WO2019169375A1 - Synergistic h2s scavenging compositions and methods thereof - Google Patents

Abstract

A production chemical composition may include a polyether polyol; and one or more corrosion inhibitors and/or one or more scale inhibitors. A method may include injecting a composition of a polyether polyol; and one or more corrosion inhibitors and/or scale inhibitors into a production stream, which may be, for example, downhole or subsea. The polyol polyether may include, for example, ethylenedioxy(dimethanol).

Description

SYNERGISTIC H₂S SCAVENGING COMPOSITIONS AND METHODS THEREOF

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is related to U.S. Patent Application No. 62/637,566, filed on

March 2, 2018, which is herein incorporated by reference in its entirety.

BACKGROUND

[0002] Production of oil and gas fields often requires managing the related risks and limitations imposed by reservoir souring upon assets and production integrity. During the production of hydrocarbons from subterranean reservoirs, the downhole environment presents harsh operating conditions for downhole equipment, including high temperatures, pressures and H₂S and C0_2. The downhole conditions can cause corrosion of production tubing and related equipment, and above listed parameters are drivers of this process. In addition to affecting integrity of production tubing, H₂S may also force restriction to production output due to topside related HSE risks and export gas H₂S specifications. This may escalate operational expenditure.

[0003] In the oil and gas industries, it is well known to treat fluid bodies and fluid streams with scavengers to remove hydrogen sulfide (H₂S). H₂S is often present in processes involving the recovery, production or handling of hydrocarbons such as petroleum, petroleum gas and their derivatives. The H₂S may be present in or above the hydrocarbon fluid but also in associated water, e.g. in sea water or underground water mixed with the hydrocarbon.

[0004] The acidity and toxicity of H₂S necessitate its reduction to low levels. To remove it, various processes are known and one of these is to treat the fluid or fluids concerned with a scavenger substance which reacts selectively with the H₂S. During hydrocarbons production, a number of methods may be used to inhibit corrosion and remove H₂S and that may otherwise impact production output and equipment function. One approach to inhibiting corrosion and scavenging H₂S involves the metered injection of corrosion inhibiting chemicals and H₂S scavenging chemicals through chemical injection lines extending from the surface. However, this involves multiple chemical injection lines, chemical injection pumps and tanks that increase capital and operational expenditures.

SUMMARY

[0005] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0006] In one aspect, embodiments disclosed herein relate to a production chemical composition that includes a polyether polyol; and one or more corrosion inhibitors.

[0007] In one aspect, embodiments disclosed herein relate to a production chemical composition that includes a polyether polyol; and one or more scale inhibitors.

[0008] In another aspect, embodiments disclosed herein relate to a method that includes injecting a composition of a polyether polyol and one or more corrosion inhibitors into a production stream.

[0009] In another aspect, embodiments disclosed herein relate to a method that includes injecting a composition of a polyether polyol and one or more scale inhibitors into a production stream.

[0010] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0011] FIG. 1 shows a schematic of Field X production to installation Y.

[0012] FIG. 2 shows a schematic of gas treatment at field Y process.

[0013] FIG. 3 depicts a pie chart of an incumbent corrosion inhibitor formulation, according to the present embodiments. [0014] FIG. 4 depicts a pie chart of a multipurpose H₂S scavenger and corrosion inhibitor according to the present embodiments.

[0015] FIG. 5 shows differential pressure profiles for none-aged and aged multipurpose product according to the present embodiments.

[0016] FIG. 6 shows viscosity profiles for none-aged and aged multipurpose product according to the present embodiments.

[0017] FIG. 7 shows a schematic of the Field X production system with average production rates according to the present embodiments.

[0018] FIG. 8 shows baseline H₂S -distribution through the X separation system according to the present embodiments.

[0019] FIG. 9 shows A2 and H dosages of Product per hour together with measured residuals of EDDM according to the present embodiments.

[0020] FIG. 10 shows Bl dosage of Product per hour together with measured residuals of

EDDM according to the present embodiments.

[0021] FIG. 11 shows total dosage of Product per hour together with measured residuals of EDDM out of the degasser according to the present embodiments.

[0022] FIG. 12 shows all measured EDDM residuals plotted with iron concentration and suspended solids according to the present embodiments.

DETAILED DESCRIPTION

[0023] Generally, the present embodiments relate to compositions and methods of using the same for the treatment of a crude oils, petroleum residua and fuels to selectively reduce the levels of sulfides (such as hydrogen sulfide) present in these systems. More specifically, the present embodiments are directed to a production chemical composition that includes a hydrogen scavenger and one or more corrosion inhibitors. The inventors of the present disclosure have found that hydrogen sulfide scavengers, used in combination with one or more corrosion inhibitors and/or scale inhibitors may have a synergistic H₂S scavenging and a corrosion and/or inorganic scale mitigation effect. In addition, the hydrogen scavengers of the present disclosure may be used in environmentally sensitive areas such as the North Sea, as they are biodegradable and environmentally friendly compared to conventional scavengers such as products of aldehydes and amine compounds. Furthermore, the environmentally acceptable combined formulation of corrosion and/or scale inhibitor(s) and H₂S scavenger may enable higher production rates from the subsea field without modification of the chemical injection system or topside process system. This may be done by allowing full production potential of wells that otherwise would be restricted or completely shut-in due to FhS content in the produced fluids.

