OA16432A - Foamers for downhole injection. - Google Patents

Abstract

A method of foaming a fluid for recovering gas from a gas well and enhancing oil production from a gas-lifted oil well penetrating a subterranean oil-bearing formation is disclosed and claimed. The method includes introducing into the fluid a foam-forming amount of a composition comprising at least one compound selected from the following: X+ alkyl benzene sulfonate; X+ alkylnapthalene sulfonate; alkyldiphenyloxide disulfonate; dialkyldiphenyloxide disulfonate; X+ alkyl sulfate; naphthalene sulfonate formaldehyde condensate; and combinations thereof. The method of invention further provides foamers that are compatible with a reverse osmosis membrane.

Description

This invention relates generally to methods of using novel foamer compositions for treatment of oil and gas wells to enliance production. More specifically, the invention relates novel foainer compositions for treatment of oil, natural gas wells and coal seam gas (CSG), 10 specifically where the produccd water is treated by a reverse osmosis (RO) membrane.

BACKGROUND OFTHE INVENTION

As natural gas wells mature, gas production, decreases due lo a décliné in réservoir pressure. The formation fluids (i.e., water and liquid hydrocarbon condensate), which resuit from high production rates, can no longer be lifted from the well and accumulate in the well bore.

1.5 This accumulation may cause the well to flow errutically at a much lower ilow rate and cvcntually ccasc production. Foaming agents, also known as foamers, are one of the many methods available to de-water a gas well. Foaincrs can be applied either by batch treatment or continuous application. With the addition of foamer to the wellbore where the loadîng liquids are présent, foain is gcneraicd with agitation from the gas flow. The surface tension and fluid 20 density of the foam are much lower than the liquids so the lighter foain, where the bubble film holds the liquids, is more easily lifted by the low gas flow rate. In oil well production, foamers arc also used in conjonction with a gas lift system to enhancc oil recovery,

A lot of attention and effort hâve been atrracted to recover coal seam gas (CSG) for use as natural gas fuel in rccent times due to high energy demand. As a conséquence of this type of 25 production, there ts a large volume of produced water, which is commonly cleaned and purified by using reverse osmosis (RO) membrane filtration units. This enables the diverse rc-use of the water and ofièrs a sustainable production approach, espectally in countries such as Australie Where water is always in high demand. However, the membrane cleaning processes can only be applied for produced water which does not contain components blocking or fouling the 30 membrane. The treated water can be reused for applications such as agriculture and municipal purposcs. Typical foamers employed to accelerate the water unloading and maintaîn the integrity of the asset can gcnerally destroy or block the RO membranes.

Ciirrenlly available foamer technologies that are incompatible with the RO membranes include the foilowing. WO 2009/064719 discloses imidazofine-based heterocyclic foamers for 35 gas/oil well deliquitication, but such quaternary compounds are not compatible with the RO r

membranes. U.S. 2006/0128990 tcuches a method of treating a gas well applying a chloride free amphoteric surfactant. U.S Patent No 7,122,509 provïdes a method of preparing a foamer composition having un anionic surfactant and a neutralizing amine. In U,S. 2005/ 0137114, an aqueous foarning composition comprising at least one anionic surfactant, cationie surfactant and at least one zwitterionic compound is disclosed. WO 02/092963 and U.S. 2007/0079963 disclose 10 methods for recovering oil from a gas-lifted oil well using a lift gas and a foarning surfactant which consists of nonionic surfactants, anionic surfactants, betaines, and siloxanes.

While the discusscd loamers contribute signiftcantly to deliquifying solutions, there is still nced for other cost-effective foamers which could provide superior foarning performance and are membrane compatible.

SUMNiARY OF THE INVENTION

This invention accordingly provides novel foamers and applications for Systems with RO membranes without compromising performance, while offering significant production benefits. The foarning composition according to the invention is a membrane compatible composition. That means that il does not contain any components destroying or blocking (lie membranes which 20 arc used for the cleaning ofthe produced water in the gas deliquificntion process.

