine and 15 ml kerosene to which was added the identified inhibitors and foamer. Total system volume of approximately 215 ml. .sup.b Severe pitting .sup.c Some pitting .sup.1 Homco MC21 .sup.2 Amtech MC1 .sup.3 Homco SF1009 .sup.4 Amtech B1 (See Footnote 5) .sup.5 Inhibitor F, Baker Cronox C617 Test Series #1

This test series with the exception of one run was conducted at 200.degree. F. and conclusively establishes that potassium hydroxide and phenol in combination is superior to the best corrosion inhibitor identified in Control Test Series #1 through #5, that corrosion inhibitor being Inhibitor F (Baker Cronox C-617). The test series also establishes the effectiveness of the potassium hydroxide/phenol corrosion inhibitor at phenol to oxygen molar ratios in the test apparatus of significantly less than 1.0.

Test procedures were similar to those presented for Control Test Series #1. Chemical concentrations, tests conditions and results are presented in Table VI for Inhibitor F (Runs 4-6) and the inventive corrosion inhibitor (Runs 7-12). Whereas Inhibitor F demonstrates unacceptable performance at 200.degree. F. and 10 and 100 psig pressure (corrosion rates of 23.0 and 43.4 mpy, respectively), the corrosion rates for the inventive formulation are approximately an order of magnitude less (2.71 and 2.73 mpy, respectively). Whereas the corrosion rates for Inhibition F at concentrations similar to the inventive inhibitor were found to be a function of air pressure, such a dependence was not observed for the inventive inhibitor. As noted, the inventive inhibitor was effective at phenol to oxygen molar ratios in the systems of significantly less than 1.

TABLE VI__________________________________________________________________________Wheel Test Results at 120.degree. F. and 200.degree. F. for Inhibitor Fand Inventive Corrosion Inhibitor FormulationTest.sup.a Inhibitor F.sup.1 KOH Phenol Foamer.sup.2 Air Pressure Temperature Test Time Corrosion RateNo. (wt \%) (wt \%) (wt \%) (wt \%) (psig) (.degree.F.) (hrs.) (mpy)__________________________________________________________________________1 0 0 0 0 2.5 120 24 216.5.sup.b2 0 0 0 50 200 48 34.0.sup.b3 0 0 0 0 200 200 48 102.1.sup.b4 0.1 0 0 0.25 2.5 120 24 5.495 0.15 0 0 0.20 10.0 200 48 23.06 0.15 0 0 0.20 100.0 200 48 43.4.sup.b7 0 5 0.15 0 10 200 48 5.768 0 10 0.15 0 10 200 48 2.789 0 10 0.15 0.20 10 200 48 2.7110 0 10 0.15 0.20 50 200 48 2.8211 0 10 0.15 0.20 100 200 48 2.7312.sup.c 0 10 0.15 0.20 200 200 48 2.19__________________________________________________________________________ .sup.a Test liquid was 80 ml of 2% KCl brine to which was added the above specified chemicals, inhibitors and foamer. Total system volume was approximately 120 ml. .sup.b Pittings .sup.c Mole ratio of phenol to oxygen in test apparatus was 0.148. .sup.1 Baker Cronox C617 .sup.2 Homco SF1009 Test Series #2

This test series further illustrates the outstanding corrosion inhibition properties possessed by NaOH/phenol and KOH/phenol in highly oxidative environments (air, water and carbon steel coupon at 350.degree. F. and 7 psig).

Test results and conditions are presented in Tables VII and VIII. Test procedures were similar to those described for Control Test Series #1.

Test results for Inhibitor F which was shown in Control Test Series #5, Run #15, to be the most promising of the commercial inhibitors tested are presented in Table VII. The test results confirm at a higher temperature the results presented in Test Series #1. These results indicated Inhibitor F to be ineffective as a corrosion inhibitor at elevated temperatures.

