WO2016134873A1 - Liquid dissolver composition, a method for its preparation and its application in metal sulfide removal - Google Patents

Abstract

The present invention relates to an aqueous composition, comprising 1. 5 to 50 wt.-% of at least one polymeric carboxylic acid having a weight average molecular weight from 1500 to 50.000 g/mol, determined by gel permeation chromatography against polystyrene standards, or its salt; 2. 2 to 28 wt.-% of at least one H⁺ ion releasing monomeric acid having a molecular weight of less than 500 g/mol; 3. 2 to 30 wt.-% of at least one surfactant.

Description

Liquid Dissolver Composition, A Method For Its Preparation And Its Application In Metal Sulfide Removal

FIELD OF INVENTION

The invention described concerns a dissolver composition for sulfide scale minerals, especially sulfides of iron, lead and zinc. The application of this dissolver chemical is particularly suited to oilfield exploration, drilling, production and process systems where sulfide scales have a tendency to form. However there is also applicability to other industries such as mining, refinery and general industry. The application of this dissolver serves to remove these highly insoluble sulfide scales, far more efficiently than other chemicals known in the art. The dissolver composition does not attack the metal surfaces to which the sulfide scale is so commonly adhered. BACKGROUND OF THE INVENTION

It has been well documented that sulfide scales of iron, zinc and lead can cause various challenges with process and production in the oil industry. The common impact is the deposition of scales that decrease production capacity. The common metal sulfide minerals are shown in Table 1. It is also possible for solid solutions to exist between the metal cations that counter the sulfide anion.

Accumulation of sulfide scale in the tubulars can result in reduced well

deliverability. The build-up of sulfide scale interferes with the operation of pumps, valves and other associated surface equipment.

Table 1 : The common sulfide minerals

Mineral Name Chemical Formula

Pyrite FeS₂

Marcasite FeS₂

Pyrrhotite Fei_-xS

Troilite FeS Mackinawite FeSi_-x

Greigite Fe₃S₄

Kansite FegSs

Sphalerite ZnS

Galena PbS

The surface of sulfide scales is oil-wet (oleophillic), in particular iron sulfide, and free-floating iron sulfide particles are often found at the oil-water interface and stabilize emulsions, thus affecting the separation. Iron sulfide has also been reported as far downstream as the refinery, where it has reduced the efficacy of heat exchange surfaces. Deposition can create an integrity risk; once sulfides form onto metal surfaces, they form a cathode to the equipment surface which yields a significant localized corrosion (pitting) potential. This is commonly exacerbated by the irregular form of the scale surfaces thus accelerating further corrosion.

Sulfide scale forms most typically as an H2S corrosion product or from the mixing of incompatible waters. The primary reaction at normal brine pH is:

M²⁺ + H2S (aq) <→ MS (s) + 2H⁺

M = Fe, Pb or Zn

It has been postulated that iron sulfide scale is predominantly deposited as a result of microbially enhanced corrosion or as a result of the reduction of iron oxide (from corrosion) by hydrogen sulfide, derived from sulfate reducing bacteria (SRB) metabolism.

The presence of iron sulfide solids is common in aging assets, as the prevalence of corrosion products, e.g. iron can occur as a result of insufficient corrosion protection. Iron, zinc and lead sulfide solids can also be found in the formation waters associated with certain reservoirs, where high pressure, high temperature and high salinity (HP/HT/HS) conditions are encountered. Removal and prevention of sulfide scales is challenging. Part of the reason for this is the extremely low solubility products (K_sp) associated with sulfide scales, due in part to the highly covalent nature of transition metals sulfides; Table 2 shows the solubility products of the most common sulfide minerals in comparison with common, conventional scales.

Table 2: Solubility product constants for a selection of common inorganic mineral scales and sulfide scales found in oil and gas production (Dean, 1999) at 25 °C.

Existing methods of remediation available to treat sulfide scale deposits comprise both mechanical and chemical. Mechanical remediation by way of jetting is possible, if the areas affected by mineral scale build up are readily accessible. Pipework with more tenacious deposits may require more aggressive milling operations. Both options incur costs in terms of deferred oil production and equipment rental.

Chemical mitigation strategies for sulfide scales can be divided into two

categories: removal and dissolution or control and prevention.

Techniques and chemicals for the removal and dissolution of sulfide scales have been documented in the literature. The most commonly performed technique has been to use hydrochloric acid, but it has been reported to perform with varying degrees of success. It has been noted for example that iron sulfide with lower amounts of sulfur has a higher solubility in acid. Challenges using hydrochloric acid are encountered due to the potentially high yield of H2S upon dissolution of the scale; additionally hydrochloric acid is very corrosive. This has led to research on the inclusion of corrosion inhibitors and scavengers into the acid blend. Other components have been reported in the formulations such as chelants, wetting agents, solvents, iron control agents, anti-sludge agents - all these components were included on the basis that sulfide scales are often associated with oil and biomass which act as a diffusion barrier that inhibit the acidic reaction. An alternative approach to acids is the use of strong oxidizing agents which avoids the toxicity hazards of acids but produces oxidation products, including elemental sulfur, which are so corrosive to pipework that is has not generally been practiced.

Due to the challenges associated with use of acids, the focus in the last decade has turned to alternative, non-acidic dissolver chemistries. These include chelating agents such as ethylenediamine-tetra-acetic acid (EDTA), diethylene-triamine- penta-acetic acid (DTPA), hydroxyethylene-diamine-tetra-acetic acid (HEDTA) or nitilotriacetic acid (NTA). The efficacy of chelating agents, however, has been shown to be relatively limited, as they function poorly in acidic environments, requiring elevated pH for full dissociation and efficacy.

Acrolein gas is effective for iron sulfide dissolution but is a challenging material to handle due to the severe health, safety and environmental problems that it gives rise to. Acrolein reacts with iron sulfide to form an intermediate compound that is far less likely to re-deposit, and at the same time, the acrolein will also scavenge H2S.

Tetrakis(hydroxymethyl) phosphonium sulfate (THPS) has been reported as effective against iron sulfide scales. THPS dissolves via a chelation method and the efficacy is vastly improved with inclusion of ammonium ions (where an intermediate complex is formed) or DETA-phosphonate is added; however when tested in a pressurized system, the efficacy of THPS-based dissolvers decreased. One of the additional advantages of THPS is that it can be used to remove deposits via continuous injection of very low concentrations. The process and science behind control and prevention of iron sulfide is much more complex than removal and dissolution. All facets are more complex, whether it is laboratory testing, implementation in the field or the mechanism of inhibition. The control and preventions strategies can therefore involve a multi-faceted approach, combining:

• Chelating agents (for iron sequestration)

• Surfactants (for water wetting)

· Biocide (to target SRB and biofilm)

• Corrosion inhibitor (to lower total iron in system)

• Sulfide scale inhibitors (threshold inhibition of scale)

The key to implementing an effective mitigation treatment is to first understand the root cause of the sulfide scale and where the source of metal ions and sulfide are coming from. Once this has been identified, then the appropriate mitigation can be put into place.

Chelating agents can be continuously injected in order to remove iron present in the system. Typical chemistries include citric acid, acetic acid or glycolic acid. These are, however, not iron specific, and THPS may be a more economically viable option. Use of chelants should typically be used to control iron that is coming from the formation, rather than from corrosion (which would be better approached using corrosion inhibition to control the iron).

Surfactants can be used to increase the efficacy of control. As previously mentioned, iron sulfide is oleophillic and often forms in systems where small amounts of oil and grease are present. Even mg/L levels of oil are enough to create a significant diffusion barrier on the growing crystal nuclei to affect efficacy of chelation, dissolution or inhibition. The surfactant is used to change the oil-wet nature of the scale to water-wet and allow better access of the primary control agent to the scale. Surfactants could also serve to act as biocide synergists, allowing better access to sessile species of bacteria that produce H2S. There is a huge range of surfactant chemistry that is available but typically involves alkoxylated alcohols, amines, phenols or natural oils. More simple solvents could also be usefully employed, such as 2-butoxyethanol, monoethyelene glycol, etc. Biocides are used to control the growth rate of SRB and ultimately are used to reduce the H2S concentration and, therefore, reduce the supersaturation with respect to iron sulfide. There are many options for biocide chemistries; the most commonly employed include glutaraldehyde, THPS or quaternary ammonium compounds. The best performing biocide is usually determined by performing a detailed time-kill study on the actual produced water targeted for treatment.

Corrosion inhibitors are used to control the amount of soluble iron in the system by preventing metal loss from downhole tubulars and surface spools. Just like chelation, lowering the amount of iron in the system removes the supersaturation with respect to iron sulfide and, therefore, the driving force behind scale

precipitation. Yet again, there are many options for corrosion control and the exact product to be deployed should be determined from a detailed laboratory and field study of the corrosion inhibition efficacy, injection location mimicking the exact process conditions.

Most of the commercially available sulfide dissolver systems for these applications are either acid based that cause widespread corrosion and liberation of toxic hydrogen sulfide gas, e.g. acids, oxidizers or acrolein; or are based upon the toxic (biocidal) THP⁺ molecule, which formulation also liberate toxic hydrogen sulfide gas as the THP⁺ molecule is only stable at a pH of less than 3. Furthermore, the commercially available sulfide dissolver systems have only limited functionality, when compared to the current high performance embodiments of the instant invention. Additionally, the commercially available treating solutions are of limited dissolution efficacy, particularly for lead and zinc sulfide and require very high temperatures to yield good kinetics whereas the instant invention has exceedingly high kinetics of dissolution, even at low temperature. The patent landscape for chemical sulfide scale dissolvers has been focused recently on non-acidic chemicals. Many of the previously mentioned methods, such as acids and their blends are considered to be prior art.