In an aspect, the invention is a method of foarning a fluid, for recovering gas Irom a gus well and enhancing oil production fiom a gas-lifted oil well penetrating a subterranean oilbearing formation. The method încludes introdueing into (lie fluid a foatn-forming amount of a composition comprising at least one compound selected from the following: X⁺ alkyl benzene 25 sulfonate; X⁺ alkylnuptliulene sulfonate; alkyldiphenyloxide disulfonatc; dialkyldtphenyloxidc disulfonate; X* alkyl sulfate: naphthalcne sulfonate formaldéhyde condensate; and combinations thereof; wherein alkyl is C6-C22; and wherein euch compound or combination is compatible with a reverse osmosis membrane. X* is an uïkali métal cation, preferably sodium, or an organic counterion, such as triethanol amine, dielhanol amine, monoethanol amine, and combinations 30 thereof.

It is an advanlage of the invention to provide a novel class of foamer as a RO compatible deliquitïcation solution.

It is another advantage of the invention to provide novel fbaming agents for downhole injection in oil and gas wells.

I r

It is a further advanlage of the invention to provide an efficient method of recovering oil froin a gas-lifted oil well penetrating a subterranean oil-bearing formation.

Another advantage of the invention is to provide an efficient method to retnove hydrocarboa fluids from a gas-producing well.

The foregoing has outlined rather broadly the features and technical advantages of the présent invention in order that the detailcd description of the invention that follows may be better understood. Additional features and advuntages of the invention will be described hcrcinaftcr that form the subject of the claims of the invention. It should be apprccîatcd by those skilled in the art that the conception and the spécifie embodiments disclosed may be readily utilîzed as a basis for modifylng or designing other embodiments for carryitig out the same purposes of the présent invention. It should also be reulized by those skilled in the art that such équivalent embodiments do not départ from the spirit and scope ofthe invention as set forth in the uppended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 illustrâtes the RO membrane compatibility testing results of Product 1 as explained in Example I.

Figure 2 illustrâtes the RO membrane compatibility testing resulls oi’best in class non-RO aniphoteric foainer I as explained in Example I.

Figures 3a and 3b illustrate ihe RO membrane compatibility testing results of best in class non-RO anionic foamers 2 and 3 as explained iu Example 1.

Figure 4 illustrâtes dynumic unloading results of Product I vs. a best in class non-RO compatible foamer in the presence of 1% coal fines in two different brines as explained in Example 2.

Figure S illustrâtes the corrosion rate as a function of time during the standard linear polarization résistance (LPR) bubble test of Producl 1 as explained in Exemple 4.

DETAILED DESCRIPTION OF THE INVENTION

The method of using the foaming compositions of this invention hâve been shown to be effective for recovering natural gas fioin a gas well and recovering crude oil from a gas-lifted oil well penetrating a subterranean oil-bearing formation. That is, the foaming agents of the présent t

I invention eiïectively remove hydrocarhon antl/or water or mixtures thereof from the wclls. The elïective amount of active ingrédient in a formulation required to sufficienlly foam varies with the System in which il is used. Methods for monitoring foanüng rates in different Systems are well known to those skilled in the art and may be used to décidé the effective amount of active ingrédient required in a particular situation. The described compounds may be used (o Impart the property of fbaming to a composition for use in an oil or gas iîcld application.

The described fbaming compositions are particularly effective for unloading fluids (oil and/or water) front oil and gas wclls under a variety of conditions. These compounds/compositions may be used in wells in which oil culs in the fleld can range front about 0% (oil fîeJd) to 100% (reiinery) oil, while the nature of the water can range from 0 to 300,000 ppm TDS (total dissolved solids). In addition, the bottom hole température can be between 60°F and 400°F. The foamers of die invention can be applied by batch treatments or continuous applications via the casing/tubing annulus or via capillary strings and are typically introduced inlo lhe downhole end of a well. An exemplary method and apparatus of introducing foatners through the use of an injection nozzle capable of atomizing (lie foamer, as disclosed in U.S. Patent No. 7,311,144. A batch treatment involves the application of a single volume of foamer to the well. as opposed to a smaller volume applied continuously for the case of a continuous application, The next batch is applied after a period of time when the foamer starts to lose its cffectiveness or décliné in performance.