Results presented in Table VIII for Test #1 and #2 clearly demonstrate that corrosion rates are unacceptable in the studied system in the absence of a corrosion inhibitor. Test results for Test #3 and #4 show that the foaming agent used in these studies fails to provide corrosion inhibition. The results obtained in Test #5 show that phenol by itself at 0.30 wt % provides little if any corrosion inhibition. Test Numbers 6-7 and 8-9 respectively show that the addition of either NaOH or KOH to the studied systems results in significant corrosion inhibition. Of the two, KOH appears to provide better corrosion inhibition performance at a given weight percentage. The combination of either NaOH or KOH with phenol unexpectedly enhanced corrosion inhibition as evidenced by the results for Test Numbers 10-15 over that observed for the individual alkali metal hydroxides. The degree of corrosion inhibition for the NaOH/phenol system (Run #10-11) and the KOH/phenol systems (Run #12-14) were similar.

Test results obtained for Runs #17-20 wherein KOH and phenol was used for corrosion inhibition at 350.degree. F. further show the excellent inhibition properties of these chemicals when used in combination at greater air pressures. The greater air pressure correspond to greater partial pressures of the oxygen oxidizing agent.

TABLE VII__________________________________________________________________________Wheel Test Results at 300.degree. F. for Commercial Inhibitor FTest.sup.a Inhibitor F.sup.1 Foamer.sup.2 Air Temperature Time Corrosion RateNo. (wt %) (wt %) (psig) (.degree.F.) (hrs.) (mpy)__________________________________________________________________________1 50 1 7 320 24 33.4.sup.b2 1 1 7 320 24 26.7.sup.b__________________________________________________________________________ .sup.a Test liquid was 80 ml of 2% KCl field brine containing above designated components at designated weight percentages. Total system volume was 120 ml. .sup.b Pitting .sup.1 Baker Cronox C617 .sup.2 Homco SF1009 TABLE VIII__________________________________________________________________________Wheel Test Results at 300.degree. F. and 350.degree. F.Test.sup.a NaOH KOH Phenol Foamer.sup.1 Air Temperature Time Corrosion RateNo. (wt %) (wtt \%) (wt \%) (wt \%) (psig) (.degree.F.) (hrs.) (mpy)__________________________________________________________________________1 0 0 0 0 5 300 48 11.5.sup.b2 0 0 0 0 5 350 55 11.6.sup.b3 0 0 0 0.2 5 300 48 13.5.sup.b4 0 0 02 10 350 55 16.45 0 0 0.30 0.2 5 350 55 14.2.sup.b6 5 0 0 0.2 5 350 55 4.067 10 0 0 0.2 5 350 55 6.318 0 5 0 0.2 5 350 55 3.709 0 10 0 0.2 5 350 55 3.9810 5 0 0.15 0.2 5 350 55 3.1111 10 0 0.30 0.2 5 350 55 2.4212 0 5 0.15 0.2 5 350 55 2.4413 0 10 0.30 0.2 5 350 55 2.9514 0 10 0.30 0.2 5 350 55 1.9015 0 1 0.30 0.2 5 350 55 3.42.sup.b16 0 1 0.05 0.2 10 350 55 4.27.sup.b17 0 5 0.05 0.2 10 350 55 3.1318 0 10 0.05 0.2 10 350 55 3.3219 0 1 0.10 0.2 10 350 55 3.0620 0 10 0.10 0.2 10 350 55 3.43__________________________________________________________________________ .sup.a Test liquid was 80 ml of 2% KCl to which the designated components were added in the designated weight percentages. .sup.b Pitting .sup.1 Homco SF1009 Test Series #3

This series of tests further illustrate the beneficial corrosion inhibition imparted by a phenolic compound, phenol, when added to a brine solution containing a hydroxide-bearing compound capable of imparting a pH of at least 9 to a base aqueous fluid, KOH, or NH.sub.4 OH and/or a foaming agent. For every combination, the addition of phenol was found to reduce the corrosion rate (i.e., improve corrosion inhibition).