US 5,080,779 describes methods for removing iron in a desalting system. The patent elaborates on a crude and water soluble chelant added to the process prior to washing water. Chelants such as EDTA are described as complexing agents for the iron to make the removal more efficient and in turn preventing the formation of iron containing scales further downstream.

US 5,332,491 describes a dispersant for iron sulfide used for the treatment of this scale in hydrocarbon streams found in refinery and petrochemical plant

operations. The dispersant described comprises a free-radical copolymer of a-olefin between Cio to C36 and maleic anhydride. The resultant polymer has the anhydride moieties along the copolymer backbone in a substantially unhydrolyzed form.

US 6,986,358 B2 describes a method and composition for decreasing iron sulfide deposits in pipelines. The method uses an aqueous formulation containing at least one compound of the generic formula [P-(CH2-CH2-OH)4]n-X and at least one amine or corresponding ammonium derivative in the presence of a solvent, where X is an anion of valency n. the pH of the solution is preferably 8. Alternatively the method employs a composition comprising tris (hydroxymethyl) phosphine (TRIS) and at least one amine or corresponding ammonium derivative. The amine preferable is ammonia or a primary alkylamine. The compositions readily complex and thereby dissolve deposits of iron (II) sulfide.

US 6,926,836 B2 is the start of a patent family where the common dissolving agent is Tetrakis (hydroxyorgano) phosphine (THP⁺) and salts thereof. In this patent, a method is described for dissolving metal sulfide scales in a water system. A solution of THP⁺ along with sufficient chelant (amino-carboxylates or amino phosphonates) provide a solution containing 0.1 to 50 % by weight of THP⁺ or THP⁺ salt and 0.1 to 50 % by weight of the chelant. US 2007/0108127 A1 described a method of treating an aqueous system containing or in contact with metal sulfide scale. The method comprises applying a synergistic blend of THP⁺ and an aqueous solution of strong acid. The resultant solution has a pH of <1 and contains 0.1 to 30 % by weight THP⁺. The scale is contacted with the solution and dissolution occurs and the dissolved scale is withdrawn from the system.

US 7,803,278 B2 is a further extension of US2007/0108127 A1 where the formulation provided is again for the treatment of metal sulfide scale deposits in aqueous systems and is a formulation of THP⁺ and a primary, secondary or tertiary alcohol having an acetylenic bond in the carbon backbone.

US 7,855,171 B2 is by a different group and is the start of another patent family that focuses on the use of THPS. In this invention an iron complexing mixture is described for the cleaning of natural gas pipelines. The patent describes the synergy between THPS and iminodisuccinic acid (IDS) and shows the advantages in performance over the individual use of either chemical in combination with ammonium chloride, sodium hydroxide, surfactant, scale inhibitor and corrosion inhibitor.

US 8,673,834 B2 is the second family by the same group and goes on to describe an iron complexing mixture, again for application in natural gas pipelines. In this patent a more complex formulation is described composed of THPS, IDS, a surface tension reducing water soluble surfactant, a water soluble corrosion inhibitor, a defoamer, a water soluble ammonium salt and a pH buffering chemical.

US 20 0/0099596 A1 is the final patent in the THPS, IDS combination reviewed and describes an iron complexing mixture for application in gas pipelines where the mixture of THPS and IDS is synergistic and offers advantages over the individual use of either chemical. The object of the instant invention is to find an alternative composition useful to dissolve sulfide scale in oilfield operations. Upon application, this composition should be able to dissolve sulfide scales without releasing stoichiometric amounts of H2S. The composition should be less toxic than compositions comprising THPS, and preferably should be essentially free of THPS.

A further object of this invention is to provide a sulfide scale dissolver that will work in less time than the composition of the prior art. A further object of this invention is to provide a sulfide scale dissolver that is efficient at higher pH, thereby mitigating corrosion to oilfield equipment. A further object of this invention is to provide a sulfide scale inhibitor that does not rely upon mineral acid and/or low pH solutions only to dissolver iron sulfide which can lead to secondary deposition of, for example, inorganic iron chloride or organic asphaltenes. SUMMARY OF THE INVENTION

In a first aspect, the present invention provides an aqueous composition, comprising

1. 5 to 50 wt.-% of at least one polymeric carboxylic acid having a weight

average molecular weight from 1 ,500 to 50,000 g/mol, determined by gel permeation chromatography against polystyrene standards, or its salt;

2. 2 to 28 wt.-% of at least one H⁺ ion releasing monomeric acid having a

molecular weight of less than 500 g/mol;

3. 2 to 30 wt.-% of at least one surfactant. The composition according to the invention is useful as a sulfide scale dissolver for application in oilfield operations.

In a preferred embodiment, the composition comprises additionally

4. at least one hydrogen sulfide scavenger.

In another preferred embodiment, the composition comprises additionally

5. at least one scale inhibitor and/or at least one corrosion inhibitor. In a second aspect, the present invention provides the use of the composition of the first aspect as a sulfide scale dissolver for application in oilfield operations and process systems. In a third aspect, the present invention provides a method for dissolving sulfide scale in oilfield operations and process systems, the method comprising bringing the sulfide scale into contact with the composition of the first aspect.

The composition comprises at least one component from each of groups 1 , 2 and 3.

In one preferred embodiment, at least one component from group 4 is present with the components from each of groups 1 , 2 and 3. In another preferred embodiment, at least one component from group 5 is present with the components from each of groups 1 , 2 and 3.

In another preferred embodiment, at least one component from each of groups 4 and 5 are present with the components from each of groups 1 , 2 and 3.

In another preferred embodiment, the composition comprises water to make the formulation add up to 100 wt.-%. This applies to the composition comprising components 1 , 2 and 3. It also applies to the composition comprising components 1 , 2, 3 together with other components as described herein, inter alia components 4 and/or 5.

Group 1

In a first aspect, Group 1 comprises polymeric or copolymeric materials that contain repeated carboxylic acid and/or carboxylate groups. Some of the monomers used for the copolymerization may not however contain carboxylic groups but will always be associated with monomers that do contain carboxylic groups. The monomers therefore are from, but not limited to, the following groups: acrylic acid, aspartic acid, allyl sulfonate and its salts, vinyl sulfonate (and salts), styrene sulfonate (and salts), ethane sulfonate (and salts), vinyl phosphonic acid, vinyl di-phosphonic acid, maleic acid, glutamic acid, taurine, methionine, alanine, allyl glycidyl ether, glycidyl methacrylate.

In one preferred embodiment the polymeric acid is poiyaspartic acid or its salt. The expression "poiyaspartic" means a polymer that comprises monomer units of aspartic acid to create a homopolymer of aspartic acid or copolymers of aspartic acid. One preferred embodiment is to prepare polyaspartate by step-growth polymerization. Aspartic acid is simply heated which results in water release and the formation of a poly(succinimide). In the subsequent step, this polymer is reacted with sodium hydroxide in water which hydrolyzes one of the two amide bonds of the succinimide ring to form a sodium carboxylate. The remaining amide bond is thus the linkage between successive aspartate units. Each aspartate unit is identified as a or β according to which carbonyl of it is part of the polymer chain. The a form has one carbon in the backbone in addition to the carbonyl itself (and a two-carbon side chain) whereas the β form has two carbons in the backbone in addition to the carbonyl itself (and a one-carbon side chain). This reaction gives a sodium poly(aspartate) copolymer composed of approximately 30 % a-linkages and 70 % β-linkages.

There are many commercial polyaspartates available and the choice of

polyaspartate is wide. The instant composition preferably includes polyaspartates ranging from 1 ,000 to 50,000, preferably 1 ,800 up to 20,000 Daltons in weight average molecular weight, determined by gel permeation chromatography against polystyrene standards. The range of a-linkages in the polyaspartate is from 0 to 100 molar %, preferably from 30 to 40 %. The preferred range of branching is from 1 % branching to 50 % branching (in the intermediate polysuccinimide), more preferably from 1 to 5 %. If the salts of the acid are used, sodium or potassium are preferred as cations. The degree of branching is controlled by the source of the aspartic acid. Naturally sourced aspartic acid results in linear polyaspartate as the amine groups are more naturally ordered. Synthetic aspartic acid results in more branched (randomly distributed) amine groups in the polymer chain.

In another preferred embodiment, the polymeric acid is a copolymer in 50:50 molar ratio between allyl sulfonic acid or its salt and maleic acid or maleic anhydride.

In another preferred embodiment, the polymeric acid is a copolymer of acrylic acid and maleic acid or maleic anhydride. The molar ratio is from 50 to 80 mol-% acrylic acid to 20 to 50 mol-% maleic acid or maleic anhydride.

Another preferred embodiment of the invention is to use an aspartic acid polymer, sodium salt with Mw of 5,000 to 7,000, preferably 6,000 Daltons (determined via gel permeation chromatography) and <1 % branching.

Another preferred embodiment of the invention is to use an aspartic acid polymer, sodium salt with a molecular weight of 4,000 to 6,000, preferably 5,000 Daltons with approximately 30 % branching.

Yet another preferred embodiment of the invention is to use a copolymer of sodium allyl sulfonate and maleic acid copolymer (50:50 molar ratio) with a molecular weight of 1 ,000 to 2,000, preferably ,500 Daltons. Yet another preferred embodiment of the invention is to use a copolymer of acrylic acid and maleic acid (70:30 molar ratio) with a molecular weight of 1 ,500 to 2,500, preferably 1 ,800 Daltons. Group 2

The acids are used to provide H⁺ ions to the formulation in order to create the synergy for dissolution of sulfide minerals. The acids used may be selected from any proton acid as it is the H⁺ ion that is their most important contribution to the composition. However it has been found that certain acids provide better end results in terms of greater dissolution speed and amount.