In embodiments of this invention, classes of foamers for use in the method of lhe invention include sodium or other ions. Other ions may include. for exainple. alkali métal cations or organic counterions, such as triethanol amine, dtethanol amine, monoetbanol amine, and combinations thereof. Représentative foamers include alkyl or alkenyl (Ce to C22) benzeue sulfonate, sodium alkylnapthalcne (CV io C22) sulfonate, alkyldiphenyloxide disulfonate (Ce to Q2)» dialkyldiphenyloxidc disulfonate (Ce to Ci»), sodium/other ions alkyl or alkenyl sulfate (Où to C22), and naphthalene sulfonate formaldéhyde condensate.

In an embodiment of the invention, sodium dodccylbenzene sulfonate is used as the foamer. The préparation of is well known in the art. The sodium dodccylbenzene sulfonate of this invention may be prepared, for exemple, by the following steps: First, sulfonation of the dodccylbenzene can be performed either by heuting the dodccylbenzene with 20% oleum or contacting it with vaporized sulfor trioxide. Then, neutrelization of the réaction mass with sodium hydroxide yields a product which is substantially sodium dodecylbenzenesulfonate in aqueous solution.

Foaming agents of the présent invention can be formulated in a membrane compatible mixer! solvent package that may contain water, xylene sulfonate, potassium formate and low or very low molecular alcohois such us methanol, and combinations thereof. Tire use of solvents reduces the vïscosity, enhances the liquid unloading eflîciency, lowers the lreezing point of the foomer und improves cotnpatibility with various components, The solvent is présent in an 10 amount rangitig from about 5% to about 70%, about 95%, or about 99% by weight actives based on total weight of the composition. The foamer of the présent invention is tolérant to high sait ûnd hydrocarbon contents too and thus can be applied in wells with high salinity water or high hydrocarbon contents, in which case the foamer of this invention can remove hydrocarbon and/or water or mixtures from the naturel gas and oil wells.

The described fourriers or foaming agents of this invention may also be effective for penetrating subterranean oil-bearing or gas-hearing formations to recover naturel gas from a gas well or r ce over crude oil from a gas-litted oil well. Excmplary gus-lift methods for producing oil are disclosed in U.S. Patent No. 5,871,048 and U.S. Patent Application No. 2004-0177968 Al. In other words, the foaming agents of the invention may be effective at aiding and making more 20 efficient removal of hydrocarbon and/or water or mixtures thereof from wells. H should be appreciated that in some embodiments other corrosion inhibitors, seale ïnhibitors, and/or biocides may be used in conjunction with or in formulations including the foamers of this invention.

Corrosion inhibitors are usually formulated in conventional foamers to protect the downhole equipment from corrosive wellborc environment. The foamer ofthis présent invention 25 provides a certain level of corrosion protection, so ofïcrs a level of corrosion protection to the downhole equipment. without compromising RO operations. However, iri certain cases other anionic and/or amphotcric corrosion ïnhibitors,, may be used in conjunction with the foamer of the invention.

In embodiments, scale ïnhibitors may also be used in conjunction with the foamer of the 30 présent invention. Représentative scale inhibitors include polyphosphates, polyphosphonates, other suitable seule inhibitors, and combinatios thereof. The composition may also include a membrane compatible mixed solvent package that may contain water. xylene sulfonate, potassium formate and very low molecular alcohois such as inethanoL and any combination thereof.

The composition of fois invention can generate stable foams and is preferably présent at a level of Γτοηι about 10 ppm to about 100,000 ppm. A more preferred range is about 100 ppm to about 20,000 ppm. Most preferably, the range is from about 200 ppm to about 10,000 ppm. The foamer composition can optionally include additional actives that are RO membrane compatible; corrosion inhibitor, scale inhibitor, biocide, paraffin dispersant.

Fven though this disclosure is directed primarily to oil and gas recovery applications, it is contemplated that the composition of the invention may also be used in other applications. For example, the composition may be used as u deposit control agent or cleaner to remove deposits 10 (e.g., hydrocarbonaccous deposits) from wells and/or pipelines. “Hydrocarbonaccous deposit” refers generally to any deposit including at least one hydrocarbon constituent and forming on the iiiner surface of flowlines, pipelines, injection lincs, wellbore surfaces, siorage tanks, process equipment, vessels, the like, and other componenls in oil and gas applications. Such deposits also include schmoo,” which refers to a solid, paste-like, or sludge-like substance that adhères to 15 almost any surface with which it cornes in contact and is particularly difïicult to remove. Deposits contributing to schmoo may include, for example, sand, clays, sulfur, naphthenic acid salts, corrosion byproducts, biomass, and other hydrocarbonaccous materials bound together with oil. In addition, the foamer of the instant invention may also bc used as a parafGn-dispersant. émulsion breaker, corrosion inhibitoi; and enhanoed oil recovery agent, or in combination with 20 paraffin-dispersants, émulsion hreakers, corrosion inhibitors, andenhanced oil recovery agents.