Test results and conditions are presented in Table IX. Test procedures were analogous to those reported for Control Test Series #1. The tests were conducted by exposing the air/brine/coupon system to a temperature of 350.degree. F. for 42.5 hrs. Test Numbers 1-5 concern corrosion inhibition in an air/brine system containing KOH (Run #1), an air/brine system containing KOH and Foamer (Run #2), an air/brine system containing KOH and phenol (Run #3), an air/brine system containing KOH, foamer and phenol (Runs #4 and #5). Test Numbers 6-10 similarly concern corrosion inhibition in an air/brine system containing NH.sub.4 OH (Run #6), an air/brine system containing NH.sub.4 OH and foamer (Run #7), an air/brine system containing NH.sub.4 OH and phenol (Run #8), an air/brine system containing NH.sub.4 OH, foamer, and phenol (Runs #9 and #10). The results for Runs #4 and #5 and for Runs #9 and #10 additionally and surprisingly show a reduction in corrosion rates when the phenol concentration is reduced from 0.3 wt. % to 0.15 wt. %. As previously noted, the addition of phenol to the fluid system in all tests resulted in a reduction in corrosion rate. The magnitude of the reduction was generally greater for solutions containing KOH rather than NH.sub.4 OH. The corrosion rates for comparable systems were generally lower for those systems containing NH.sub.4 OH than for KOH.

TABLE IX______________________________________Wheel Test Results at 350.degree. F.Test KOH NH.sub.4 OH Phenol Foamer.sup.c Corrosion RateNo..sup.a,b (wt %) (wt %) (wt %) (wt %) (mpy)______________________________________1 1 10 0 0 0 7.432 10 0 0 0.2 7.043 10 0 0.3 0 3.324 10 0 0.3 0.2 3.205 10 0 0.15 0.2 3.016 0 10 0 0 4.247 0 10 0 0.2 3.388 0 10 0.3 0 2.819 0 10 0.3 0.2 2.5710 10 0.15 0.2 2.32______________________________________ .sup.a 80 ml of total fluid used in each test. Fluids for Test Numbers 1- were prepared from 80 ml of 2% KCl brine to which KOH, phenol and foamer were added in the designated perecentages. Fluids for Test Numbers 6-10 were prepared from 65 ml of 2% KCl brine and 15 ml of 60 wt % NH.sub.4 OH to which phenol and foamer were added in the designated percentages. Tota system volume was 120 ml. .sup.b Test conditions were 350.degree. F. and 7.6 psig for 42.5 hrs. Overburden gas was air. .sup.c Foamer was Homco SF1009 TABLE X______________________________________Commercial InhibitorsInhibitor Tradename Active Components.sup.1______________________________________A Homco MC-21.sup.2 Amine, methanolB Homco MC-117.sup.2 Ethylene glycolC Homco AC-105-C.sup.2 MethanolD Amtech MC-1.sup.3 Ethylene glycol, methanolE Amtech B-1.sup.3 Ethylene glycolF Baker Cronox C-617.sup.4 Phosphonate, 2-butoxyethanol______________________________________ .sup.1 Components disclosed on Material Safety Data Sheet. Other active components may be present but were not disclosed. .sup.2 Homco International, Inc., P.O. Box 26292, 6021 Camille Avenue, Oklahoma City, OK, 72129 .sup.3 Amtech Corp., 2221 S. Eastern, Oklahoma City, OK, 73129 .sup.4 Baker Performance Chemicals, Inc., 3920 Esses Lane, Houston, TX

Claims

1. In a process for drilling a wellbore or conducting workover, completion or production operations in a wellbore wherein aerated liquid comprised of a gas phase dispersed in a continuous water-based liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said liquid phase of a corrosion inhibitor comprising at least one hydroxide-bearing compound in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least one phenolic compound.

2. A drilling, completion, workover or production process comprising

mixing in the wellbore at a predetermined depth a gas and a liquid comprised of (a) water in a major portion, and a (b) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound thereby forming a corrosion-inhibited aerated liquid.

3. In a process for drilling a wellbore or conducting workover or completions operations in a wellbore wherein foam comprised of a dispersed gas phase in a continuous liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said foam of a corrosion inhibitor comprising at least one hydroxide-bearing compound in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least two phenolic compound.