It is preferred that the acid to be used has a pK_a value in the range from -8.0 to 4.0. The acids are preferably selected from the group consisting of, but not limited to, sulfuric acid, sulfurous acid, hyposulfurous acid, hyposulfite, persulfuric acid, pyrosulfuric acid, disulfurous acid, dithionous acid, tetrathionic acid, thiosulfurous acid, hydrosulfuric acid, peroxydisulfuric acid, perchloric acid, hydrochloric acid, hypochlorous acid, chlorous acid, chloric acid, hyponitrous acid, nitrous acid, nitric acid, pernitric acid, carbonous acid, carbonic acid, hypocarbonous acid,

percarbonic acid, hypocarbonous acid, percarbonic acid, oxalic acid, acetic acid, phosphoric acid, phosphorous acid, hypophosphorous acid, perphosphoric acid, hypophosphoric acid, pyrophosphoric acid, hydrophosphoric acid, hydrobromic acid, bromous acid, bromic acid, hypobromous acid, hypoiodous acid, iodous acid, iodic acid, periodic acid, hydroiodic acid, fluorous acid, fluoric acid, hypofluorous acid, perfluoric acid, hydrofluoric acid, chromic acid, chromous acid,

hypochromous acid, perchromic acid, hydroselenic acid, selenic acid, selenous acid, hydronitric acid, boric acid, molybdic acid, perxenic acid, silicofluoric acid, telluric acid, tellurous acid, tungstic acid, xenic acid, citric acid, formic acid, pyroantimonic acid, permanganic acid, manganic acid, antimonic acid, antimonous acid, silicic acid, titanic acid, arsenic acid, pertechnetic acid, hydroarsenic acid, dichromic acid, tetraboric acid, metastannic acid, hypooxalous acid, ferricyanic acid, cyanic acid, siliceous acid, hydrocyanic acid, thiocyanic acid, uranic acid, diuranic acid, sulfamic acid, malonic acid, tartaric acid, glutamic acid, phthalic acid, azelaic acid, barbituric acid, benzilic acid, cinnamic acid, fumaric acid, glutaric acid, gluconic acid, hexanoic acid, lactic acid, malic acid, oleic acid, folic acid, propiolic acid, propionic acid, rosolic acid, stearic acid, tannic acid, trifluoroacetic acid, uric acid, ascorbic acid, gallic acid and acetylsalicylic acid. In a more preferred embodiment, the acid is an inorganic acid. The expression inorganic shall mean that the acid does not contain carbon-carbon or carbon- hydrogen bonds.

A particularly preferred embodiment is to use hydrochloric acid.

Another particularly preferred embodiment is to use phosphoric acid. Another particularly preferred embodiment is to use nitric acid.

Another particularly preferred embodiment is to use a synergistic blend of hydrochloric acid and phosphoric acid where the molar ratio is 5 parts of phosphoric acid and 1 part of hydrochloric acid.

Group 3

A surfactant as defined herein is a compound that will decrease the surface tension when added to the aqueous compositions as described herein. In a comparison of the aqueous composition with and without surfactant, the aqueous composition with surfactant needs to have a lower surface tension.

In a preferred embodiment, the surfactant is a compound having an HLB value of between 11 and 16, preferably between 12 and 14. HLB values are determined most accurately using method EN 12836:2002 (Surface active agents - Determination of the water number of alkoxylated products).

The presence of a surfactant is crucial to the success of a sulfide dissolver formulation due to the oil wetting nature of the sulfide scales themselves. In order to gain access to the mineral surface for dissolution, the accumulated oil and other organic solids have to first be removed to allow the subsequent synergistic dissolver components described in group 1 and group 2. Surfactants for use in the present invention typically contain hydrophobic groups such as alkenyl, cycioalkenyi, alkyl, cycloalkyi, aryl, alkyl/aryl or more complex aryl (as in petroleum sulfonates) moieties being from Ce to C22, preferably C10 to C20, typically C12 to C18, and a hydrophilic moiety which preferably is a polyethoxy group with 5 to 20 ethoxy units. Other hydrophobic groups included in the invention are polysiloxane groups and polyoxypropylene groups.

The surfactant may for example comprise or consist of an at least sparingly water- soluble salt of sulfonic or mono-esterified sulfuric acids, e.g. an alkylbenzene sulfonate, alkyl sulfate, alkyl ether sulfate, olefin sulfonate, alkane sulfonate, alkylphenol sulfate, alkylphenol ether sulfate, alkylethanolamide sulfate,

alkylethanolamidether sulfate, or alpha sulfo fatty acid or its ester each having at least one alkyl or alkenyl group with from Ce to C22, more usually C10 to C20, aliphatic atoms.

The expression "ether" here-in-before refers to compounds containing one or more glyceryl groups and/or an oxyalkylene or polyoxyalkylene group especially a group containing from 1 to 150 oxyethylene and/or oxypropylene groups. One or more oxybutylene groups may additionally or alternatively be present. For example, the sulfonated or sulfated surfactant may be sodium dodecyl benzene sulfonate, potassium hexadecyl benzene sulfonate, sodium dodecyl, dimethyl benzene sulfonate, sodium lauryl sulfate, sodium tallow sulfate, potassium oleyl sulfate, ammonium lauryl sulfate, sodium tallow sulfate, potassium oleyl sulfate,

ammonium lauryl monoethoxy sulfate, or monethanolamine cetyl 10 mole ethoxylate sulfate.

Other anionic surfactants useful according to the current invention include alkyl sulfosuccinates, such as sodium dihexylsulfosuccinate, alkyl ether sulfosuccinates, alkyl sulfosuccinamates, alkyl ether sulfosuccinamates, acylsarcosinates, acyl taurides, isethionates, soaps such as stearates, palmitates, resinates, oleates, linoleates and alkyl ether carboxylates. Anionic phosphate esters and alkyl phosphonates, alkylamino and imino

methylene phosphonates may be used. In each case the anionic surfactant typically contains at least one alkyl or alkenyl chain having from Cs to C22, preferably C10 to C20. In the case of ethers, there is one or more glyceryl group, and/or from 1 to 150 oxyethylene and/or oxypropylene and/or oxybutylene groups. Preferred anionic surfactants are sodium salts. Other salts of commercial interest include those of potassium, lithium, calcium, magnesium, ammonium,

monoethanolamine, diethanolamine, triethanolamine, alkyl amines containing up to seven aliphatic carbon atoms, and alkyl and/or hydroxyl alkyl phosphonium.

The surfactant component of the present invention may optionally contain or consist of non-ionic surfactants. The non-ionic surfactant may be e.g. C10 to C22 alkanolamides of a mono or di-lower alkanolamine, such as coconut

monethanolamide. Other non-ionic surfactants which may optionally be present, include tertiary acetylenic glycols, polyethoxylated alcohols, polyethoxylated mercaptans, glucamines and their alkoxylates, glucamides and their alkoxylates, alkylpolyglucacides, polyethoxylated carboxylic acids, polyethoxylated amines, polyethoxylated alkylolamides, polyethoxylated alkylphenols, polyethoxylated glyceryl esters, polyethoxylated sorbitan esters, polyethoxylated phosphate esters, and the propoxylate or ethoxylated and propoxylated analogues of all the aforesaid ethoxylated non-ionics, all having a Cs to C22 alkyl or alkenyl group and up to 20 ethyleneoxy and/or propyleneoxy groups. Also included are

polyoxypropylene/polyethylene oxide block copolymers, polyoxybutylene / polyoxyethylene copolymers and polyoxybuylene/polyoxypropylene copolymers. The polyethoxy, polyoxypropylene and polyoxybutylene compounds may be end capped with, e.g. benzyl groups to reduce the foaming tendency.

Compositions of the present invention may contain an amphoteric surfactant. The amphoteric surfactant may for example be a betaine, e.g. a betaine of the formula (R)3N⁺CH2COO^_, wherein each R may be the same or different and is an alkyl, cycloalkyl, alkenyl or alkaryl group and preferably at least one, and more

preferably not more than one R has an average of from Ce to C20, e.g. C10 to C18 of an aliphatic nature and each other R has an average of from Ci to C₄. Other amphoteric surfactants for use according to the current invention include quaternary imidazolines, alkyl amine ether sulfates, sulfobetaines and other quaternary amine or quaternised imidazoline sulfonic acids and their salts, and zwitterionic surfactants, e.g. N-alkyl taurines, carboxylates amidoamines such as R¹CONH(CH2)2N"(CH₂CH2CH3)2CH2CO-2 and amido acids having, in each case, hydrocarbon groups capable of conferring surfactant properties (R¹ is either alkyl, cycloalkyl alkenyl or alkaryl groups having from Ce to C20 of an aliphatic nature). Typical examples include 2-tallow alkyl, 1 -tallow amido alkyl, 1-carboxymethyl imidazoline and 2-coconut alkyl N-carboxymethyl 2 (hydroxyalkyl) imidazoline. Generally speaking any water soluble amphoteric or zwitterionic surfactant compound which comprises a hydrophobic portion including Ce to C20 alkyl or alkenyl group and a hydrophilic portion containing an amine or quaternary ammonium group and a carboxylate, sulfate or sulfonic acid group may be used in the present invention.

Compositions of the present invention may also include cationic surfactants. The cationic surfactant may for example be a quaternary ammonium compound of the formula:

wherein

is a C5 to C21 aliphatic hydrocarbon group,

is an anionic counter ion, and

are selected from the group consisting of hydrogen, methyl, ethyl allyl, propyl, butyl, phenyl or benzyl residues, Typically alkylammonium surfactants for use according to the invention have one or at most two relatively long aliphatic chains per molecule (e.g. chains having an average of Cs to C20 each, usually C12 to Cis) and two or three relatively short chain alkyl groups having Ci to C₄ each, e.g. methyl or ethyl groups, preferably methyl groups. Typical examples include dodecyl trimethyl ammonium salts.