The foregoing may be better uruierstood by reference to the foliowing examples, which are intended for illustrative purposes and are not intended to limit the scopc of the invention.

Example I

RO Membrane Compaiibiliiy

The industry standard test protocol was utilized to déterminé lhe compatibilily of lhe foamers with a Filmtec BW30 membrane. This test involved detennining whether the foamers, by themselves, would negatively impact membrane performance. The following QC spécification for Filmtec BW30 membrane is used: Feed Composition NaCl; Feed Concentration 2,000 ppm; Feed Température 25 C; Feed Pressure 220 psi; Pcrmcatc Flow 45 LMH; Minimum Rejection 99.5%.

The RO membrane compaiibiliiy test protocol used in this cxamplc consistcd of the following steps:

1. Cut sample coupon from membrane sheet

2. Déterminé baseline flux and sait rejection

a) Recirculaie test solution at pressurized standard conditions with the foamer. Test flux and sait rejection at 2, 6 and 24 hours.

b) Soak in test solution for 2 weeks, rinsc and test flux and sale rejection.

The standard test conditions were as follows. Flux and rejection were determined by using a test skid cquipped with a flat-plate membrane cell for a membrane coupon with an effective membrane area of 0.023 m². The standard test solution contained 2,000 ppm NaCl for lhe BW30 membrane and was circulated through the membrane cell al a flow rate of 1,000 ml/min at die desired pressure.

The circulation test procedure was as follows. The test solution was made up to contain 2,000 ppm NaCl for the BW30 membrane and lhe foamer products at their respective concentrations (see Table 1 below). Rejection and flux ai standard conditions were determined after 2, 6, and 24 hrs pressurized circulation using the lest solution.

The soak lest procedure was as follows. Membrane was soaked in a solution that conlained the tesled products at the desired concentration. Rejection and flux were determined with the standard test solution after 2 weeks soaking. The membrane was removed, rinsed, and then tested for flux and rejection using the standard test conditions for lhe membrane type.

Product J (sodium dodecylbenzenesulfonale) in its aqueous solution fbrm was tested against two kinds of commonly used foamers: best-in-class non-RO betaine foamer 1 and nonRO amollie foamers 2 and 3 (Table I). Foamer 1 contained coco-amidopropyl betaine as foaming

agent, quatemary ammonium as corrosion inhibiting agent and phosphonate as antî-scaling agent, Bcst-în-class non-RO anionic foamer 2 was aqueous solution of laura a olcfin sulphonate. Bestiti-class ποπ-RO anionic foamer 3 was ammonium alcohol (Cû-Cio) ethcr sulfate (AES) in waler/isoproponal (IPA) solution, with weight pcrccnlagc of AES: Water: ΓΡΑ being 65:25:10.

Table 1

Foamers for RO Membrane Compatibility Test

	FÏeïd treat rate	Maximum test rate
Foamer	(ppm)	(ppm)
Product 1	1,300	6,500
Best-in-class non-RO	1,610	16,100
Betaine foamer 1
Best-in-class non-RO	875	4,357
anionic foamer 2
Bost-ln-class non-RO	607	3,035
anionic foamer 3

Before starting the test procedure, the base lînc sait rejeotion and flux was determined l'or each membrane sample. Before baseline data was recordcd, the membrane was operaled under standard test conditions for about 12 hours. The base line data point for each membrane sample becatne an “internai standard” against which the test data was compared, lience reducing the impact of membrane variability.

The circulation and soak test results of dcmineralized water (blank) are summarized in Table 2 and were used to compare against foamers at the varions dosages. The blank test revealed equal or less than 10% flux change vs. baseline in 2, 6, and 24 hr circulation tests and 2 week soak test.

