Solids prevention in the scavenging of h2s

Abstract

A fluid composition includes a sulfide scavenger formulation to reduce a concentration of one or more sulfide species in a production stream and a solids control additive to reduce solid formation in the production steam as a result of reaction of the sulfide scavenger formulation and the one or more sulfide species.

Description

IS24.1495-WO-PCTSOLIDS PREVENTION IN THE SCAVENGING OF H2SBACKGROUND

[0001] The present disclosure generally relates to systems and methods for reducing solids in the scavenging of sulfide specifies during fluid treatment.BACKGROUND

[0002] The present disclosure generally relates to systems and methods for reducing solids in the scavenging of sulfide specifies during fluid treatment.

[0003] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and / or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it may be understood that these statements are to be read in this light, and not as admissions of prior art.

[0004] During oil and gas production, harsh operating conditions including high temperature, pressures, and presence of unwanted species such as hydrogen sulfide (H2S), carbon dioxide (CO2), carbon monoxide (CO), nitrogen dioxide (NO2), and / or sulfur dioxide (SO2) may be present. Such harsh conditions may lead to corrosion of production tubing and related equipment. Further in some cases, health and safety specifications (e.g., governmental regulations) may include restrictions on amounts of unwanted species in production fluids. For example, sulfide species such as H2S may be present in processes involving recovery, production, and / or handling of hydrocarbons and their derivatives. Acidity and toxicity of sulfide species may warrant reduction of sulfide species within production fluids. To remove sulfide species from production fluids, scavenger chemistry formulations may be introduced through chemical injection, pumps, tanks, and the like. Unfortunately, sulfide species remediation systems may induce solid formation within production fluid which may lead to flow inhibition and / or blockages of production fluids thatIS24.1495-WO-PCT may add significant costs to oil and gas operations. Thus, a need exists to reduce solid formation within production fluids during fluid treatment operations.SUMMARY

[0005] A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

[0006] In certain embodiments, a fluid composition is provided. The fluid composition includes a sulfide scavenger formulation to reduce a concentration of one or more sulfide species in a production stream and a solids control additive to reduce solid formation in the production stream as a result of reaction of the sulfide scavenger formulation and the one or more sulfide species.

[0007] In certain embodiments, a method is provided. The method includes introducing a treatment fluid at an inlet of a production stream, wherein the treatment fluid comprises a sulfide scavenger and a solids control additive, reducing, via the sulfide scavenger of the treatment fluid, a concentration of H2S in the production stream and inhibiting, via the solids control additive of the treatment fluid, solids formation in the production stream.

[0008] In certain embodiments, a system is provided. The system includes a fluid treatment system including one or more tanks, a fluid injector, and a controller. The controller is configured to receive a sulfide scavenger at the one or more tanks and receive a solids control additive at the one or more tanks. The controller is also configured to generate a treatment fluid based on mixing the sulfide scavenger and the solids control additive and inject, via the fluid injector, the treatment fluid into a pipeline comprising a production stream, wherein injection of the treatment fluid is configured to reduce a concentration of H2S in the production stream and reduce solids formation in the production stream.IS24.1495-WO-PCT

[0009] Various refinements of the features noted above may exist in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

[0011] FIG. l is a schematic diagram of an embodiment of a hydrocarbon site that may produce and process hydrocarbons, in accordance with aspects of the present disclosure;

[0012] FIG. 2 is a schematic diagram of an embodiment of a fluid treatment system of the hydrocarbon site of FIG. 1, in accordance with aspects of the present disclosure;

[0013] FIG. 3 is a flow diagram of a process for generating a treatment fluid, in accordance with aspects of the present disclosure;

[0014] FIG. 4 is a flow diagram of a process for pretreating a production stream, in accordance with aspects of the present disclosure;

[0015] FIG. 5 is a flow diagram of a process for inhibiting solid and / or insoluble polymer formation in a production stream, in accordance with aspects of the present disclosure;

[0016] FIG. 6 is a graph of a percentage of hydrogen sulfide (H2S) in a production fluid versus time for an experimental additive formulation and comparative sample, in accordance with aspects of the present disclosure; andIS24.1495-WO-PCT

[0017] FIG. 7 is a graph of a percentage of carbon dioxide (CO2) in a production fluid versus time for an experimental additive formulation and comparative sample, in accordance with aspects of the present disclosure.DETAILED DESCRIPTION

[0018] Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0019] As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled), and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale for purposes of clarification.