Benzalkonium salts having one Cs to C20 alkyl group, two Ci to C₄ alkyl groups and a benzyl group are also useful. Another useful class of cationic surfactant according to the present invention comprises N-alkyl pyridinium salts wherein the alkyl group has an average of from Ce to C22, preferably C10 to C20. Other similarly alkylated heterocyclic salts, such as N-alkyl isoquinolinium salts, may also be used. Alkaryl dialkylammonium salts in which the alkylaryl group is an alkyl benzene group having an average of from Cs to C22, preferably C10 to C20 and the other two alkyl groups usually have from Ci to C₄, e.g. methyl groups are useful. Other classes of cationic surfactant which are of use in the present invention include so called alkyl imidazoline or quaternized imidazoline salts having at least one alkyl group in the molecule with an average of from Cs to C22 preferably C10 to C20. Typical examples include alkyl methyl hydroxyethyl imidazolinium salts, alkyl benzyl hydroxyethyl imidazolinium salts, and 2 alkyl-l-alkylamidoethyl imidazoline salts. Another class of cationic surfactant for use according to the current invention comprises the amido amines such as those formed by reacting a fatty acid having C2 to C22 or an ester, glyceride or similar amide forming derivative thereof, with a di or poly amine, such as, for example, ethylene diamine or diethylene triamine, in such a proportion as to leave at least one free amine group. Quaternized amido amines may similarly be employed. Alkyl phosphonium and hydroxyalkyl phosphonium salts having one Cs to C20 alkyl group and three Ci to C₄ alkyl or hydroxyalkyl groups may also be used as cationic surfactants in the present invention. Typically the cationic surfactant may be any water soluble compound having a positively ionized group, usually comprising a nitrogen atom, and either one or two alkyl groups each having an average of from Cs to C22. The anionic portion of the cationic surfactant may be any anion which confers water solubility, such as formate, acetate, lactate, tartrate, citrate, chloride, nitrate, sulfate or an alkylsulfate ion having up to C₄ such as a higher alkyl sulfate or organic sulfonate. Polyfluorinated anionic, nonionic or cationic surfactants may also be useful in the compositions of the present invention. Examples of such surfactants are

polyfluorinated alkyl sulfates and polyfluorinated quaternary ammonium

compounds. Compositions of the current invention may contain a semi-polar surfactant such as an amine oxide e.g. an amine oxide containing one or two (preferably one) Cs to C22 alkyl group, the remaining substituent or substituents being preferably lower alkyl groups, e.g. Ci to C4 alkyl groups or benzyl groups. Particularly preferred for use according to the current invention are surfactants which are effective as wetting agents, typically such surfactants are effective at lowering the surface tension between water and a hydrophobic solid surface. Surfactants are preferred which do not stabilize foams to a substantial extent.

Mixtures of two or more of the foregoing surfactants may be used. In particular mixtures of non-ionic surfactants with cationic and/or amphoteric and/or semi polar surfactants or with anionic surfactants may be used. Typically mixtures of anionic and cationic surfactants are avoided, which are often less mutually compatible. The surfactants in the compositions of the current invention may be used as a bio- penetrant.

Compositions of the invention may also comprise non-surfactant bio-penetrants including any of those described in W099/33345. The non-surfactant bio- penetrant may for example be a quaternary ammonium polymer or copolymer. The quaternary ammonium polymer may for example be any of those described in US. Pat. No. 4,778,813. Particularly preferred is poly [oxyethylene(dimethyliminio) ethylene (dimethyliminio)ethylene dichloride]. This is a copolymer of

Ν,Ν,Ν',Ν', -tetramethyl-1 ,2-diamino ethane with bis(2-chloroethyl) ether, which is commonly referred to as "WSCP". The latter is the commercial name of a product which is sold by Buckman Laboratories. However, any other water soluble polymer containing a plurality of quaternary ammonium groups may be used. Some other typical examples include: Poly [hydroxyethylene(dimethyliminio)ethylene

(dimethyliminio)methylene dichloride], Poly [hydroxyl-ethylene (dimethyliminio)-2 hydroxypropylene (dimethyliminio) methylene dichloride], N-[3-(dimethylammonio)propyl]-N[3(ethyleneoxyethylenedimethylamm

propyl]urea dichloride-4-[1-tris(2-hydroxyethyl)ammonium chloride,

2-butenyl]poly[1 -dimethyl ammonium chloride-2 butenyl]tris(2- hydroxyethyl)ammonium chloride.

The non-surfactant-bio-penetrant may alternatively be a hydrotrope. Hydrotropes are sometimes confused with surfactants because they are also amphiphilic. However hydrotropes do not significantly affect surface tension at low

concentrations. Hydrotropes act as solubilizers. When present in relatively high concentrations (e.g. greater than about 1 wt.-%) they increase the water solubility of sparingly or moderately soluble solutes.

A preferred class of hydrotropes includes water soluble glycol ethers. The glycol ether is preferably a water soluble compound of the formula HO[CR²CR²0]_PR³ where R² and R³ can be methyl, ethyl or preferably H, provided that the total number of carbon atoms per [CR²CR²0] group does not exceed 4, more preferably is not more than 3 and most preferably is 2. R³ is a lower hydrocarbon group such that the compound is water soluble, e.g. butyl, propyl, ethyl or preferably methyl, p is from 1 to 20, preferably 1 to 10, especially 1 to 5, typically 1 to 3, most preferably 2. Preferred examples include diethylene glycol monomethyl ether or 2-butoxyethanol (ethylene glycol monobutyl ether).

An important class of hydrotropes for use according to the current invention comprises the lower alkyl aryl sulfonates. Water soluble salts, e.g. sodium, potassium, ammonium or salts of benzene sulfonic, toluene sulfonic, xylene sulfonic, ethyl benzene sulfonic or cumene sulfonic acids are very effective.

Generally, alkylbenzene sulfonic acids having up to four or even five aliphatic carbon atoms show hydrotropicity but not significant surfactancy. Above six aliphatic carbons, e.g. sodium octyl benzene sulfonate, surfactancy predominates over hydrotropicity. Naphthalene sulfonates are also useful as non-surfactant bio- penetrants, e.g. alkali metal Ci to C alkyl naphthalene sulfonates. Urea is also an effective hydrotrope. One preferred embodiment uses a surfactant including at least one N-Alkyl-N- acylglucamine

whereas in formula (I)

Ra is a linear or branched, saturated or unsaturated C5-C2i-hydrocarbon residue, preferably a C7-Ci3-hydrocarbon residue, and

Rb is a C1-C4 alkyl residue, preferably methyl. In another preferred embodiment, the N-Alkyl-N-acylglucamines (I) comprise at least 50 wt.-% of the total amount of N-Alkyl-N-acylglucamines (I) compounds with C7-C9-alkyl residue and at least 50 wt.-% of the total amount of N-Alkyl-N- acylglucamines (I) compound with C -Ci3-alkyl residue. In another preferred embodiment, the surfactant is including at least one cyclic N-Alkyl-N-acylglucamine of the formulae

whereas in formulae (II; III; IV)

Ra is a linear or branched, saturated or unsaturated C5-C2i-alkyl residue, preferably a C7-Ci3-alkyl residue, and

Rb is a Ci-C₄-alkyl residue, preferably methyl. yet another preferred embodiment, the surfactant is nonyl phenol ethoxylate

wherein n is a number from 1 to 20, but preferably 6 to 15, or more preferably 8 to 12.

Group 4

The addition of a sulfide scavenger serves a two-fold purpose; firstly it scavenges any residual H2S generated as a result of excess H⁺ ions in the synergistic combination of group 1 and group 2 components also comprising a surfactant from group 3; and secondly it increases the efficacy of the dissolution by removing H2S generated from dissolution of sulfide scales and encourages the equilibrium of the reaction to promote further dissociation of sulfide scale by the components in group 1 and group 2, also comprising a surfactant from group 3.

Scavengers that can be included in the formulation include triazine compounds, described by the following formula:

Where R⁴ can be independently selected from the group consisting of Ci to C20 straight or branched alkyl groups, or -R⁵OH, where R⁵ is a Ci to C20 straight or branched alkylene group. Preferably, at least one R⁴ group is a Ci to C20 straight or branched alkyl group and at least one R⁴ group is -R⁵OH.

Further, the scavenger can be selected from a range of hemi-acetal compounds, described by the general formula R⁶R⁷C(OH)OR⁸ wherein R⁶, R⁷ or R⁸ are hydrogen and/or Ci to C20 straight or branched alkyl group. In a preferred embodiment, R⁶, R⁷, R⁸ all are Ci to C20 straight or branched alkyl groups.

Further, the scavenger compound may be selected from hydantoins. Exemplary hydantoins include, but are not limited to hydroxyalkylhydantoins,

bis(hydroxyalkyl)hydantoins, and dialkylhydantoins, where the alkyl group is generally a Ci to C6 alkyl group. Exemplary hydroxyaklyhydantoins use able as the aldehyde-releasing compound include, but are not limited to, 1-hydroxymethyl-5,5- dimethyl-hydantoin also known as monomethylol-dimethylhydantoin (MDMH), 3-hydroxymethyl-5,5-dimethylhydantoin. Exemplary bis (hydroxyl-alkyl) hydantoins useable as the aldehyde-releasing compound include, but are not limited to, 1 ,3-bis(hydroxymethyl)-5,5-dimethylhydantoin as known as

dimethyloldimethylhydantoin (DMDMH). Exemplary dialkylhydantoins useable as the aldehyde-releasing compound include, but are not limited to,

5,5-dimethylhydantoin. In addition, mixtures of the hydantoins may also be used.