The circulation and sœk test results of Product I al 1,300 ppm and 6,500 ppm dosages are summarized in Table 3. Equal or less than 10% flux change vs. baseline was observed in ail the tests. Product 1 showed no impact in the testing compared to the blank and is thus classed as RO membrane compatible.

The circulation and soak test results of best-in-class bciaine foamer I and anionic foamers 2 and 3 are summarized in Tables 4, 5, and 6, respectively. The betaine foamer 1, when dosed at 1,600 ppm field treat rate and 16,000 ppm, which is ten times the lleld Ireat rate, gave more than

50% flux change vs. baseline in ail the tests. The test résulta of anionie foamers rcvcalcd more than 10% flux change in ail the lest conditions. Thercfore, threc ofthcin are classed as RO membrane incompatible.

The RO membrane compati b il ity test results of Product J, betaine foamer l and anionie foamers 2 and 3, together with the test resuit of blank water, were plotled in FIGs 1,2, 3a, and 3b 10 respectively.

Table 2

RO Compatibility of Demineralized Water (blank)

Blank	Rejection	Flux Change vs. Baseline
Baseline	97.5%	N/A
2 hr Circulation	98.5%	-2%
6 hr Circulation	98.6%	-6%
24 hr Circulation	98.6%	-10%
2 week soak	98.7%	-6%

Table 3

RO Compatibility of Product 1

Product 1
1,300 ppm	Rejection	Flux Change vs. Baseline
Baseline	98.3%	-
2 hr Circulation	99.0%	-2.7%
6 hr Circulation	98.7%	-1.7%
24 hr Circulation	98.7%	-8.5%
2 week soak	98.7%	__________-10.0%
6,500 ppm
Baseline	98.3%	-
2 hr Circulation	99.0%	-3.5%
6 hr Circulation	99.0%	-0.5%
24 hr Circulation	99.0%	-6.9%
2 week soak	98.8%	-9.1%

RO Compatibility ofNon-RO Betaine Foamer 1

Table 4

Non-RO Betaine Foamer 1
1,610 ppm Baseline	Rej action 98.6%	Flux Change vs. Baseline
2 hr Circulation	98.9%........	-53.0%
β hr Circulation	98.9%	-55.0%
24 hr Circulation	98.9%	-67.0%
2 week soak	98.7%	-70.0%
16,100 ppm
BaseS ne	98.0%	-
2 hr Circulation	98.5%	-61.0%
6 hr Circulation	98.5%	-59.0%
24 hr Circulation	98.6%	-67.0%
2 week soak	-	-

Table 5

RO Compatibility ofNon-RO Anionic Foamer 2

Non-RO Anton c Foamer 2
875 ppm	Rejection	Flux Change vs. Baseline
Baseline	98.8%	-
2 hr Circulation	98.9%	-7.2%
6 hr Circulation	99.0%	-5.5%
24 hr Circulation	99.0%	-16.0%
2 week soak	98.9%	-13.5%
4,375 ppm
Baseline	98.9%	-
2 hr Circulation	99.1%	-17.3%
6 hr Circulation	99.1%	-19.3%
24 hr Circulation	99.2%	-21.5%
2 week soak	98.4%	-27.0%

RO Compatibility of Non-RO Amoiiic Foamer 3

Table 6

Non-RO Anlonlc Foamer 3
2,100 ppm	Rejectlûn	Flux Change vs. Baseline
Baseline	98.0%	··
2 hr Circulation	98.3%	-21.0%
6 hr Circulation	98.5%	-26.0%
24 hr Circulation 2 week soak	96.8%	__________-34.0% _________
21,000 ppm		----------------
Baseline	98.0%	*
2 hr Circulation	98.3%	-43.0%
6 hr Circulation	98.5%	•42.0%
24 hr Circulation	98.8%	-46.0%
2 week eoak	-	-

For a person skilled in the art it was very surprising and unexpected that replacing alkyl linear sulfonates with aryl sulfonates would resuit in a decrease of flux change or an increase of 10 the permeate stream. A skilled person would rather cxpcct that the use of aryl sullbnate surfactants (e.g., alkyl benzene sulfonate) would resuit in a larger flux change or lower permeate streams due to the higher volume and bulkiness ofthe benzene groups.