[0020] As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.

[0021] Furthermore, when introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to beIS24.1495-WO-PCT inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment,” “an embodiment,” or “some embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, the phrase A “based on” B is intended to mean that A is at least partially based on B. Moreover, unless expressly stated otherwise, the term “or” is intended to be inclusive (e.g., logical OR) and not exclusive (e.g., logical XOR). In other words, the phrase A “or” B is intended to mean A, B, or both A and B.

[0022] All numerical values within the detailed description herein are modified by “about” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. For example, “about” or “approximately” may refer to ±0.2%, ±0.5%, ±1%, ±2, ±5%, ±10%, or ±15%. All ranges expressed herein should include both end points as two specific embodiments unless specified or indicated to the contrary. For purposes herein a “polymer” has two or more of the same or different monomer (“mer”) units.

[0023] Hydrocarbon well sites (e.g., hydrocarbon wells, wells) may include a number of components that facilitate the extraction, processing, and distribution of hydrocarbons (e.g., oil) from a well or well site. For example, the hydrocarbon well site may include one or more wellbores (e.g., boreholes) extending to respective subterranean reservoirs. The wellbore may include various equipment (e.g., hydrocarbon production equipment) such as tubing, conduits, casings, liners, and strings used at the hydrocarbon well site, such as directly in a wellbore and / or coupled to a wellbore via a wellhead, a Christmas tree, a distribution manifold, or any combination thereof. As used herein, the wellbore may refer to any of the tubing, conduits, casings, liners, and strings that may couple to the wellbore and / or positioned directly within the wellbore.

[0024] In some embodiments, the hydrocarbon well site may also include a fluid treatment system. The fluid treatment may be used to treat production fluids such as crude oils, petroleum residua, fuels, and the like to selectively reduce the levels of sulfides (such as H2S, thiols). In some cases, treatment fluids may include chemical scavengers to reduceIS24.1495-WO-PCT sulfide species, chemical formulations to reduce corrosion, and the like. As defined herein, a chemical scavenger is a treating chemical that may be added to production fluid (e.g., liquid, gas) to react with a contaminant to modify the contaminant to reduce unwanted effects. For example, sulfide scavengers may reduce the presence of soluble sulfide species, H2S, S2' and HS’ when added to the production fluid.

[0025] In certain embodiments, presence of chemical scavengers in production fluids may generate one or more reaction products and / or promote one or more side reactions that may impact further processing steps of the hydrocarbon site. For example, undertreatment of production fluids with sulfide scavengers may result in subsequent reactions such as oligomerization and / or polymerization. Formation of solids such as oligomers and / or polymers may impact flow dynamics of the production fluid and impact processability (e.g., solubility) of the production fluids. Solid formation may necessitate additional processes such as various filtration processes to reduce and / or prevent solid build-up in equipment of the hydrocarbon well site. Filtration processes may include adding additional equipment and / or increase maintenance requirements during fluid treatment. As such, there is a need to reduce solid formation and / or improve solubility of reaction products of treatment fluids without added filtration steps. Accordingly, an additive formulation (e.g., solids control additive) is provided herein to reduce solid formation (e.g., precipitation, aggregation) during treatment of fluids with chemical scavenger formulations.