Glyoxal (or ethandial) is a dialdehyde that has been shown in the art to scavenge hydrogen sulfide gas (e.g. US-4,680,127) and may also be used in the present invention to scavenge any hydrogen sulfide when contained in a formulation comprising group 1 and group 2 components, with an additional surfactant from group 3.

Zinc carboxylates, such as those described in US-2014/0190870, can also be used in combination with the current invention to provide scavenging of hydrogen sulfide resulting from dissolution of sulfide scales by the synergistic components taken from group 1 and group 2. Specific examples of suitable metal salts include, but are not limited to, zinc chloride, zinc acetate, zinc octoate, a zinc salt containing at least one hydrocarbyl group of at least 4 carbon atoms, such as zinc di-(neo-alkyl)-phosphorodithioate, zinc 2-ethylhexyl isopropyl phosphorodithioate, zinc dihydrocarbyldithiophosphates (ZDDP), zinc hydrocarbyl phosphate, zinc ethyl hexanoate (zinc 2-hexanoate), zinc naphthenates, zinc oleate, zinc carboxylate polymers (e.g. catena-2-ethylhexananto-(O,O')-tri^-2- ethylhexanato(0,0') dizinc (II)), copper salts, cobalt salts, manganese salts, iron salts such as iron chloride, iron carboxylates (e.g. iron oleate), iron neocarboxylates (e.g. iron 2-ethyl hexanoate), iron naphthenates, ferrocene, molybdenum metal salts, and combinations thereof. One specific suitable example is zinc octoate. In one non-limiting embodiment, the metal salts are oil soluble, but it is expected that water soluble (aqueous soluble) metal salts will also be useful. Other transition metal salts including cobalt salts and manganese salts can also be used.

One preferred embodiment of the current invention is to use 1 , 3, 5

Hexahydrotriethanol-1 , 3, 5 Triazine to scavenge hydrogen sulfide gas:

Another preferred embodiment of the current invention is to use the hemiacetal (ethylenedioxy) dimethanol (EDDM):

Yet another preferred embodiment of the current invention is to use

1 ,3-bis(hydroxymethyl)-5,5-dimethylhydantoin as known as

dimethyloldimethylhydantoin (DMD H):

Group 5

Scale and/or corrosion inhibitors may be added to the water separately from or in association with the polyaspartate compounds described in group 1 and surfactants described in group 2. The addition of these components serves to add functionality to the overall product.

Adding a scale inhibitor can prevent either the deposition of unwanted solids that may result from mixing of incompatible waters. Furthermore a batch treatment of the invention fluids entering the reservoir could serve to dissolve sulfide scale and a scale inhibitor squeeze treatment chemical could be contained within the formulation.

The corrosion inhibitor serves to reduce the overall corrosivity of the treatment, protecting the tubulars and production equipment that the dissolver is being deployed into; furthermore a batch treatment of the invention fluids entering the reservoir could serve to dissolve sulfide scales and a corrosion inhibitor squeeze chemical could be contained within the formulation.

Conventional scale inhibitors which may be added to the water to be treated in conjunction with the present invention include, but are not limited to,

1-hydroxyethane-1 ,1-diphosphonates, diethylenetriamine penta(methylene phosphonic acid), nitrilo(methylene phosphonic acid), methacrylic diphosphonate homopolymer, polymaleates, polyacrylates, polymethacrylates, polyphosphates, phosphate esters, acrylic acid-allyl ethanolamine diphosphonate copolymer, sodium vinyl sulfonate-acrylic acid-allyl ammonia diphosphonate terpolymer, acrylic acid-maleie acid-diethylene triamine) allyl phosphonate terpolymer and polycarboxylates, all added to the formulation so that the conventional scale inhibitor present in the water to be treated ranges from 20 to 50 mg/L. Conventional corrosion inhibitors which may be added to the water to be treated in conjunction with the present invention include, but are not limited to soluble zinc salts, nitrates, sulfites, benzoate, tannin, lignin sulfonates, benzotriazoles and mercapto-benzothiazoles amines, imidazolines, quaternary ammonium compounds, resins and phosphate esters, all added to the formulation so that the conventional corrosion inhibitor present in the water to be treated ranges from 50 to 100 mg/L One preferred embodiment of the current invention is to use amino tris(methylene phosphonic acid) as scale inhibitor

Another preferred embodiment of the current invention is to use diethyl triamine penta(methylene phosphonic acid) as scale inhibitor

Yet another preferred embodiment of the current invention is to use tallow alkyl amine ethoxylate as corrosion inhibitor

wherein

o is a number from 4 to 10. Yet another preferred embodiment of the current invention is to use coconut alkyl dimethyl benzyl ammonium chloride as corrosion inhibitor

wherein

R⁹ is alkyl with carbon chain length ranging from Ce to Cie. The composition may additionally contain biocides, for example, formaldehyde or glutaraldehyde, water dispersants, demulsifiers, antifoams, solvents, oxygen scavengers and/or flocculants. There may also be added to the water to be treated oxygen scavengers, flocculants such as polyacrylamide dispersants, antifoams such as acetylenic diols, silicones or polyethoxylated antifoams.

A preferred embodiment of the present invention comprises

10 to 50 wt.-% of at least one polymeric carboxylic acid having a weight average molecular weight from 1 ,500 to 50,000 g/mol, determined by gel permeation chromatography against polystyrene standards, or its salt;

5 to 30 wt.-% of at least one H+ ion releasing monomeric acid having a molecular weight of less than 500 g/mol;

5 to 30 wt.-% of at least one surfactant. 1 to 20 wt.-% of the scavenger species described above in group 4, preferably between 5 and 15%,

1 to 20 wt.-% of the scale and/or corrosion inhibitor species described above in group 5, preferably between 5 and 10 wt.-%.

The remainder of the composition is preferably balanced with water. In a preferred embodiment, the composition has a pH of 0.5 to 4.5 In another preferred embodiment, the composition is essentially free of THPS. The expression "essentially free" shall mean that the composition will contain less than 0.1 wt-%, preferably less than 0.01 wt-% but even more preferably lower than the current occupational exposure limit ( 2 mg/m³ - 8 hour time weighted average).

The inventive composition is preferably applied to a deposit of sulfide scale for application as a sulfide scale dissolver in typical concentrations starting from

50 g/L up to neat product and where relevant in a suitable carrier solvent such as, but not limited to, water, low concentration brines of potassium chloride, calcium chloride or sodium chloride. The exact concentration will depend on the type of sulfide scale, static conditions, materials of construction of the medium being treated, quality of the water being used to make up the inventive solution, temperature of the system and length of time required for dissolution. At this concentration range, the inventive system provides substantial dissolution of the sulfide scale in order to improve the flowability of hydrocarbon production upon removal of the scale.

In another preferred embodiment, the sulfide scale dissolver wherein the inventive composition is present in typical concentrations starting from 50 g/L up to neat product and is essentially free of THPS. The present invention also includes a process for applications using the compositions above for application to be deployed in dissolution of sulfide scales in drilling and the production cycle, particularly as a component of well work-over, well intervention, production enhancement and flow assurance remediation packages.

The injection fluid containing the instant invention may additionally contain other ingredients known to those familiar with the art, including, but not restricted to, acids, dispersants, viscosifiers, lubricity agents, scale inhibitors, friction reducers, crosslinker, surfactants, scavenger, pH adjuster, iron control agents, breakers; this is especially true if any produced water (or recycled water) is used to perform the treatment. Employing the embodiments of the instant invention improves the dissolution of sulfide scales to render it soluble while not corroding the oilfield equipment fouled with sulfide scale, nor yielding high concentrations of hydrogen sulfide gas, and working at very high kinetics. Other applications of the embodiments of the instantaneous invention include treating water for downhole injection for pressure support, treatment of drilling and work-over operations, wettability alteration and well cleanout.

Examples

In the following examples and in the remainder of this specification, percentages are weight percentages relative to the total weight of the respective composition, unless noted otherwise. The same polyaspartate was used throughout the testing, an aspartic acid polymer, sodium salt with Mw of 6,000 Daltons (determined via gel permeation chromatography) and <1 % branching.

EXAMPLE 1 : Reference Examples (all comparative)

Baseline tests were performed in order to understand the performance exhibited by prior art and state-of-the art techniques detailed in the patent literature. The test data for the reference examples has been summarized in Table 3.

Table 3: Baseline tests on sulfide mineral samples using current known art.

No. Dissolver PH Mackinawite Sphalerite Galena Field

Formulation before Weight Loss Weight Loss Weight Scale test (%) (%) Loss Weight

(%) Loss

(%)

1.1 27 % THPS + 0.88 30.42 3.68 2.64 35.34

5 % NH₄CI

1.2 27 % THPS + 1 .88 43.72 3.83 2.83 48.29

5 % IDS 1.3 HCI 20 % -0.78 93.69 87.91 78.12 98.96

1.4 20 % P-Asp 9.12 0 0 0 0

The tests were performed using 50 grams of dissolver solution and 5 grams of mineral sample. All tests were performed at 60 °C and were run for 24 hours. The scale was carefully pre-weighed and then after the test, was dried and prepared accordingly and reweighed thus calculating a weight loss and therefore a dissolution percentage. In all tests 20 % of the main component was used in order to match up activity. NhUCI and IDS were added at 5 % each in the benchmark tests, as indicated is the optimal in the state-of-the-art literature. The dilution water used was deionized.