Examplc 2

Liquid Unioading Efficiency

The unioading efficiency testing of the foamers was perfonned using a dynainic foamîng test apparatus in the laboratory. This provided a means to scrccu tbaincrs under various conditions and rank performance. The dynamic foamlng test used a liquid sample thaï consisted of synthetîc brine or fteld brine with a percentage of field condensate or oil présent. In some cases, additional species, such as coal fines or particulates, may be added to reproduce well 20 production conditions. The sample was then dosed with the desired treat rate of foamer. 100 g of the total test fluid was slowly poured into a 1,000 ml column at the bottom of which nilrogen gas (7 LPM) was sparged through a frit glass. The gas flow generated foam and unioading occurred.

The liquid unioading efficiency was calculated by dividing the weight of the liquid 25 removed from the column after 15 min by 100 g. A best-in-class non-RO foamer was tested as a control. The test results of the control and Product 1 were plotted in FIG 4. Product 1 shows excellent performance in liquid unioading and demonstrates lhe negligible impact solids, such as coul fines, have on the foam formation and stability. The performance of Product 1 was

comparable to the best-iu-class non-RO foamer under the tested conditions. The two brines used for testlng are shown below.

*Brlne 1 - Durham Ranch Water Chemistry (ppm)
Sodium - Na	2400
Calcium - Ca	8.1
Potassium - K	16
Megneslum - Mg	1.9
Strontium - Sr	3.9
Barium - Ba	3
iron - Fe	0.1
Chloride - CI	2500
Sulfate - SO4	< 1
Bicarbonate HCO3

Brine 2 - Spring Gully Water Chemistry (ppm)

Sodium-Na

Calcium - Ca	15
Potassium - K	15
Megnesium Mg...........................	3.6
Strontium - Sr Barium - Ba	.—3J§._________ 3
Iron - Fe	3
Chloride - CI Sulfate - SO4 Bicarbonate HCO3	1900 < 1

Example 3

Corrosion Tendency Properiies

A seven day material coinpatibiJity test was designed to évaluait: lhe corrosion protection of chcinieals of certain niaterials (e.g., mêlais). Coupons were statically immersed in the test liquid and kept at the desired température for a period of seven days. The corrosion rate was calculated based on the weight différence of the coupon before and aller the lest. The coupon was also inspected for pitting at I0X magnification after immersion, fable 6 summurizes the 15 details of the coupons (material to be tested. manufacturer / supplier, compound used and coupon dimensions) used for this study, Besides CI0I8 carbon steel, SS2205, which is one of mctals commonly used for capillary injection System, was evaluated as well.

Table 6

Métal Conipatibility Study Parameters

Material	.MamiiftÇiureiZSMPPli.çr
SS2205	| NES Capillary String
C1018	î Corrosion Test Supplies

Allpy. SS2205

CÏ0Ï8 ' 2.2” x ’/i” oprôds......................

’ V xi /16”panels & 2” x’Λ” x 1/16” panels

Cleaning: The métal spécimens (referred ta as panels) were cleaned by the following method before the test. The panels were scrubbed with a commercial abrasive clcancr. Then the panels were rinsed in tap water and dried in acetone.

Measurements: 1he following were recoided inkially on the coupons that underwent the spécifie tests. The coupons were weighed to the nearest rcnth of a milligram on an analytical balance. The lengths and thieknesses or lengths and ODS of the panels were measured with a digital vernicr caiiper accurate to + 0.001 inch.

Immersion: The following immersion procedure was utilized. The brine test solutions were saturated with carbon dioxidc by bubbling in carbon dioxïde for 15 minutes. The panels were immerscd fully in two-ounce glass jars filled with 50 ml of the test solution. The jars were placed in an oven maintained at 13O°F for a period of 7 days. Each test was run in dupïicate.

Time: The measured parameters were taken after immersion for 7 days at 13O⁰F. After the test period, the following steps were taken to examine lhe coupon and corrosion rate. The panels were rinsed in deionized water, rinsed in acetone, and towel-dried. The wejghls and dimensions were measured after air-drying for 1 hour. Métal corrosion rates were calculated using the équation below. The coupons were inspected after immei-sion at 10X magnificatîon for pitting.