[0026] In some embodiments, a fluid treatment formulation may include scavenger chemistries and a solids control additive. The fluid treatment formulation may be injected into a production stream (e.g., a hydrocarbon-containing production stream) to dissolve and / or disperse solids within a pipeline of a hydrocarbon site. For example, a hemiacetal- based scavenger may be included in the fluid treatment formulation to reduce H2S in the production stream. As the hemiacetal consumes H2S, the solids control additive may reduce polymerization reactions of undertreated H2S, reaction byproducts, and the like. As such, the fluid treatment fluid may reduce a H2S level and reduce formation of insoluble materials from the reaction of the hemiacetal -based scavenger with H2S. Lower H2S levels may reduce effects of corrosion and improve the quality of oil and gas products and the reduction of solidsIS24.1495-WO-PCT within the production fluid may increase processability of oil and gas products. In some embodiments, the treatment fluid may be injected into a pipeline for enabling one-step fluid treatment process. In certain embodiments, the production fluids may be pretreated with the solids control additive prior to injection of the scavenger chemistry formulation to reduce production and / or to improve solubility of reaction products from reducing sulfur species via the scavenger chemistry formulation.

[0027] With the foregoing in mind, FIG. l is a schematic diagram of an embodiment of a hydrocarbon site 10 where hydrocarbon products, such as crude oil and natural gas, may be extracted from the ground, processed, and stored. Datasets related to the operation of the hydrocarbon site 10 may be employed in accordance with the present embodiments. As shown in FIG. 1, the hydrocarbon site 10 may include a number of components or facilities that correspond to wells, processing facilities, collection components, distribution networks, and the like. During the design phase of planning for the types of components to use at the hydrocarbon site 10, the locations of the components at the hydrocarbon site 10, and other design properties, a variety of factors are taken under consideration.

[0028] The hydrocarbon site 10 may include a number of wells 12 disposed within a geological formation. As used herein, wells 12 may generally refer to physical components such as the drilling platform 16 and wellbore 18 and / or the general area of the reservoir in which extraction is desired (e g., a reservoir well section). The drilling operations may include drilling the wellbore 18, injecting drilling fluids into the wellbore 18, performing casing operations within the wellbore 18, and the like. In addition to including the drilling platform 16, the hydrocarbon site 10 may include surface equipment 20 that may carry out certain operations, such as fluid treatment processes, cement installation operation, well logging operations to detect conditions of the wellbore 18, and the like. As such, the surface equipment 20 may include equipment that store cement slurries, drilling fluids, displacement fluids, spacer fluids, treatment fluids, chemical wash fluids, and the like. The surface equipment 20 may include piping and other materials used to transport the various fluids described above into the wellbore 18. The surface equipment 20 may also include pumpsIS24.1495-WO-PCT and other equipment (e ., batch mixers, centrifugal pumps, liquid additive metering systems, tanks, etc.) that may fill in the interior of a casing string with the fluids discussed above.

[0029] In addition to the equipment used for drilling operations, the hydrocarbon site may include a number of well devices that may control the flow of hydrocarbons being extracted from the wells 12. For instance, the well devices in the hydrocarbon site 10 may include pumpjacks 22, submersible pumps 24, well trees 26, and the like. The pumpjacks 22 may mechanically lift hydrocarbons (e.g., oil) out of the well 12 when a bottom hole pressure of the well 12 is not sufficient to extract the hydrocarbons to the surface. The submersible pump 24 may be an assembly that may be submerged in a hydrocarbon liquid that may be pumped. As such, the submersible pump 24 may include a hermetically sealed motor, such that liquids may not penetrate the seal into the motor. Further, the hermetically sealed motor may push hydrocarbons from underground areas or the reservoir to the surface. The well trees 26 may be an assembly of valves, spools, and fittings used for natural flowing wells. As such, the well trees 26 may be used for an oil well, gas well, water injection well, water disposal well, gas injection well, condensate well, and the like. By way of reference, the wells 12 may be part of a first hierarchical level and the well devices that extract hydrocarbons from the wells 12 may be part of a second hierarchical level above the first hierarchical level. Each hierarchical level may include a number of components and the presently disclosed techniques may account for these levels when determining the design plans for the hydrocarbon site 10.