4. A drilling, completion or workover process comprising the steps of:

(a) intimately mixing a gas and a liquid comprised of (1) water in a major portion, (2) a foaming agent in amounts effective for a 60 to 99.75% quality foam, and a (3) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound thereby forming a foam; and

(b) injecting said foam into either a tubular or annular space in a wellbore thereby producing said wellbore fluids via the non-injection tubular or annular space.

5. In a process for drilling a wellbore or conducting workover, completion or production operations in a wellbore wherein aerated liquid comprised of a gas phase dispersed in a continuous water-based liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said liquid phase of a corrosion inhibitor comprising at least one hydroxide-bearing compound in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least one phenolic compound of the formula ##STR7## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO.sub.2, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

6. In a process for drilling a wellbore or conducting workover, completion or production operations in a wellbore wherein aerated liquid comprised of a gas phase dispersed in a continuous water-based liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said liquid phase of a corrosion inhibitor comprising at least one hydroxide-bearing compound wherein said hydroxide-bearing compound is an alkali metal hydroxide or ammonium hydroxide in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least one phenolic compound of the formula ##STR8## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

7. A process according to claim 6 wherein said alkali metal hydroxide is sodium hydroxide or potassium hydroxide.

8. A process according to claim 7 wherein said phenolic compound is phenol, o-cresol, o-fluorophenol, o-chlorophenol, o-bromophenol, o-iodophenol, o-nitrophenol, catechol, resorcinol, guaiacol, hydroquinone, salicylaldehyde or o-allylphenol or the salts thereof.

9. The process according to claim 7 wherein said phenolic compound is phenol, cresol, salicylaldehyde, or o-nitrophenol or the ammonium, potassium or sodium salts thereof.

10. A process according to claim 9 wherein said phenolic is phenol or sodium or potassium salts thereof and said hydroxide-bearing compound is sodium hydroxide or potassium hydroxide.

11. A process according to claim 10 wherein said gas phase is comprised in major portion of air.

12. A process according to claim 11 wherein the molar ratio of the phenol to the oxidizing agent in the aerated liquid is significantly less than one.

13. A process according to claim 9 wherein said gas phase is comprised in major portion of air.

14. A process according to claim 6 wherein said gas phase is comprised in major portion of air.

15. A drilling, completion, workover or production process comprising mixing in the wellbore at a predetermined depth a gas and a liquid comprised of (a) water in a major portion, and a (b) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound wherein said hydroxide-bearing compound is an alkali metal hydroxide or ammonium hydroxide in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound of the formula ##STR9## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

16. A drilling, completion, workover or production process comprising mixing in the wellbore at a predetermined depth a gas and a liquid comprised of (a) water in a major portion, and a (b) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound wherein said hydroxide-bearing compound is an alkali metal hydroxide or ammonium hydroxide in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound of the formula ##STR10## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

17. A process according to claim 16 wherein said alkali metal hydroxide is sodium hydroxide or potassium hydroxide.

18. The process according to claim 17 wherein said phenolic compound is phenol, cresol, o-fluorophenol, o-chlorophenol, o-bromophenol, o-iodophenol, o-nitrophenol, catechol, resorcinol, guaiacol, hydroquinone, salicylaldehyde or o-allylphenol or the salts thereof.

19. A process according to claim 17 wherein said phenolic compound is phenol, cresol, salicylaldehyde or o-nitrophenol or the ammonium, potassium or sodium salts thereof.

20. The process according to claim 19, wherein said phenolic compound is phenol or the sodium or potassium salts thereof and said hydroxide-bearing compound is sodium hydroxide or potassium hydroxide.

21. A process according to claim 20 wherein said gas is comprised in major portion of air.

22. A process according to claim 21 wherein the molar ratio of the phenolic compound to the oxidizing agent in the aerated liquid is significantly less than one.