Reporting of Results; The corrosion rates (ineasure in mils per year, mpy) were calculated using the following équation: Corrosion Raie == (Weight Loss of Coupon x 534)/(Density in gm/cc x area in inches² x time in hours). 534 is the corrosion constant. Table 7 lists the results for SS2205 panels. Table 8 lists results for Cl018 panels.

The concentration of Product 1 was 5,000 ppm. Syntlietic brine composition was NaCl =

5.3 gms/liter and CaClj - 0.44 gms/liter. There were two different panels, one ’/i” widc and one W widc. For each pair of panels, the first was the !4” wide p«uiel and the second was the widc panel. The wider panel had a largcr area, lowering the corrosion rate.

Table 7

SS2205 7 Day Corrosion Test afeightChanwe

PRODUCT 1 Neat

PRQDÜCf î Neat

..............l..àfiEœn^_„...........

< 0.00Î tnpy________j No Visible ÂttaciT.......

5.0.001 jnpy _ I No Visible Attack

Table 8

Cl 018 7 Day Corrosion 'l'est

Chemical 1- ___'»πι·.ιηιιι>·ι· Î		..............	Anpearance
PRODUCT ί Neat	- 6.0 mg	î 1.05 mpy	Uniform Corrosion
PRODUCT 1 Neat	- 10.1 mg	I 1.23 mpy	Uniform Corrosion
Synthetic Brine	- 26.1 mg	4.73 mpy	Severely Pilted
Synthetic Brine	- 46.6 mg	i 5.68 mpy	Scvereiy Pitted
Syn. Brine + PRODUCT1	- 12.7 mg	2.19 mpy	Uniform Corrosion
Syn. Brine + PRODUCT1	- 17.7 mg	2.16 mpy	Uniform Corrosion

Observations: Table 7 summarized the SS2205 test results. After 7 days lest in neat Product I, both coupons had neither mensurable weight loss nor pitting.

Example 4

Linear Polarization Rate

J 5 The standard linear polarization résistance (LPR) bubble test is a corrosion test used to evaluate real-time response of corrosion rates with chemical addition. It can also be used to evaluate the partitioning properties of cheinicals (i.e., how quickly and to what extent in the tnultiphase system the chemicals will enter the water phase imder stagnant conditions) where corrosion réaction takes place. With respect to the field conditions, this test simulâtes low profile 20 areas, such as dead legs and water traps, where no or very limited mixing exists and the performance of an inhibitor is determined by its capabiliîy to partition into the water phase.

The testing conditions are given in Table 9. Synthetic brine (0.535% NaCl, 0.0045% CaCl3.2HjO by weight), was used, without addition of oil phase. The bubble cell tests were conducted at 130°F (54*C). The brine was saturated with COj and stirred at 100 rpm before the

f foamer was dosed. Product 1 was evaluated at a dosage of 5,000 ppm based on total volume. Its protection of Cl 018 carbon steel was investigated. Tbe cell was purged with CO2 for 1 hour, and during this time the solution was also allowed to heat to the desired température of i30F (54^qC). After baseline corrosion data was taken for three hours prior to injection, the cells were injected with 5,000 ppm Product 1 based on total volume. The lest was run for a total of 12 hours after injection.

Table 9

EPR Bubble lest of Product 1

Chem 1 cal	Product 1
Dosage	5,000 ppm
	Corrosion Rate (NIPY)	Protection (%)
Base line	150.5	-
2 hrs after Dosing	65.5	56.5
8 hrs after Dosing	59	60.8
11.9 hrs after Dosing	57	62.1
20 hrs after Dosing	24	84.1

Upon the addition of 5,000 ppm Product I, instant réduction of the corrosion rate was obscrvcd (Figure 5). Corrosion rate of the inhibited solution over the 16 hour period after dosing of the cliemical stayed much lower than the uninhibited baseline. The corrosion protection was calculated using the following équation: Protection = 100 x (Uninhibited corrosion rate inhibited corrosion rate)/(uninhibited corrosion rate), 'table 9 summarizes the corrosion protection rate in the bubble test and shows that the protection rate increased over the 20 hours tcsiîng period. The bubble lest results demonslrated clearly that Product 1 affords corrosion protection to carbon steel.