The performance of polyaspartate (P-Asp) alone is noted to yield zero

performance in dissolving any sulfide mineral tested.

EXAMPLE 2: Polymeric Carboxylic Acid Synergist Two Component System (all comparative)

Individual components were then tested to determine further baseline effects pertaining to the use of polyaspartate and various acids to validate the synergistic effect displayed by adding H⁺ to polyaspartate. The results of various acids (of group 2), acidic scale inhibitors (SI) and corrosion inhibitor (CI) alone to

polyaspartate (of group 1) has been summarized in Table 4.

Table 4: Effect of adding various acids, scale inhibitors and corrosion

inhibitors to polyaspartate to sulfide mineral dissolution.

No. Dissolver Formulation pH ackinawite Sphalerite Galena Field

Weight Weight Weight Scale

Loss Loss Loss Weight

Loss

(%) (%) (%) (%)

2.1 20 % P-Asp 9.12 0 0 0 0 2.2 20 % P-Asp + HCI 0.50 81.23 36.03 15.63 88.68

2.3 20 % P-Asp + H3PO4 2.54 6.91 5.86 3.01 7.44

2.4 20 % P-Asp + GAA 3.98 2.27 1.86 1.20 3.24

2.5 20 % P-Asp + HNO3 0.75 72.39 38.14 12.36 79.43

2.6 20 % P-Asp + Citric acid 4.23 2.21 1.86 1.23 3.16

2.7 20 % P-Asp + Glycolic 4.18 2.43 2.15 1.91 3.21 acid

2.8 7 % Polyaspartate + HCI 1.00 19.06 11.09 8.61 31.49

2.9 7 % Polyaspartate + HCI 0.00 50.78 23.55 19.31 68.21

2.10 7 % Polymer 1 + HCI 1.00 19.74 13.43 9.10 26.44

2.1 1 7 % Polymer 1 + HCI 0.00 80.23 32.19 15.37 86.12

2.12 7 % Polymer 2 1.00 29.90 16.33 1 1.61 41.35

2.13 7 % Polymer 2 + HCI 0.00 67.85 35.27 16.94 71.26

2.14 7 % Polymer 3 1.00 15.67 9.31 4.28 24.91

2.15 7 % Polymer 3 + HCI 0.00 60.29 29.53 14.84 69.88

2.16 7 % Polymer 4 1.00 20.69 12.54 8.97 29.31

2.17 7 % Polymer 4 + HCI 0.00 83.48 31.25 16.17 92.37

2.18 20 % P-Asp + 5 % SI1 2.97 0 0 0 0

2.19 20 % P-Asp + 5 % SI2 2.82 5.65 2.35 0.86 7.65

2.20 20 % P-Asp + 5 % SI3 2.95 4.97 2.16 0.63 6.21

2.21 20 % P-Asp + 5 % CM 6.52 0 0 0 0

The Dissolver Formulation contained the acid constituent other than polyaspartate (P-Asp) as indicated in the table to make a specific pH and the remainder of the formulation up to 100 % was made up with water.

Polymer 1 is a copolymer of maleic acid or maleic anhydrite and sodium allyl sulfonic acid in a 50:50 molar ratio with Mw of 1 ,500 Daltons; Polymer 2 is a copolymer of acrylic acid and maleic acid or maleic anhydrite in a 50:50 molar ratio with Mw of 1 ,800 Daltons;

Polymer 3 is polyacrylic acid homopolymer with Mw of 2,200 Daltons;

Polymer 4 is polyphosphino carboxylic acid with Mw of 2,000 Daltons.

It can be seen that the dissolution power of polyaspartate containing fluids is greatly increased with the addition of acids.

EXAMPLE 3: Systematic Variation in Acid Concentration with Polyaspartate The next stage in the experimental investigation was to determine the relationship of H⁺ addition to polyaspartate by varying systematically the concentration and type of H⁺ source. To show the effect, three acids have been presented:

hydrochloric acid (HCI), phosphoric acid (H3PO4) and glacial acetic acid (GAA) and shown in Tables 5, 6 and 7 respectively.

Table 5: Effect of systematically adding hydrochloric acid to 20 %

polyaspartate.

No. Dissolver Formulation PH Field Scale Weight Loss

(%)

3.1 P-Asp + HCI 3.40 4.81

3.2 P-Asp + HCI 2.14 13.32

3.3 P-Asp + HCI 0.66 31.00

3.4 P-Asp + HCI 0.46 41.02

3.5 P-Asp + HCI 0.32 49.69

3.6 P-Asp + HCI 0.21 57.89 .

3.7 P-Asp + HCI 0.12 67.96

3.8 P-Asp + HCI 0.08 76.53

3.9 P-Asp + HCI -0.07 88.68

3.10 P-Asp + HCI -0.19 92.01 3.11 P-Asp + HCI -0.27 94.83

3.12 HCI 10 % -0.48 95.72

The amount of polyaspartate (P-Asp) is 20 % in every test with HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water. Table 6: Effect of systematically adding phosphoric acid to 20 %

polyaspartate.

The amount of polyaspartate (P-Asp) is 20 % every time with H3PO4 added to achieve the indicated pH and the balance of the formulation to 100 % is water. Table 7: Effect of systematically adding glacial acetic acid to 20 % polyaspartate.

The amount of polyaspartate (P-Asp) is 20 % every time with glacial acetic acid (GAA) added to achieve the indicated pH and the balance of the formulation to 100 % is water.

What the data shows is that when polyaspertate is added, at a much higher pH - by a buffering effect - the same performance in terms of dissolution is achieved. So less acid is needed, less corrosion is caused and less H2S released, finally none of the formulations contain toxic THPS. This can be seen above in Table 7 for example where GAA at pH 1 .99 shows 7.24 % dissolution and if P-Asp is added to buffer it to 3.86 still 7.53 % dissolution is achieved. The same observation is seen with all acids.

It can be seen that the addition of increasing concentration of acid, in order to achieve a progressively lower pH, in all cases resulted in increased dissolution, however this is not a linear relationship. It can be seen that the same sulfide mineral dissolution performance can be achieved at a much higher (less acidic) pH when using a combination of polyaspartate and acid that just acid alone; this indicates a complex complimentary relationship between the acids and the polyaspartate. It can be seen that the stronger the acid, the better the

complimentary relationship. The observed effect is where the polymeric carboxylic acid component does not diminish the acid dissolution and allows as effective dissolution while at the same time providing the same reduction in corrosion rate that one would expect with neutralization or passivation of the pH. The are further benefits observed with kinetics of dissolution that could be discerned visually in the tests that point to a further complimentary relationship between the components of the invention but this has been better quantified in the next example. The influence of the counter ions can not be discounted; however there are no suggestions for a mechanism at this time.

This complexity has been exemplified in Table 8 with the experimental interplay between adding successively increasing concentrations of hydrochloric acid to a fixed concentration of polyaspartate and phosphoric acid, blended in order to achieve a progressively lower pH.

Table 8: Effect of systematically adding hydrochloric acid to 20 %

polyaspartate and 11.8 % H3P0₄ to show the synergy between components.

3.40 P-Asp + HCI + H3PO4 + Surfactant 1.90 30.02

3.41 P-Asp + HCI + H3PO4 1.80 35.01

3.42 P-Asp + HCI + H3PO4 + Surfactant 1.80 34.86

3.43 P-Asp + HCI + H3PO4 1.70 38.92

3.44 P-Asp + HCI + H3PO4 + Surfactant 1.70 39.08

3.45 P-Asp + HCI + H3PO4 1.60 44.77

3.46 P-Asp + HCI + H3PO4 + Surfactant 1.60 44.81

3.47 P-Asp + HCI + H3PO4 1.50 47.29

3.48 P-Asp + HCI + H3PO4 + Surfactant 1.50 46.10

3.49 P-Asp + HCI + H3PO4 1.40 54.98

3.50 P-Asp + HCI + H3PO4 + Surfactant 1 .40 55.63

3.51 P-Asp + HCI + H3PO4 1 .30 57.74

3.52 P-Asp + HCI + H3PO4 + Surfactant 1.30 58.17

3.53 P-Asp + HCI + H3PO4 1.20 61.24

3.54 P-Asp + HCI + H3PO4 + Surfactant 1.20 61.42

3.55 P-Asp + HCI + H3PO4 1.10 67.29

3.56 P-Asp + HCI + H3PO4 + Surfactant 1 .10 67.36

3.57 P-Asp + HCI + H3PO4 1.00 73.23

3.58 P-Asp + HCI + H₃PO₄ + Surfactant 1.00 73.05

3.59 P-Asp + HCI + H3PO4 0.90 85.69

3.60 P-Asp + HCI + H3PO4 + Surfactant 0.90 85.32

The amount of polyaspartate (P-Asp) is 20 % every time with a constant 1 1 .8 % H3PO4 and then HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water. In the tests with surfactant, the amount of polyaspartate (P-Asp) is 20 % every time with a constant 1 1.8 % H3PO4, and 10 % of surfactant, in this case the surfactant was tallow diamine with 10 moles of EO (commercial name 'GENAMIN DAT 100' and then HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water.

EXAMPLE 4: Speed of Dissolution

One of the most unique features of the disclosed sulfide scale dissolvers is the speed to achieve dissolution. When reviewing the prior art, and the formulations disclosed it is apparent that they typically take several hours to achieve optimum dissolution. It is clearly more desirable to achieve rapid dissolution in just a few hours after the dissolving fluid comes into contact with sulfide scales in oilfield operations.

The currently disclosed sulfide dissolvers have been designed with kinetics of dissolution in mind and the previously described weight loss method was adapted in order to test and determine the speed to achieve dissolution.