[0024] In embodiments using a scale inhibitor, a combined treatment package of a sulfide scavenger and a scale inhibitor may allow for a single formulation to target both sulfides present in a production stream as well as scales or scale-forming components. Solids such as scales present in hydrocarbon-containing produced from subterranean formations may be only slightly soluble at reservoir pressure and temperature. As produced fluids undergo pressure and temperature changes during production, solids may precipitate from the fluids and deposit on downhole tools, pipe wall surface, tubes, tanks, and other equipment. Solid deposition may cause additional operational problems such as poor oil and water separation, increased fluid viscosity, and pressure drops in the production and transportation pipelines; all of which can cause reductions in output and substandard oil and water quality. Deposits on the riser or generally within the production installations reduce output and may even lead to a production standstill. Thus, inclusion of a scale inhibitor may operate, for example, by disrupting the growth of solid particles or other crystalline materials into scales, leading to a decrease in the average size of these insoluble impurities and inhibiting precipitate formation. In addition, chemical additives may also disperse deposited solids and remediate scale buildup. Further, as shown herein, the presently claimed combination of sulfide scavenger and scale inhibitor in fact has a synergistic effect, resulting in a better than expected result using the combined scavenger and inhibitor than individual components.

[0025] While most of the terms used herein will be recognizable to those of skill in the art, the following definitions are nevertheless put forth to aid in the understanding of the present disclosure. It should be understood, however, that when not explicitly defined, terms should be interpreted as adopting a meaning presently accepted by those of skill in the art.

[0026] As defined herein, a scavenger is a treating chemical that is added to a drilling mud or other fluid or a gas to react with a contaminant to change the contaminant to a less harmful compound. If a contaminant is harmful at very low concentration, a scavenger must be able to remove the contaminant to an even lower concentration to ensure safety. As defined herein, a hydrogen sulfide scavenger is a chemical that removes all three soluble sulfide species, H₂S, S ² and HS from a liquid or a gas and forms a product that is nonhazardous and noncorrosive. Frequently, the compositions are reaction products of aldehydes and amine compounds, and may, or may not contain one or more triazine or derivatives thereof. However, these conventional scavengers will increase alkalinity and scale potential due to their amine content.

[0027] As used herein, the term“environmentally acceptable” is defined as chemicals or formulations that can pass the most stringent environmental testing criteria as described below. Furthermore, as used herein, the term“environmentally unacceptable” is defined as chemicals or formulations that do not pass the most stringent environmental testing criteria. Specifically, one measure of sample toxicity is marine biodegradation data as outlined in Organization for Economic Cooperation and Development, Procedure OECD 306 or BODIS. Finder OECD 306, the rules governing offshore chemical use set forth three tests: bioaccumulation, biodegradation and toxicity. For a chemical to be used without restriction offshore in the North Sea it must satisfy two of the following three criteria: (1) biodegradation is greater than 60%, if less than 20% it is automatically marked for substitution; (2) bioaccumulation as measured by octanol/water partitioning coefficient (log Po/w) is below 3 (or have a molecular weight >700); and (3) toxicity to the most sensitive marine species (often Skeletonema) is greater than LC50 or EC50 of 10 ppm. In order to comply with these constraints, components of the wellbore fluids in some embodiments may be selected such that they meet the requirements for biodegradation and aquatic toxicity. At present (and for the last 30 years), the geographic location with the most stringent environmental and discharge testing criteria for well treatment operation is the North Sea, but the definition of either of these terms should in no way be limited to any past, present or future North Sea environmental testing criteria. Further, the test criteria also in no way limit the geographical region of use of the fluid, but provides an indication of the environmental profile of a product (or fluid containing a product).

[0028] As solutions are found useful to provide certain functions in treatment fluids, when used in the North Sea off shore, or other highly regulated off shore environments, stringent requirements for particular off shore environments are met. Any oilfield chemical that is used in the North Sea is registered with the respective country’s regulatory body which assigns a rating or color classification to each chemical depending on its environmental and toxicological characteristics. Based on the chemical rating or color classification, the chemical will either be regarded as more or less environmentally acceptable. In the North Sea, the classification techniques vary. For example, Norway and Denmark follow color classification for chemical products, United Kingdom (UK) follows color and letter ratings for organic and inorganic chemical products, respectively, and Netherlands follows letter categories. Thus, countries within a small geographic region have customized their classification system based upon a desire to differentiate environmentally acceptable chemical products and chemicals noted for substitution. Regardless of the classification system, each of the North Sea countries (Norway, Denmark, Netherlands and United Kingdom) employs the same three ecotoxicology tests criteria, as described above, to differentiate chemical products.