[0030] After the hydrocarbons are extracted from the surface via the well devices, the extracted hydrocarbons may be distributed to other devices via a network of pipelines 28. That is, the well devices of the hydrocarbon site 10 may be connected together via a network of pipelines 28. In addition to the well devices described above, the network of pipelines 28 may be connected to other collecting or gathering components, such as wellhead distribution manifolds 30, separators 32, storage tanks 34, and the like.

[0031] In some embodiments, the pumpjacks 22, the submersible pumps 24, well trees 26, wellhead distribution manifolds 30, separators 32, and storage tanks 34 may be connected together via the network of pipelines 28. The wellhead distribution manifolds 30 may collectIS24.1495-WO-PCT the hydrocarbons that may have been extracted by the pumpjacks 22, the submersible pumps 24, and the well trees 26, such that the collected hydrocarbons may be routed to various hydrocarbon processing or storage areas in the hydrocarbon site 10. The separator 32 may include a pressure vessel that may separate well fluids produced from oil and gas wells into separate gas and liquid components. For example, the separator 32 may separate hydrocarbons extracted by the pumpjacks 22, the submersible pumps 24, or the well trees 26 into oil components, gas components, and water components. After the hydrocarbons have been separated, each separated component may be stored in a particular storage tank 34. The hydrocarbons stored in the storage tanks 34 may be transported via the pipelines 28 to transport vehicles, refineries, and the like.

[0032] In certain instances, the hydrocarbons and / or production streams may be treated by a fluid treatment system 40 to reduce one or more undesirable species (e.g., sulfide species), reduce corrosion via one or more corrosion inhibitors, and the like. The fluid treatment system 40 may be positioned at suitable portion of the hydrocarbon site 10. Thait is, the fluid treatment system 40 may be injected into production streams of the hydrocarbons before and / or after separation of gas and liquid components. The fluid treatment system 40 may include a solids control additive to reduce solid formation and / or increase solubility of products formed during treatment of process streams. In this manner, the fluid treatment system 40 may reduce dependency on filtration processes during fluid treatment processes.

[0033] Although the hydrocarbon site 10 is described above with certain components, it should be understood that the hydrocarbon site 10 may include additional, fewer, or different components. For example, although discussed above in relation to a hydrocarbon site 10 on land, present embodiments may also include analysis of off-shore hydrocarbon sites 10 and the components thereof. That is, the embodiments described herein are directed to identifying intervals of interest for any suitable hydrocarbon site that may include various types of components that are related to the production and distribution of hydrocarbons. In this way, the components depicted in FIG. 1 are provided as an example context in which the embodiments described herein may be implemented. As such, the embodiments of this disclosure should not be limited to the components listed in FIG. 1.IS24.1495-WO-PCT

[0034] FIG. 2 is a schematic diagram of an embodiment of the fluid treatment system 40 of the hydrocarbon site 10 of FIG. 1. The fluid treatment system 40 may be used to inject one or more treatment fluids 42 into processing fluid 44 of the pipelines 28 of the hydrocarbon site 10. The fluid treatment system 40 may include one or more tanks 46, secondary containment 48, one or more valves 50, a sight glass 52, one or more fdters 54, one or more pumps 56, one or more fluid injectors 58 (e.g., injection quills, injection lance, or other suitable equipment for injecting fluids into a process stream), a controller 60, one or more additional components, or a combination thereof.

[0035] The controller 60 may include a processor 62, a memory 64 including instructions 66 executable by the processor 62, communication component 68, one or more additional components, or a combination thereof. The processor 62 may include single-threaded processor(s), multi -threaded processor(s), or both. The processor 62 may process instructions 66 stored in the memory 64. The processor 62 may also include hardware-based processor(s) each including one or more cores. The processor 62 may include general purpose processor(s), special purpose processor(s), or both. The processor 62 may be communicatively coupled to other components of the fluid treatment system 40.