23. A process according to claim 19 wherein said gas is comprised in major portion of air.

24. A process according to claim 16 wherein said gas is comprised in major portion of air.

25. In a process for drilling a wellbore or conducting workover or completions operations in a wellbore wherein foam comprised of a dispersed gas phase in a continuous liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said foam of a corrosion inhibitor comprising at least one hydroxide-bearing compound in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least one phenolic compound of the formula ##STR11## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

26. In a process for drilling a wellbore or conducting workover or completions operations in a wellbore wherein foam comprised of a dispersed gas phase in a continuous liquid phase is employed as the principle wellbore fluid, the improvement comprises the inclusion in said foam of a corrosion inhibitor comprising at least one hydroxide-bearing compound wherein said hydroxide-bearing compound is an alkali metal hydroxide or ammonium hydroxide in concentrations sufficient to impart a pH of at least 9 to said liquid phase and an effective amount of at least one phenolic compound of the formula ##STR12## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible.

27. A process according to claim 26 wherein said alkali metal hydroxide is sodium hydroxide or potassium hydroxide.

28. A process according to claim 27 wherein said phenolic compound is phenol, o-cresol, o-fluorophenol, o-chlorophenol, o-bromophenol, o-iodophenol, o-nitrophenol, catechol, resorcinol, guaiacol, hydroquinone, salicylaldehyde or o-allylphenol or salts thereof.

29. The process according to claim 27 wherein said phenolic compound is phenol, cresol, salicylaldehyde, or o-nitrophenol or the ammonium, potassium or sodium salts thereof.

30. A process according to claim 29 wherein said phenolic compound is phenol or the sodium or potassium salt thereof and said hydroxide-bearing compound is sodium hydroxide or potassium hydroxide.

31. A process according to claim 30 wherein said foaming agent is comprised of at least one amidopropylbetaine.

32. The process according to claim 31 wherein said foaming agent is additionally comprised of one or more aliphatic or alkyl aryl hydrocarbon sulfonates of formula

R--SO.sub.3 M

wherein R is an oleophilic group having from 10 to 18 carbon atoms and M is an alkali metal or ammonium cation.

33. A process according to claim 31 wherein said foaming agent is comprised of cocoamidopropylbetaine and at least one ethoxylated and sulfated alcohol.

34. A process according to claim 33 wherein said gas is comprised in major portion of air and said foam upon injecting is exposed to a temperature of at least 350.degree. F.

35. A process according to claim 34 wherein the molar ratio of the phenolic compound to the oxidizing agent is significantly less than one.

36. A process according to claim 30 wherein said gas phase is comprised in major portion of air.

37. A process according to claim 36 wherein the molar ratio of the phenolic compound to the oxidizing agent in the foam is significantly less than one.

38. A process according to claim 29 wherein said gas phase is comprised in major portion of air.

39. A process according to claim 26 wherein said gas phase is comprised in major portion of air.

40. A drilling, completion or workover process comprising the steps of:

(a) intimately mixing a gas and a liquid composed of (1) water in a major portion, (2) a foaming agent in amounts effective for a 60 to 99.75% quality foam, and a (3) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound is an alkali metal hydroxide or ammonium hydroxide in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound of the formula ##STR13## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible thereby forming a foam; and

(b) injecting said foam into either a tubular or annular space in a wellbore thereby producing said wellbore fluids via the non-injection tubular or annular space.

41. A process according to claim 40 wherein said alkali metal hydroxide is sodium hydroxide or potassium hydroxide.

42. The process according to claim 41 wherein said phenolic compound is phenol, cresol, o-fluorophenol, o-chlorophenol, o-bromophenol, o-iodophenol, o-nitrophenol, catechol, resorcinol, guaiacol, hydroquinone, salicylaldehyde or o-allylphenol or the salts thereof.

43. A process according to claim 42 wherein said hydroxy aromatic compound is phenol, cresol, salicylaldehyde or o-nitrophenol or the ammonium, potassium or sodium salts thereof.

44. The process according to claim 43 wherein said hydroxy-bearing compound is phenol or the sodium or potassium salts thereof and said hydroxide-bearing compound is sodium hydroxide or potassium hydroxide.