[0029] When each component in a chemical product passes the above-mentioned criteria, then the whole product is rated as“Green” or PLONOR (Pose Little Or NO Risk) in Norway and Denmark. When one of the components only meets two of the criteria, then the product can receive“Yellow” classification in Norway and Denmark, but it is still environmentally friendly. If the biodegradation in seawater is <20% after 28 days for any of the components, then the chemical products receive“Red” classification or substitution warning (z.e., environmentally unfriendly classification in the North Sea). Table 1, below, summarizes the North Sea regulations. As a rule of thumb, two or more “Good” results means that the chemical compounds are acceptable, while two or more “Bad” results means that the chemical compound is unacceptable. However, a chemical compound having less than 20 % biodegradation alone is unacceptable. Depending on the service performed, a well service operation may involve a large amount of chemicals, which means that the introduction of environmentally friendly chemicals may be mandatory.

Table 1. North Sea Regulations Interpretation.

[0030] In one aspect, embodiments disclosed herein relate to production chemical compositions and methods of using the same for treating fluids or gas with the purpose of reducing the level of H₂S therein. According to the present embodiments, the fluid or gas may be selected from the group of petroleum, petroleum products, natural gas, liquefied petroleum gas or other type of oil fraction or refined oil.

[0031] According to the present embodiments, the compositions as described herein are production chemical compositions that may include a hydrogen sulfide scavenger. The selection of the hydrogen sulfide scavenger is performed in such a manner that the scavenger is compatible with the corrosion and/or scale inhibitor(s). The hydrogen sulfide scavengers that have showed utility in the present disclosure are selected from the group of polyols, and more specifically polyether polyols. According to the present embodiments, the polyol may be present in an amount ranging from at least 10 wt% of the production chemical composition, up to 95 wt%.

[0032] In one or more embodiments, the polyol may be ethylenedioxy (dimethanol)

(EDDM) (or dimethylol glycol). Other polyols may include ethylenedioxy (diethanol) or variants including more than one ethylene oxide unit. The amount of ethylenedioxy(dimethanol) or other polyol included in the composition may depend on the amount of H₂S present in the production stream or flow line that may be scavenged. As described later in greater detail, the experimental development work indicates that hydrogen sulfide scavengers, such as EDDM, may be capable of delivering suitable hydrogen sulfide scavenging capacity, while maintaining corrosion inhibitor component performance in one or more embodiments, and in another embodiment EDDM may enhance scale inhibitor performance. Without being bound by the theory, it is believed that EDDM may react with the hydrosulfide (HS ) in the water phase and hence reduce the scale potential for sulfide scales to form.

[0033] According to the present embodiments, the production chemical compositions of the present disclosure may contain one or more corrosion inhibitors. Depending upon the type of corrosion encountered, the corrosion inhibitor may be organic or inorganic or a combination thereof. Non-limiting examples of corrosion inhibitors may include phosphates, silicates, borates, zinc compounds, organic amines (particularly quaternary nitrogen compounds, commonly referred to as quats), betaines, benzoic acid, and benzoic acid derivatives (such as sodium benzoate), phosphate esters, heterocyclic nitrogen and sulfur compounds (such as benzotriazole), organic acids, and the like.

[0034] The corrosion inhibitors that have particular shown utility in the present disclosure may be selected from the group of imidazolines, phosphate esters and ester quats. For example, a quaternary nitrogen containing compound may have the formula (I) or (II):

where n is an integer from 1 to 4; Ri, R₂, R₃, R₄, and R₅ are each independently selected from H, — (C0₂H)_W (i.e., a di-carboxylic acid), — (C0₂R₆)_x (i.e., a di-ester), — (C(=0)NR₇R8)_W (i.e., a di-amido), — C(0)NR₇R₈, — N(H)C(=0)Rs, tetrazolyl, substituted tetrazolyl, alkoxy, dialkoxy, alkyl, substituted alkyl, dialkyl, substituted dialkyl, amine, substituted amine, and combinations thereof; wherein R₆ is a Ci-Cx alkyl or phenyl, R₇ is H or a Ci-C₄ alkyl, Rs is H or a Ci-C₄ alkyl, W is 1 or 2, and X is 1 or 2; Y is selected from napthyl, benzyl, anthracyl, phenanthrinyl, substituted napthyl, substituted benzyl, substituted anthracyl, substituted phenanthrinyl, and combinations thereof; and X is a counterion with a charge sufficient to balance the positive charge on the compound of the general formula (I); or

wherein Xi and X₂ are independently an alkyl or hydroxyalkyl group containing 1-4 carbon atoms, or -(A)COOR; X₃ is an alkyl group containing 1 to 6 carbon atoms, a hydroxyalkyl group containing 1-4 carbon atoms, an alkenyl group containing 2 to 6 carbon atoms, an aryl (e.g. a C5-20 aryl group, or C₆-io aryl group), or an aralkyl group (e.g. a C1-6 alkyl-C₅-2o aryl or Ci_-6 alkyl-C₆-io aryl) or; A is an alkylene group with 2 or 3 carbon atoms or an alkylene oxide group with 2 to 4 carbon atoms; each R is independently an alkyl group containing from 5 to 23 carbons atoms or an alkenyl group containing from 7 to 23 carbons atoms and 1, 2 or 3 double bonds; and Q^z is an anion of charge -z where z is 1, 2 or 3.