[0036] The memory 64 may be any suitable articles of manufacture that can serve as media to store processor-executable code, data, or the like. These articles of manufacture may represent computer-readable media (e.g., any suitable form of memory or storage) that may store the processor-executable code used by the processor 62 to perform the presently disclosed techniques. As used herein, applications may include any suitable computer software or program that may be installed onto the controller 60 and executed by the processor 62. The memory 64 may represent non-transitory computer-readable media (e.g., any suitable form of memory or storage) that may store the processor-executable code (e.g., the instructions 66) used by the processor 62 to perform various techniques described herein. It should be noted that non-transitory merely indicates that the media is tangible and not a signal.

[0037] The communication component 68 may include a wireless or wired communication component (e.g., circuitry) that may facilitate communication between theIS24.1495-WO-PCT controller 60, various types of devices, and / or components of the fluid treatment system 40. Additionally, the communication component 68 may facilitate data transfer to the controller 60, such that the controller 60 may receive data from the other components of the fluid treatment system 40. The communication component 68 may use a variety of communication protocols, such as Open Database Connectivity (ODBC), TCP / IP Protocol, Distributed Relational Database Architecture (DRDA) protocol, Database Change Protocol (DCP), HTTP protocol, other suitable current or future protocols, or combinations thereof.

[0038] It should be noted that the components described above with regard to the controller 60 are exemplary components and the controller 60 may include additional or fewer components as shown. In addition, although the components are described as being part of the controller 60, the components may also be part of any suitable computing device to perform the various operations described herein.

[0039] In some embodiments, the treatment fluid 42 may include a sulfide scavenger formulation and a solids control additive. The sulfide scavenger formulation may be selected from polyols such as polyether polyols. For example, the sulfide scavenger formulation may be ethylenedioxy (dimethanol) (EDDM). EDDM may be used to reduce the concentration of sulfide species in the production fluid. 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. Sulfide scavengers, such as EDDM, may be capable of delivering suitable hydrogen sulfide scavenging capacity, while maintaining corrosion inhibitor component performance and / or may enhance scale inhibitor performance. Without being bound by the theory, it is believed that EDDM may react with the bisulfide (HS‘) in the aqueous phase to reduce formation of sulfide scales. As such, there is a need for reducing solid formation from subsequent reaction of EDDM to facilitate sulfide species reduction while reducing undesirable solid formation.

[0040] In certain embodiments, the solids control additive may include an anionic surfactant such as diphenyl oxide disulfonates. The diphenyl oxide disulfonates may have a C6 to C16 carbon chain length. In some embodiments, the diphenyl oxide disulfonates mayIS24.1495-WO-PCT be an acid. In an embodiment, the additive used to reduce insoluble material is alkyl diphenyloxide disulfonate. The solids control additive may include any suitable additive such as disodium hexadecyldiphenyloxide disulfonate, disodium dihexadecyldiphenyloxide disulfonate, and the like. The solids control additive may include 0.4 to 7.5 wt% of the treatment fluid 42. In some embodiments, the solids control additive may include about 0.5 to 3.0 wt%,0.5 to 5.0 wt%, 1 to 7.0 wt%, 1 to 7.5 wt%, or about 0.3 to 7.6 wt% of the treatment fluid 42.

[0041] In some embodiments, the sulfide scavenger formulation and the solids control additive may be mixed within the tanks 46 to produce the treatment fluid 42. The treatment fluid 42 may be pumped via the pump 56 into the pipeline 28. For example, the treatment fluid 42 may be injected via the fluid injectors 58 into fluids 44 within the pipeline 28 to reduce a concentration of sulfide species and reduce solid formation during chemical treatment of the fluids 44. The fluids 44 may be dosed with the treatment fluid based on a concentration of sulfide species in the fluids 44. For example, the treatment fluid 42 may make up from about 0.2% to 15%, about 0.4% to 10%, or about 0.4% to 7.5% of the fluids 44. It should be noted, that the dosage of the treatment fluid 42 may be based on a concentration of sulfide species within the fluids 44 and / or one or more additional operating conditions. As such, an amount of the treatment fluid 42 used may be based on a volume of the treatment fluid 42 to remove a mass of sulfide species. For example, the amount of treatment fluid 41 may be around 5 to 25 L / kg (Liters treatment fluid per kg of sulfur species).