Ail of the compositions and methods disclosed and claïnied herein can bc made and executed without undue expérimentation in light 0Γ the présent disclosure. While this invention may be etnbodied in many different forms, there are described in detail herein spécifie preferred embodiments of the invention, The présent disclosure is an exemplification of the principlcs of the invention and is not intended to limit the invention to the particular embodiments illustrated. ln addition, unless expressly stated to the contrary, use of the term “a” is intended to include “at least 011e” or “onc or more.” For exampJc, “a device” is intended te include “at least one device” or “one or more devices.”

r

Any ranges gîven either in absolute terms or in approximate tenns are intended to encompass both, and any définitions used herein are intendcd to be clarifying and not limiting. Notwithstanding that (lie numerical ranges and parameters setling forth the broad scope of the invention are approximations, the numerical values sei forth in the spécifie examples are reported as precisely as possible, Any numerical value, however, inherently contains certain errors necessarily resulting from ihc standard déviation found in their respective testing measurements. Moreovcr, ail ranges disclosed herein are to be understood to encompass any and ail subranges (including ail fractional and whole values) subsumed therein.

Furthermore, the invention encompasses any and ail possible combinations of sonie or ail ofthe various embodiments described herein. Any and ail patents, patent applications, scientific papers, and other référencés cited in this application, as well as any référencés cited therein, arc hereby incorporated by reference in their entirety, It should also be understood that various changes and modifications to the prcsently preferred embodiments described herein will bc apparent to those skilled in (hc art. Such changes and modifications can be inade without departing frvni the spirit and scopc of the invention and without ditninishing its ijilended advantages. It îs theref'ore intended that such changes and modifications be covered by the appended daims.

Claims (15)

1. The claimed invention is:

   1. A method of foatning a fluid, for recovering gas from a gas well and enhancîng oil production from a gas-lifted oil weJI pcnctrating a subterranean oil-bearing formation, the method comprising: introducing into the fluid a foam-forming amount of a composition comprising at least onc compound selected from lhe following: X⁺ alkyl benzene sulfonate; X⁺ alkylnapthalene sulfonate; alkyldiphenyloxîdc disulfonate; dialkyldiphenyloxide disulfonate; X* alkyl sulfate; naphthalenc sulfonate formaldéhyde condensate; and combinations thereof; wherein alkyl is C(,-C;>s and wherein each compound or combination is compatible with a reverse osmosis membrane.
2. 2. The method of Claim I,wherein X¹ is selected from at least onc alkali métal cation, at least one organic cation, and combinations thereof.
3. 3. The method of Claim 1, wherein X* is selected from: trîethanol amine, diethanol amine, monoethanol amine, and combinations thereof.
4. 4. The method of Claim 1, wherein the at least onc compound includes sodium dodccylbenzcne sulfonate.
5. 5. The method of Claim 1, further comprising a solvent.
6. 6. The method of Claim 5, wherein the solvent is selected from the group consisting of: water; xylene sulfonate; potassium formate; low molecular weight. alcuhols; and any combination thereof.
7. 7. The method of Claim 5, wherein the solvent is jnethanol.
8. 8. The method of Claim 5, wherein the solvent is présent in an amount ranging from about 5 to about 70% by weight actives based on a total weight ofthe composition.
9. 9. The method of Claim 5, wherein the solvent is présent in an amount ranging from about 5 to about 95% by weight actives based on a total weight ofthe composition.
10. 10. The method of Claim 5, herein the solvent is présent in an amount ranging from about 5 to about 99% by weight actives based on a total weight ofthe composition.
11. 1 1. The method of Claim l, lùrlhcr comprising wherein the composition includes an additive selected from the group consisting of: corrosion inhibitor, scaie inhibitor, biocide, paraffm dispersant.
12. 12. The method of Claim 11, wherein the additive is compatible with a reverse osmosis

    5 membrane.
13. 13. The method of Claim 1, further comprising introducing into the fluid the foamforming amount ofthe foaming composition to the downholc end of a well as batch addition or continuously.
14. 14. The method of Claim 1, ftirther comprising introducing to the lluid lrom about 10

    10 ppm to about 100,000 ppm of actives in the composition to (hc well, based on volume of the fluid.
15. 15. The jnethod of Claim f, wherein tlie fluid is oil or condensate and water.