[0035] Imidazolines may be formed by the condensation of a polyethylene amine with an acid or ester (specifically a fatty acid or ester thereof) to result in an imidazoline (and an amidoamine), such as described in W02016092010, which is incorporated by reference in its entirety. Whether a first of the nitrogen atoms is substituted may depend on the length of the polyethylene amine. Further, it is also understood that the resulting imidazoline may also be acrylated, such as described in U.S. Patent No. 7,057,050, which is incorporated by reference in its entirety.

[0036] Phosphate esters may be of the general formula (III):

wherein R_a, R_b and R_c are each H or a hydrocarbon group which may contain oxygen or nitrogen atoms with a carbon atom number ranging from 1 to 49. In particular embodiments, the R_a, R_b and R_c may include optional alkylene oxide groups terminated with a long (0,-0, o) alkyl, alkenyl, aryl, or arylalkyl chains, optionally substituted with hydroxyl, benzyl or carboxylic acid groups, or optionally containing intra-hydrocarbon chain groups such as carboxyl group (-C00-), oxygen (-0-), or a secondary amine group (-NH-).

[0037] In one or more embodiments, the corrosion inhibitor(s) may be present in the production chemical composition in an amount ranging from 5 to 50 wt% of the composition. Further, as noted above, corrosion inhibitor(s) may be used in combination with a hydrogen sulfide scavenger. In one or more embodiments, the hydrogen sulfide scavenger is ethyl enedioxy(dimethanol). As previously discussed, at least 10 wt% of the composition may be the ethylenedioxy(dimethanol). The amount of ethylenedioxy(dimethanol) included in the composition may depend on the amount of FhS present in the production stream or flow line that may be scavenged. For example, in one or more embodiments, for each kilo of FhS that was present, 1.6-15 kilo EDDM may be used. Thus, where a lower amount of EDDM is needed, the balance of the composition may be a solvent, such as, but not limited to water or glycol.

[0038] The inventors of the present application have found that the combination of a FhS scavenger and one or more corrosion inhibitors may have a synergistic effect in downhole applications. Specifically, by using a FhS scavenger, such as ethylenedioxy(dimethanol) (EDDM), with one or more corrosion inhibitors, a synergistic FhS scavenging and FhS and corrosion mitigation may occur, particularly in subsea and downhole applications. Without being bound by the theory, it is believed that a hydrogen scavenger, such as EDDM, upon reaction with FhS, may form thiols, specifically thiocarbonyls, which may function as either sulfur synergist or corrosion inhibitor on its own or in combination with the corrosion inhibitors described herein.

[0039] The inventors of the present application have found that the combination of a H₂S scavenger and one or more scale inhibitors may have a synergistic effect. Specifically, by using a H₂S scavenger, such as ethylenedioxy(dimethanol) (EDDM), with one or more scale inhibitors, a synergistic H₂S scavenging and H₂S and scale mitigation may occur, particularly in subsea and downhole applications.

[0040] Scale Inhibitor

[0041] In one or more embodiments the scale inhibitor may be selected from a polyamide

(such as polyaspartate or polyaspartamide), polyamidoamine, polyethyleneimine, polyetthyloxazoline, polyphosphate, polyacrylates or copolymers thereof, polymethacrylates, polyamine base or a combination of 1 -hydroxy ethane- 1,1- diphosphonates, organophosphoric acid (such as diethylenetriamine penta(methylene phosphonic acid), nitrilo(methylene phosphonic acid), or hydroxyethylidene diphosphonic acid), methacrylic diphosphonate homopolymer, polymaleates, 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, poly-maleic acid, polycarboxylates, polysaccharide-based polycarboxylates, carboxymethyl inulin biopolymers, cationic inulin, starch based biopolymers, sulfonated polyacrylic acid co- polymer or any combination of the above.

[0042] In one or more embodiments, the scale inhibitor(s) may be present in the production chemical composition in an amount ranging from 5 to 50 wt% of the composition. Further, as noted above, scale inhibitor(s) may be used in combination with a hydrogen sulfide scavenger. In one or more embodiments, the hydrogen sulfide scavenger is EDDM. As previously discussed, at least 10 wt% of the composition may be the EDDM The amount of EDDM included in the composition may depend on the amount of H₂S present in the production stream or flow line that may be scavenged. For example, in one or more embodiments, for each kilo of H₂S that was present, 1.6-15 kilo EDDM may be used. Thus, where a lower amount of EDDM is needed, the balance of the composition may be a solvent, such as, but not limited to water or glycol.