45. The process according to claim 30 wherein said foaming agent is comprised of at least one N-acrylsaracosinate, sodium N-acryl-N-alkyltaurate, alkyl sulfate, ethoxylated and sulfated alcohol, ethoxylated and sulfated alkylphenol, fatty acid diethanolamide, amine oxide, alkyl betaine, or amidopropylbetaine.

46. A process according to claim 44 wherein said foaming agent is comprised of at least one amidopropylbetaine.

47. A process according to claim 46 wherein said foaming agent is comprised of at least one amidopropylbetaine is cocoamidopropylbetaine and at least one ethoxylated and sulfated alcohol.

48. A process according to claim 47 wherein said gas is comprised in major portion of air and said foam upon injecting is exposed to a temperature of at least 350.degree. F.

49. A process according to claim 48 wherein the molar ratio of the phenolic compound to the oxidizing agent in the foam is significantly less than one.

50. The process according to claim 46 wherein said foaming agent is additionally comprised of one or more aliphatic or alkyl aryl hydrocarbon sulfonates of formula

R--SO.sub.3 M

wherein R is an oleophilic group having from 10 to 18 carbon atoms and M is an alkali metal or ammonium cation.

51. A process according to claim 43 wherein said gas is comprised in major portion of air.

52. A process according to claim 51 wherein the molar ratio of the phenolic compound to the oxidizing agent in the foam is significantly less than one.

53. A process according to claim 40 wherein said gas is comprised in major portion of air.

54. A process according to claim 41 wherein said gas is comprised in major portion of air.

55. A drilling, completion or workover process comprising the steps of:

(a) intimately mixing a gas and a liquid comprised of (1) water in a major portion, (2) a foaming agent in amounts effective for a 60 to 99.75% quality foam, and a (3) corrosion inhibitor wherein said corrosion inhibitor is comprised of an effective amount of at least one hydroxide-bearing compound in concentrations sufficient to impart and maintain a pH of at least 9 to said liquid and at least one an effective amount of at least one phenolic compound of the formula ##STR14## wherein R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are independently selected from the group consisting of hydroxyl groups, alkoxy groups containing from 1 to 6 carbon atoms; alkyl groups containing from 1 to 6 carbon atoms, a phenyl group, NO, COOH, COH, sulfonic acids, ketones containing from 1 to 6 carbon atoms, F, Cl, Br, I, hydrogen, or the salts of any of the preceding acids or alcohol, wherein at least two of the above R groups are hydrogen; or phenolic mixtures thereof, and the resulting compound is water soluble or dispersible thereby forming a foam; and

(b) injecting said foam into either a tubular or annular space in a wellbore thereby producing said wellbore fluids via the non-injection tubular or annular space.

56. A process according to claim 55 wherein said foaming agent comprised of at least one amidopropylbetaine.

57. The process according to claim 56 wherein said foaming agent is additionally comprised of one or more aliphatic or alkyl aryl hydrocarbon sulfonates of formula

R--SO.sub.3 M

wherein R is an oleophilic group having from 10 to 18 carbon atoms and M is an alkali metal or ammonium cation.

58. A process according to claim 56 wherein said foaming agent of at least one amidopropylbetaine is cocoamidopropylbetaine and at least one ethoxylated and sulfated alcohol.

59. A process according to claim 55 wherein said foam is exposed to a temperature of at least about 200.degree. F.

60. A process according to claim 55 wherein said foam is exposed to a temperature of at least about 350.degree. F.

61. A process according to claim 25 wherein said foaming agent is comprised of at least one amidopropylbetaine.

62. The process according to claim 61 wherein said foaming agent is additionally comprised of one or more aliphatic or alkyl aryl hydrocarbon sulfonates of formula

R--SO.sub.3 M

wherein R is an oleophilic group having from 10 to 18 carbon atoms and M is an alkali metal or ammonium cation.

63. A process according to claim 61 wherein said foaming agent is comprised of at least one amidopropylbetaine is cocoamidopropylbetaine and at least one ethoxylated and sulfated alcohol.