Several dissolver chemistries were tested in order to determine the speed of dissolution by withdrawing an aliquot of the test fluid at set intervals during the test and measuring the concentration of soluble scaling ions in the fluid as a directly proportional measurement to dissolution efficacy. The results of this

experimentation are shown in Table 9.

Table 9: Effect of systematically adding hydrochloric acid to 20 %

polyaspartate and 11.8 % H3PO4 to show the synergy between components in terms of speed of dissolution.

No. Dissolver pH Iron concentration (mg/L) Field

Formulatio Scale

1 2 3 4 6 24

n Weight hour hours hours hours hours hours

Loss

(%)

4.1 P-Asp + 2.84 1500 1700 1800 1900 2000 2700 7.49 H3PO4 P-Asp + 2.84 1450 1700 1850 1900 2050 2750 7.46 surfactant

HCI 10 % -0.46 1200 2050 3150 4550 7200 32500 95.72

P-Asp + 2.00 5150 5950 6200 6500 6900 9300 25.84 HCI +

P-Asp + 2.00 5200 6000 6100 6450 6900 9300 25.91 HCI + surfactant

P-Asp + 1 .90 6000 6200 7000 7300 7700 10400 29.42 HCI +

P-Asp + 1 .90 6000 6250 7100 7350 7800 10500 30.02 HCI + surfactant

P-Asp + 1.80 6800 7000 7500 7700 8500 12000 35.01 HCI +

H₃P0₄

P-Asp + 1.80 6700 7050 7600 7800 8700 12200 34.86 HCI + surfactant

P-Asp + 1.70 7700 7800 8150 9000 9400 13600 38.92 HCI +

P-Asp + 1.70 7400 7700 8100 9000 9450 13800 39.08 HCI + surfactant P-Asp + 1.60 8500 9200 9250 9800 10000 14250 44.77 HCI +

P-Asp + 1.60 8550 9250 9300 9850 1 1000 14500 44.81 HCI + surfactant

P-Asp + 1.50 9200 9500 10200 10500 1 1500 14550 47.29 HCI +

P-Asp + 1.50 9250 9500 10400 10800 11800 14850 46.10 HCI + surfactant

P-Asp + 1.40 10500 1 1550 1 1800 13000 12500 16300 54.98 HCI +

P-Asp + 1 .40 10550 1 1700 1 1900 13100 14500 16400 55.63 HCI +

H₃P0₄ +

surfactant

P-Asp + 1.30 10950 1 1500 12350 12900 13600 16550 57.74 HCI +

P-Asp + 1.30 11000 1 1600 12400 13000 13700 16700 58.17 HCI + surfactant

P-Asp + 1.20 12100 14250 14500 15100 16200 21000 61 .24 HCI +

H3PO4 P-Asp + 1.20 12000 14300 14600 15000 16200 21050 61 .42 HCI + surfactant

P-Asp + 1.10 13500 15500 16200 17000 17800 23900 67.29 HCI +

P-Asp + 1.10 13700 15800 16500 17400 18000 24150 67.36 HCI + surfactant

P-Asp + 1.00 14500 17000 17500 18300 19350 26150 73.23 HCI +

P-Asp + 1.00 14500 17500 18000 18500 19250 26000 73.05 HCI + surfactant

P-Asp + 0.90 17000 19750 20500 21500 22500 29950 85.69 HCI +

P-Asp + 0.90 17200 20000 21 100 21900 23000 30650 85.32 HCI + surfactant

27% 0.88 420 675 1050 1450 2200 10000 35.34 THPS +

27% 0.90 240 950 1540 2050 33050 13950 48.29 THPS +

5% IDS The amount of polyaspartate (P-Asp) is 20 % every time with a constant 1 1.8 % H3P0₄ and then HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water. In the tests with surfactant, the amount of

polyaspartate (P-Asp) is 20 % every time with a constant 11 .8 % H3PO4, and 10 % of surfactant, in this case the surfactant was tallow diamine with 10 moles of EO (commercial name 'GENAMIN DAT 100' and then HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water.

It can be seen that the examples of the current disclosed invention after just 1 hour contact time contain over 40 times the soluble iron (e.g. Test 4.27) in the

withdrawn aliquot of test solution when compared to the THPS and ammonium chloride (e.g. Test 4.28). This trend continues over the course of 6 hours where the instant invention outperforms the current state-of-the-art inventions. A few noteworthy observations were seen during these tests. The first is that

THPS and IDS together (Test 4.29) yielded a repeatedly slower reaction rate in the first hour of dissolution when compared to THPS and ammonium chloride (Test 4.28), but after 24 hours the THPS and IDS outperformed THPS and ammonium chloride in total dissolution. Secondly, the pH of THPS and ammonium chloride decreased significantly after dissolution of sulfide minerals. In the example in Table 9, the initial pH of 20 % THPS and 4 % NH₄CI was 1.71 and after the test decreased to 1.03. It is hypothesized that at this very low pH, the corrosivity of the resultant fluid is going to be very high and pose a potential integrity risk to the metallurgy of the oilfield systems. The pH of the instant invention on the other hand repeatedly increases after dissolution, typically by 1 whole pH unit in the experiments performed to >pH 2 which represents a much lower integrity risk.

In order to test, experimentally, the corrosivity of the instant invention and the other state-of-the-art chemistries, ASTM standard testing was performed (ASTM G31 -72 and ASTM D471 ) on the fluids, pre- and post-test. Tests were run for 24 hours in a static jar test at 40 °C. The results can be seen in Table 10 and the clear benefit of the instant invention can be discerned. The pH of the acids and the compositions of the instant invention examples were chosen because of their similarities in performance.

Table 10: Corrosivity of the instant invention vs. other disclosed inventions and benchmarks.

In the tests with surfactant, the amount of polyaspartate (P-Asp) is 20 % every time with a constant 1 1.8 % H3PO4, and 10 % of surfactant, in this case the surfactant was tallow diamine with 10 moles of EO (commercial name 'GENAMIN DAT 100' and then HCI added to achieve the indicated pH and the balance of the formulation to 100 % is water. This is with the exception of tests 4.30 and 4.31 which had half the concentration of the aforementioned components with the balance made up to 100 % with water.

EXAMPLE 5: Addition of Surfactant to Combination Polyaspartate and Acid Sulfide minerals, in particular, iron sulfide, are oleophillic, that is preferentially oil wetting. Therefore it is very typical for real field sulfide scales to be coated in hydrocarbon. As the dissolver chemicals are wholly aqueous, the surface of the scales first needs to be water wetted in order to allow access of the dissolver species to the mineral surface. Surfactants are therefore incorporated into the formulation of the instant invention to perform this purpose.

Experiments were performed with sulfide scales that had been exposed first to crude oil in order to oil wet the surface. The samples were then exposed to various formulations of the instant invention in order to determine the effect that

surfactants have on the dissolution. The same weight loss experiment as described previously was used. Results are shown in Table 1 1. All formulations contained 20 % polyaspartate and 1 1.8 % phosphoric acid (termed Dissolver only) and in addition 10 % of a named surfactant. The benefit of having a surfactant when the surfaces are pre-wetted with oil when compared to dissolver packages not containing surfactant. It is not clear to discern a pattern or a model for the different types of surfactant and their relative efficacy. In addition to this investigation on general surfactants, a systematic experiment was performed on a single surfactant hydrotope with varying degrees of ethoxylation. Nonyl phenol was the hydrotope selected as it is well known to those skilled in the art. The degree of ethoxylation was chosen to range from 2 moles up to 20 moles. This way the effect of ethoxylation and therefore relative water solubility could be determined. This can be related back to the hydrophilic- lipophilic balance or HLB which has been indicated, along with the experimental results, in Table 12. It can be seen that there is an optimum HLB for this particular system and this particular oil. Table 1 1 : Experiments on the effect of surfactants on dissolution of oil wetted sulfide scales.

No. Dissolver Formulation Field Scale

Weight Loss (%)

5.1 Dissolver (20 % Polyaspartate + 1 1.8 % H₃P0₄) only 32.48

5.2 20 % THPS + 4 % NH₄CI 21.26 5.3 Dissolver + nonyl phenol + 9EO 54.36

5.4 Dissolver + lauryl alcohol + 12EO 53.67

5.5 Dissolver + octyl phenol + 10EO 53.68

5.6 Dissolver + isodecyl alcohol + 6EO 48.18

5.7 Dissolver + EO/PO block copolymer 40 % EO 43.85

5.8 Dissolver + undecyl alcohol + 7.5EO 51.83

5.9 Dissolver + tridecyl alcohol + 15 EO 51.47

5.10 Dissolver + tallow fatty alcohol + 1 EO 53.48

5.1 1 Dissolver + Oleyl alcohol + 15EO 56.85

5.12 Dissolver + C12/C15 oxo alcohol + 10EO 54.38

5.13 Dissolver + caster oil + 20EO 56.82

5.14 Dissolver + tallow fatty amine + 10EO 54.17

5.15 Dissolver + coconut fatty amine + 10EO 57.25

5.16 Dissolver + oleyl amine + 20EO 52.73

5.17 Dissolver + stearyl amine + 15EO 52.41

5.18 Dissolver + coco alkyl dimethyl benzyl amm. CI 45.69

5.19 Dissolver + naphthenic amidoamine benzyl amm. CI 43.73

5.20 Dissolver + coco amidopropyl betaine Cs / C18 44.27

5.21 Dissolver + salted TOFA:TEPA imidazoline 34.96

5.22 Dissolver + 10 % 2-butoxyethanol 42.62

5.23 Dissolver + 10 % monoethylene glycol 36.91

In the tests with surfactant, the amount of polyaspartate (P-Asp) was 20 % in every test with a constant 1 1.8 % H3PO4 (termed 'dissolver'), 10 % of surfactant mutual solvent (type as indicated), and HCI added to achieve the required pH (1.85), and the balance of the formulation to 100 % is water. Experiments on the effect of different nonyl phenol ethoxylate surfactants on dissolution of oil wetted sulfide scales, systematically varying the EO content.