[0043] Furthermore, while conventional compositions may necessitate the incorporation of glycols such as to provide cold weather properties (avoid freezing) and makes product suitable for subsea or downhole injection (avoid hydrate formation), as well as sulfur synergists, the present compositions may achieve the desired results without such inclusion, thus providing for better HSE properties. That is, the present inventors have found that hydrogen sulfide scavengers such as EDDM may decrease the freezing temperature of chemical mixtures and may prevent hydrate formation. In one or more embodiments, the production chemical composition is substantially free of glycols. In yet another embodiment, the production chemical composition is substantially free of sulfur synergists. Without being bound by the theory, the inventors of the present application believe that the hydrogen scavenger of the present disclosure, such as EDDM, may exhibit hydrate inhibition properties and solvents such as glycol may be removed from the formulation, allowing the multipurpose product to be more cost-efficient.

[0044] However, it is also envisioned that glycol may be included in the present production chemical composition when the amount of H₂S present in the fluid to be treated is sufficiently low that it is not desired to have up to 90 wt% of the composition being hydrogen sulfide scavenger, such as EDDM. Thus, in that instance, glycol (or water) may be included to obtain the appropriate dilution.

[0045] Glycol is generally present in all conventional formulations, such as to provide cold weather properties (avoid freezing) and makes product suitable for subsea or downhole injection (avoid hydrate formation). However, in the present formulation, its inclusion may only be when the amount of H₂S present is sufficiently low that it is not desired to have up to 90 wt% of the composition being EDDM. Thus, in that instance, glycol (or water) may be included to obtain the appropriate dilution. Cold weather properties, however, may be achieved without the necessitation of glycols being present. That is, the present inventors have found that EDDM decreases the freezing temperature of chemical mixtures and prevents hydrate and scale formation [0046] Upon mixing, the production chemical compositions of the present embodiments may be used for treating a fluid or a gaseous stream of hydrocarbons with the purpose of reducing or removing the sulfides therein. Such operations are known to persons skilled in the art and involve bringing the production chemical composition as described herein into contact with a body of liquid and/or a gaseous stream of hydrocarbons having hydrogen sulfide container therein. The liquid or gas body may be a static body or a flowing stream. One skilled in the art would appreciate that the methods and blends of the present disclosure are applicable to a wide variety of fluid streams, including liquefied petroleum gas as well as crude oil and petroleum residual fuel, heating oil, etc., as well as gaseous hydrocarbon streams. For instance, the scavenger may be contacted with wet or dry gaseous mixtures of hydrogen sulfide and hydrocarbon vapors, such as is found in natural gas or obtained in the drilling, removal from the ground, storage, transport, and processing of crude oil. In one or more embodiments, the liquid or gas body may be selected from the group of petroleum, petroleum products, natural gas, liquefied petroleum gas or other type of oil fraction or refined oil. Moreover, the fluid body or stream may comprise water, such as underground water or sea water involved in a hydrocarbon recovery process such as oil drilling. The point at which the production chemical combination is introduced into the fluid may be determined in accordance with conventional practice.

[0047] One embodiment of the present disclosure includes a method, such as a method to remove or reduce significant amounts of H₂S from produced fluids during transit via subsea production pipelines. In one or more embodiments, the method is a treating method of a fluid or a gaseous stream of hydrocarbons to remove or reduce the hydrogen sulfide content in a fluid or a gas.

[0048] It is also envisioned that the production chemical compositions as described herein may be used for scavenging H₂S during multiphase flow while maintaining corrosion and/or scale inhibitor.

[0049] One embodiment of the present disclosure includes a method, such as a method of injecting a production chemical composition. In such an illustrative embodiment, the method may involve injecting a production chemical composition into a production stream. In one or more embodiments, the production chemical composition may be injected downhole or subsea. In one or more embodiments, the production chemical composition as described herein may be injected into a stream that is less than 40°F. According to the present embodiments, the production chemical composition may be injected at a dosage ranging from about 1 ppm to about 500 ppm.

[0050] EXAMPLES

[0051] The following examples are presented to further illustrate the properties of the production chemical compositions as described herein.

[0052] Specifically, a novel multiphase FES scavenger was incorporated into an incumbent subsea corrosion inhibitor and incumbent scale inhibitor. The experiments included identification of suitable multiphase scavenging chemistry, tailoring of the multipurpose chemical to retain corrosion inhibition properties, and confirmation that the chemistry did not deleteriously impact performance of other production chemicals used nor the production process itself. The qualification work supported a full-scale field test that demonstrated suitability of the new multipurpose chemical.

[0053] Field X located in the Norwegian Continental Shell consists of several deposits and has been developed with seven subsea templates and two satellite wells. The field is produced by pressure support using water injection. Field X well stream is routed to installation Y through high- (A2) and the low- (Bl) pressure lines. FIG. 1 describes the process and the chemical injection points 100. Referring now to FIG. 1, 110 represents the stream directed to the Y gas process. The actual subsea system is more complex with a distribution of the chemical over several templates. Additionally, cyclones, floatation unit and recirculating flows are omitted from this figure for simplification.

[0054] Field X gas process system is not directly treated with FES-scavenger. This is compensated by overdosing triazine-based FES scavenger into the field Y gas, before the two gas streams are commingled (FIG. 2). Referring now to FIG. 2, 200 represents the triazine-based FES scavenger injection, while 210 represents the stream directed to the Y gas process. While this has been an acceptable solution in the past, however, due to the increasing H₂S production from the X wells, several challenges have resulted in choked down wells at the field X. The three most troubling concerns are:

1) It is not possible to treat the gas phase efficiently enough via the existing triazine- based H₂S scavenger injection system, resulting in H₂S above export gas specifications.

2) The gas phases in the low-pressure parts of the process system, e.g. degasser, have H₂S concentrations in range of 2000-3000 ppm, which represents increased health and safety risks when sampling or performing maintenance tasks.

3) Discharges of the overdosed triazine-based H₂S scavenger contribute to 20% of the Environmental impact factor (EIF) of fields X and Y.

[0055] Mitigation of H₂S produced by X wells had to be implemented upstream of the X process. Based on similar experiences with two Y wells, a subsea applied multiphase H₂S scavenger was selected as a way forward. Due to limited availability of chemical injection lines, the product had to be multipurpose, and in addition to H₂S scavenging capabilities it had to maintain corrosion and/or scale protection of the low- and high- pressure production flowlines at the level comparable to the incumbent subsea corrosion and/or scale inhibitor. In addition, the product had to be suitable for the subsea deployment and proving no negative impact on chemical injection system, production process or other production chemicals used.

[0056] Moreover, because chemicals are subject to strict regulations encountered in the

Norwegian sectors of the North Sea, the new combined H₂S scavenger formulation had to be tailored in a way to satisfy environmental regulation to be awarded as environmentally acceptable [e.g., biodegradable (> 60% in 28 days), non-bioaccumulativity (log Pow <3) and have a low toxicity level (<10 mg/1)]. As EDDM has hydrate inhibition properties, it was possible to remove glycol from the formulation, allowing the multipurpose product to be more cost-efficient.

[0057] Several multiphase H₂S scavengers were screened for multiphase application on subsea field X. The main challenge for some scavengers was the compatibility with amine-based corrosion inhibitors and scale inhibitors. Those scavengers nullified corrosion inhibitors performance while also some were physically incompatible with corrosion inhibitors. EDDM chemistry showed that it can deliver suitable H₂S scavenging capacity while not disrupting corrosion and/or scale inhibitor performance. While many other chemistries were majorly affected or even nullified performance of the amine-based corrosion inhibitor, EDDM allowed further optimization of the formulation increasing robustness of the final product, as shown below in Table 2).

Table 2. Corrosion inhibition performance of incumbent corrosion inhibitor versus combinations of three multipurpose EES scavenger and corrosion inhibitor. Information generated in rotating cage testing at 72°C, 0.99 bar C0₂, 28.5 g/1 NaCl, 23.65 mmol/l total alkalinity with 7.86 mmol/l acetate.

[0058] As EDDM has hydrate inhibition properties, it was possible to remove glycol from the formulation, allowing the multipurpose product to be more cost-efficient. Moreover, corrosion inhibition performance testing in H₂S containing environments demonstrated negligible contribution of some aids and synergists in the formulation, allowing further optimization of the final product as shown below in Table 3.

Table 3. Corrosion inhibition performance of incumbent corrosion inhibitor versus multipurpose H₂S scavenger and corrosion inhibitor. Information generated in rotating cage testing at 80°C, 20 Pa, 0.55 bar C0₂, 0.14 bar H₂S, 28.5 g/1 NaCl, 12.3 mmol/l total alkalinity with 6.1 mmol/l acetate.

*100 ppm of multipurpose product contains comparable amount of amine filmer as 30 ppm of incumbent corrosion inhibitor

[0059] In addition to the laboratory generated information, knowledge about the amount of H₂S required to be scavenged upstream field X process may be considered when tailoring the final product. A detailed H₂S mass balance revealed the amount of H₂S produced and amount of EDDM required to be injected to the low- and high-pressure X flowlines to scavenge H₂S to an acceptable level. Moreover, the amount of amine filmer in the novel product should not have negative impact on the separation process topside, and hence it was desirably maintained at the level present in the incumbent corrosion inhibitor.

[0060] Referring now to FIGS. 3 and 4, FIGS. 3 and 4 depict simplified pie charts of incumbent corrosion inhibitor formulation (FIG. 3) and a multipurpose H₂S scavenger and corrosion inhibitor according to the present disclosure (FIG. 4). These composition representations demonstrate how the glycol solvent was minimized in the final product formulation.

[0061] A maturity assessment was performed based on previous experience with EDDM based products. Tests with the incumbent corrosion inhibitor and with EDDM in Sapphire Rocking Cell (SRC) provided confidence for proceeding towards a field test. However, the following investigations had to be completed before moving forward with multipurpose product: 1) materials compatibility testing; 2) long term thermal stability testing with final formulation; 3) interaction of multipurpose product with incumbent topside scale inhibitor crucial for minimizing deleterious impact of iron scales and related separation challenges. [0062] The chemical corrosivity towards 316 stainless steel and carbon steel grade

C1018 specimens was investigated by exposing specimens to neat chemical at 20°C and 90°C for 30 days. In these tests, the general corrosion and tendency to pitting was assessed based on ASTMG31 - l2a. The results are shown below in Table 4. The compatibility of the chemical towards different elastomers present in the injection line was also tested, with the results given in Table 5, below.