In the tests with surfactant, the amount of polyaspartate (P-Asp) was 20 % in every test with a constant 11.8 % H3PO4 (termed 'dissolver') 10 % of surfactant (type as indicated), and HCI added to achieve the required pH (1.85), and the balance of the formulation to 100 % is water. EXAMPLE 6: Scavenger Addition to Combination Polyaspartate, Acid and Surfactant

The addition of hydrogen sulfide scavenger to the formulation serves a dual purpose. Firstly it scavenges any hydrogen sulfide gas that may be yielded as part of the dissolution process; secondly, it may serve to increase the efficacy of dissolution by shifting the equilibrium of the reaction by removing water soluble H2S and therefore lowering the concentration allows for the dissolution process to proceed and yield more soluble H2S due to the removal previously by the scavenger.

Three different scavengers were used in experimentation; the results are shown in Table 13. The experiments were performed on the same dissolver package as previously described: 20 % polyaspartate, 1.5 % hydrochloric acid and 1 1.8 % phosphoric acid and in addition 5 % of a named H2S scavenger.

Table 13: Experiments on the effect of different hydrogen sulfide scavengers on dissolution of sulfide scales and evolved gas.

No. Dissolver Formulation Mackinawite H₂S in head S²- + HS-

Scale space in liquid

Weight Loss

(%) (ppm) (ppm)

6.1 Dissolver only

30.42 >50 >50

6.2 Dissolver + 1 , 3, 5

Hexahydrotriethanol-1 , 3, 5 22.37 46 96

Triazine

6.3 Dissolver + (ethylenedioxy)

34.24 24 49 dimethanol (EDDM)

6.4 Dissolver + dimethylol-

33.67 22 43 dimethylhydantoin (DMDMH)

6.5 HCI (10 %) 95.72 >20,000 >20,000

6.6 THPS 27 % + NH4CI 4 % 35.34 >20,000 >20,000 6.7 THPS 27 % + IDS 4 % 48.29 >20,000 >20,000

In the tests with triazine, the term 'Dissolver' represented a formulation in every case of 20 % polyaspartate (P-Asp) with a constant 1 1.8 % H3PO4 and 10 % of a tallow diamine with 10 moles of EO, and HCI added to achieve the required pH (1.85). The H2S scavenger component indicated was added at 10 %

concentration, and the balance of the formulation to 100 % was water.

Claims

PATENT CLAIMS

1. Composition, comprising water and

1. 5 to 50 wt.-% of at least one polymeric carboxylic acid having a

weight average molecular weight from 1500 to 50.000 g/mol, determined by gel permeation chromatography against polystyrene standards, or its salt;

2. 2 to 28 wt.-% of at least one H⁺ ion releasing monomeric acid having a molecular weight of less than 500 g/mol;

3 2 to 30 wt.-% of at least one surfactant.

2. Composition according to claim 1 , additionally comprising at least one hydrogen sulfide scavenger. 3. Composition according to claim 1 and/or 2, additionally comprising at least one scale inhibitor.

4. Composition according to one or more of claims 1 to 3, additionally comprising at least one corrosion inhibitor.

5. Composition according to one or more of claims 1 to 4, wherein the polymeric carboxylic acid is a polyaspartate which is a homopolymer of aspartic acid. 6. Composition according to one or more of claims 1 to 4, wherein the polymeric carboxylic acid is a copolymer in 50:50 molar ratio between allyl sulfonic acid or its salt and maleic acid or maleic anhydride.

7. Composition according to one or more of claims 1 to 4, wherein the polymeric carboxylic acid is a copolymer of acrylic acid and maleic acid or maleic anhydride, wherein the molar ratio is from 50 to 80 mol-% acrylic acid to 20 to 50 mol-% maleic acid or maleic anhydride.

8. Composition according to one or more of claims 1 to 7, wherein the polymeric carboxylic acid has a weight average molecular weight from 1 ,800 up to 20,000 Daltons. 9. Composition according to one or more of claims 5 and/or 8, wherein the amount of a-linkages in the polyaspartate is from 20 to 40 molar %.

10. Composition according to one or more of claims 5, 8 and/or 9, wherein the degree of branching of the polyaspartate is from 1 mol-% to 50 mol-%.

1 1. Composition according to one or more of claims 1 to 10, wherein the H⁺ ion releasing monomeric acid is an inorganic acid.

12. Composition according to one or more of claims 1 to 1 1 , wherein the acid is selected from the group consisting of hydrochloric acid, phosphoric acid and nitric acid.

13. Composition according to one or more of claims 1 to 12, wherein the acid is a blend of hydrochloric acid and phosphoric acid.

14. Composition according to one or more of claims 1 to 13, wherein the surfactant contains an aliphatic or an aromatic residue having 8 to 22 carbon atoms, and 5 to 20 ethoxy groups. 5. Composition according to claim 14, wherein the surfactant is an ethoxylated aliphatic alcohol, an ethoxylated aromatic alcohol or an ethoxylated amine.

16. Composition according to one or more of claims 1 to 13, wherein the surfactant is an anionic surfactant selected from sulfosuccinates, phosphate esters, or alkyl ether sulfonates.

17. Composition according to one or more of claims 1 to 13, wherein the surfactant is a cationic surfactant selected from quaternary alkylammonium compounds. 18. Composition according to one or more of claims 1 to 13, wherein the surfactant is an amphoteric surfactant selected from betaines or sulfobetaines.

19. Composition according to one or more of claims 1 to 18, wherein a hydrotrope selected from the group consisting of

a) water soluble glycol ethers of the formula

HO[CR2CR₂0]nR'

where

each R is methyl, ethyl or H, provided that the total number of carbon atoms per [CR2CR2O] group does not exceed 4, R' is butyl, propyl, ethyl or methyl and

n is from 1 to 20, b) alkyl aryl sulfonates with Ci to C₄ alkyl and C6 to C10 aryl groups, and c) urea is additionally present.

20. Composition according to one or more of claims 1 to 19, wherein a hydrogen sulfide scavenger is present, selected from the group consisting of a) triazine compounds of the formula:

wherein

R is independently selected from the group consisting of Ci to C20 straight or branched alkyl groups, or -R1OH, where Ri is a Ci to C20 straight or branched alkylene group, b) hemi-acetal compounds of the formula RiR2C(OH)OR wherein R, Ri or R2 are hydrogen or Ci to C20 straight or branched alkyl groups, c) hydantoins, d) glyoxal e) zinc carboxylates. 21. Composition according to claim 20, wherein the scavenger is selected from i , 3, 5 Hexahydrotriethanol-1 , 3, 5 Triazine

(ethylenedioxy) dimethanol (EDDM)

and dimethyloldimethylhydantoin (DMDMH)

22. Composition according to one or more of claims 1 to 21 , wherein additionally a scale inhibitor selected from the group consisting of 1- hydroxyethane-1 ,1-diphosphonates, diethylenetriamine penta(methylene phosphonic acid), nitrilo(methylene phosphonic acid), methacrylic diphosphonate homopolymer, polymaleates, polyacrylates, polymethacrylates, polyphosphates, phosphate esters, acrylic acid-allyl ethanolamine diphosphonate copolymer, sodium vinyl sulfonate-acrylic acid-allyl ammonia diphosphonate terpolymer, acrylic acid-maleic acid-diethylene triamine) allyl phosphonate terpolymer and polycarboxylates is added.

23. Composition according to one or more of claims 1 to 22, wherein additionally a corrosion inhibitor selected from the group consisting of soluble zinc salts, nitrates, sulfites, benzoate, tannin, lignin sulfonates, benzotriazoles and mercapto-benzothiazoles amines, imidazolines, quaternary ammonium

compounds, resins and phosphate esters is added.

24. Composition according to claim 22, wherein the scale inhibitor is

or

Composition according to claim 23, wherein the corrosion inhibitor is

wherein n is a number from 4 to 10 or

wherein R is Cs to Cie alkyl.

26. Composition according to one or more of claims 1 to 25, wherein the amount of the polymeric carboxylic acid is from 10 to 50 wt.-%.

27. Composition according to one or more of claims 1 to 26, wherein the amount of the H⁺ ion releasing acid is from 5 to 28 wt.-%.

28. Composition according to one or more of claims 1 to 27, wherein the amount of the surfactant is from 5 to 30 wt.-%.

29. Composition according to one or more of claims 20 to 28, wherein the amount of the hydrogen sulfide scavenger is from 1 to 20 wt.-%. 30. Composition according to one or more of claims 22 to 29, wherein the amount of the scale inhibitor is from 1 to 20 wt.-%.

3 . Composition according to one or more of claims 23 to 29, wherein the amount of the corrosion inhibitor is from 1 to 20 wt.-%.

32. Composition according to one or more of claims 1 to 31 , wherein the surfactant has an HLB value of 11 to 16.

33. Use of the composition according to one or more of claims 1 to 32 as a sulfide scale dissolver for application in oil and gas recovery.

34. Method for dissolving sulfide scale in oil and gas recovery, the method comprising bringing the sulfide scale into contact with the composition according to one or more of claims 1 - 32.

35. Use according to claim 33, wherein the sulfide scale is dissolved from metal surfaces which are in contact with fluids produced from oil and gas wells.

36. Method according to claim 34, wherein the sulfide scale is dissolved from metal surfaces which are in contact with fluids produced from oil and gas wells.