Table 4. Alloys compatibility for product with 316 stainless steel and C1018 carbon steel in 30- day immersion.

*Tested for information only, there is no carbon steel in contact with the lean chemical

Table 5. Compatibility results for immersion of elastomers and plastic to neat product for 14.

days at 20°C.

[0063] Long term stability test at -10, 4, 20 and 90°C was performed for 30 days. At the end of the 30 day period, kinematic viscosity curves were obtained for the multipurpose product exposed at four different temperatures. The viscosity was lower than 200 cP at 4°C in all scenarios. Moreover, the multipurpose product was submitted to filtration test pre-and post-exposures at 4°C for 4 and 8 weeks. The product was filtered through a 2 pm filter prior to performing the pre-aging filter test and the subsequent dynamic scale loop (DSL) test. The obtained differential pressure profiles and kinematic viscosity curves are shown in FIGS. 5-6, respectively. Referring now to FIG. 5, the test was performed at 25°C, 5.5 bar, using 1.5 mm OD/ 0.75 mm ID alloy coil and 2 pm filter for 5 filtration cycles. Referring now to FIG. 6, FIG. 6 depicts viscosity profiles for none- aged and aged multipurpose product. Lack of major changes in differential pressure during filtration or viscosity curves were also recorded, as seen in FIG. 6. [0064] Interaction of combined H₂S scavenger and corrosion inhibitor product with an incumbent topside scale inhibitor was investigated with DSL testing. Test conditions and pass/fail acceptance criterion applied in DSL testing is shown below in Tables 6 and 7.

Table 6. Test condition and pass/fail acceptance criterion applied in DSL testing.

Table 7. Water composition used for DSL testing (representative for the field X).

[0065] An EDDM multipurpose composition containing a corrosion inhibitor in combination with a polyaspartate incumbent scale inhibitor was tested. Dynamic tube blocking tests results are presented below in Table 8. There are some variations between the tests, but not more than what fits inside the margins of error in the test procedure. Findings suggested lack of nullifying interaction between chemistries when introduced in the process stream.

Table 8. Dynamic tube blocking tests.

[0066] Production from the H-template wells was routed to the A-2 line during the test.

The retention time in the subsea production system was 4 to 6 hours, depending on the location of each template. Schematic of the field X production system with average production rates is provided in FIG. 7. Referring now to FIG. 7, 700 represents the chemical injection points, while 710 represents the stream directed to the Y gas. G-4 has no water, hence no corrosion inhibitor injection occurs yet at 720. As seen in FIG. 7, the gas 730 includes 2% water, while 740 includes 1% water.

[0067] The FhS concentrations were measured at the gas outlet of each process unit in addition to a range of other analysis performed onshore on water and oil samples. To get the FhS mass balance as accurately as possible, the water chemistry and C0₂ concentration in the gas may be considered. Water compositions as analysed and used in simulations are shown in Table 9, below.

Table 9. Water composition used in calculations.

[0068] The pH of the water in the separator is one of the parameters to be considered for the mass balance. Table 10 shows the conditions and the calculated pH values at equilibrium, based on measurements of C0₂ concentration in the gas, performed under this field test. It also depicts the pH values used in the mass balance (estimated real pH).

Table 10. pH calculations based on multiphase equilibrium.

[0069] An H₂S distribution model has been used to calculate the amount of H₂S being produced in the A-2 and B-l flowlines. The model is based on multiphase equilibrium program that considers the phase distribution of the gases and includes water evaporation. Previous H₂S scavenger tests have proved that the model is accurate enough for this purpose, and much easier to use than a full multiphase equilibrium study.

[0070] FIG. 8 shows the process schematic with the amount of H₂S produced in total from each line and the distribution in the three phases through the process. Referring now to FIG. 8, 810 represents hydrogen sulphide to gas phase 250 ppm-50 kg/d, 820 represents H₂S to gas phase 495 ppm-l l l kg/d, while 830 represents H₂S to gas phase 2800 ppm-2l6 kg.

[0071] In the model, gas outlet rate of the degasser was adjusted to 54400 Sm³/d to fit the model with the measured H₂S concentration and calculated pH in the degasser. The real gas flow at this point was closer to 20000 Sm³/d, hence the amount of H₂S following the oily water back to the two stage separator was most likely underestimated.

[0072] This was used as baseline data and similar mass balance calculations are calculated for selected dosages of the multipurpose product injected to the X subsea templates. Table 11 shows the dosages in litres per day, ppm with regards total fluids and ppm with regards to water phase.

Table 11. Main dosages of multipurpose product tested in litres per day and ppm(v).

[0073] Table 12, below, shows the amount of injected EDDM compared to the amount of

H₂S removed, based on the mass balance.

Table 12. ThS-scavenger efficiency data for the EDDM part of the product.

[0074] The efficiency for the Bl line was increased compared tor the A2 line. This can be explained by higher pH, which results in more H₂S available in the water phase where the reaction takes place. This was confirmed by the sulphide ion concentration measured in the two separators. In addition, there were several recirculation flows back to the two- stage separator, allowing more time for the reaction.

[0075] The injection dosages and measured residuals are shown in FIGS. 9-11.

Specifically, FIG. 9 depicts A2 and H dosages of product per hour together with measured residuals of EDDM, while FIG. 10 depicts the Bl dosage of product per hour together with measured residuals of EDDM. FIG. 11 depicts the total dosage of product per hour together with the measured residuals of EDDM out of the degasser.

[0076] The ratio between the injected amount of EDDM injected and the residual EDDM

(unreacted) analysed for each flowline were approximately the same, spent EDDM showing 36-47%. [0077] The injection of the polyaspartate based scale inhibitor was unaltered and stable during the test period. Residual measurements were stable, e.g. 15-20 ppm for the first stage separator and 50 ppm for the second stage separator.

[0078] The ion analysis data shows relatively stable values with variations within the accuracy of the measurement methods. Interestingly, the iron concentration increases slightly with increasing dosages of EDDM. At the same time, suspended solids measured in the system were reduced, as seen in FIG. 12. Without being bound by the theory, it is believed that this indicates that EDDM presence in the system improves control of iron sulfide scales by reducing the concentration of sulfide available in the water phase.

[0079] As shown above, a multiphase FES scavenger was successfully incorporated into the incumbent subsea corrosion inhibitor. The new product was tailored to retain suitable corrosion inhibition properties. In addition, this new chemistry did not impact the performance of the other production chemicals used nor the production process itself.

[0080] The new combined formulation of corrosion inhibitor and FES scavenger enables higher production rates by allowing increased production rates of main FES contributing wells. This was achieved without any requirements for modification of the chemical injection system or topside process system. In addition, the reduction of available sulfide in the water reduced the precipitation of iron sulfides previously shown to be a challenge for the water treatment process topside.

[0081] Advantageously, embodiments of the present disclosure may provide production chemical compositions that include a FES scavenger and one or more corrosion inhibitors and /or scale inhibitors that may exhibit a synergistic FES scavenging and a corrosion/scale mitigation effect. Another aspect of the present disclosure is that the production chemical compositions as described herein may be used in environmentally sensitive areas such as the North Sea, as they are biodegradable and environmentally friendly compared to conventional scavengers. Furthermore, the environmentally acceptable combined composition of corrosion inhibitor(s) and FES scavenger may enable higher production rates from the subsea field without modification of the chemical injection system or topside process system. Additionally, it indicates that polyaspartate has a reduced impact without EDDM in the system and that there is a demonstrable synergistic effect that is achieved by incorporating both polyaspartate and EDDM in the same system.

[0082] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 ET.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

CLAIMS What is claimed:

1. A production chemical composition, comprising:

a polyether polyol; and

at least one selected from a corrosion inhibitor and/or a scale inhibitor.

2. The composition of claim 1, wherein the polyether polyol comprises ethylenedioxy(dimethanol).

3. The composition of claim 1, wherein the one or more corrosion inhibitors are selected from the group of imidazolines, phosphate esters and ester quats.

4. The composition of claim 1, wherein the one or more scale inhibitors are selected from polyamides, poly acrylates, polyaspartate, polyamines, polyamidoamines, polyethyleneimines, polyphosphates, sulfonated polyacrylic acid co-polymer or a combination thereof.

5. The composition of claim 1, wherein the one or more scale inhibitors is polyaspartate.

6. The composition of claim 1, wherein the one or more corrosion inhibitors is present in an amount up to 50 wt% of the composition.

7. The composition of claim 1, wherein the one or more scale inhibitors is present in an amount from 5 wt% up to 50 wt% of the composition.

8. The composition of claim 1, wherein the polyether polyol is present in an amount ranging from at least 10 wt% to 95 wt%.

9. The composition of claim 1, wherein a balance of the production chemical composition is a solvent.

10. The composition of claim 9, wherein the solvent is selected from water or a glycol.

11. The composition of claim 1, wherein the production chemical composition is substantially free of sulfur synergists.

12. The composition of claim 1, wherein the production chemical composition is substantially free of glycols.

13. A method, comprising:

injecting the composition of claim 1 into a production stream.

14. The method of claim 13, wherein the composition is injected downhole or subsea.

15. The method of claim 13, wherein the composition is injected into a stream that is less than 40°F.

16. The method of claim 13, wherein the composition is injected at a dosage ranging from 20 to 500 ppm.

17. The method of claim 13, wherein the one or more corrosion inhibitors are selected from the group of imidazolines, phosphate esters and ester quats.

18. The method of claim 13, wherein the one or more scale inhibitors are selected from polyamides, polyacrylates, polyamines, polyphosphates or a combination thereof.

19. The method of claim 13, wherein the one or more corrosion inhibitors is present in an amount up to 50 wt% of the composition.

20. The method of claim 13, wherein the polyol polyether comprises ethylenedioxy(dimethanol).