[0042] The treatment fluid 42 may be introduced to the pipeline 28 within a compatible temperature, pressure, and flow rate envelope. For example, the temperature envelope may range from about 5°C to 150°C. The pressure envelope may range from about 100 kPa to 10,000 kPa.

[0043] In certain embodiments, the controller 60 of the fluid treatment system 40 may be used to modify the amount, temperature, pressure, flow rate, and the like of treatment fluid 42 injected into the pipeline 28. The controller may receive data indicative of conditions of the hydrocarbon well sites 10 of FIG. 1 and modify the amount, temperature, pressure, flow rate, and the like introduced to the pipeline 28. The controller 60 may modify injectionIS24.1495-WO-PCT conditions in near real time and / or based on a schedule. For example, the controller 60 may receive data indicative of a concentration of H2S present within the fluids 44. The data may indicate that the concentration of H2S has increased relative to previous data, or otherwise above a threshold or outside of a threshold range. As such, the controller 60 may control the fluid injectors 58 to increase an amount of treatment fluid 42 introduced to the pipeline 28. In this manner, the controller 60 may be used to ensure the fluids 44 extracted from the pipeline 28 at one or more subsequent steps has a similar concentration of sulfide species and reduced solids relative to untreated fluids. Dynamic control of fluid treatment may improve operation of oil and gas processes.

[0044] In some embodiments, the fluid treatment system 40 may include one or more sensors 70. The sensors 70 may be used to analyze the treatment fluid 42 and / or the fluids 44 before and / or after injection of the treatment fluid 42. The sensors 70 may measure one or more parameters (e.g., fluid parameters), such as a fluid temperature, a fluid pressure, a fluid flow rate, a fluid composition, or any combination thereof, as fluid enters and / or exits the fluid treatment system 40. Thus, the sensors 70 may include temperature sensors, pressure sensors, flow rate sensors, fluid composition sensors, or a combination thereof. In some embodiments, the sensors 70 may include a fluid test meter, such as a multiphase flow meter (e.g., using full gamma spectroscopy) configured to measure a flowrate of fluid flowing within the fluid treatment system 40. The sensors 70 may include a plurality of sensor modules, wherein a first module may be a flow meter and a second module may be a conductivity sensor, a pressure sensor, and the like. The sensors 70 may provide sensor feedback data related to one or more parameters of fluid flow through one or more actuator controlled valves 50, the tanks 46, the filters 54, the pumps 56, the fluid injectors 58, the pipelines 28, and the like. The valves 50 may include one or more gate valves, ball valves, flapper valves, needle valves, butterfly valves, diaphragm valves, pinch valves, choke valves, or any combination thereof. As discussed in detail below, the valves include actuators (e.g., electric actuators, hydraulic actuators, or pneumatic actuators) configured to move the valves between open and closed positions. The valves may be controlled based on a variety of sensor feedback from the sensors 70. For example, the sensors 70 may include surface sensors (Internet of Things (loT) sensors, gauges, and so forth. The sensors 70 may be used to controlIS24.1495-WO-PCT actuation of the valves 50, the pumps 56, the fluid injectors 58, and the like to control flow of the treatment fluid 44 into the pipeline 28.

[0045] It should be noted, in some embodiments, the fluid treatment system 40 may be operated according to preset conditions. That is, the controller 60 of the fluid treatment system 40 may not dynamically change conditions of the fluid treatment. For example, the controller 60 may be configured to provide the treatment fluid 42 at predetermined time intervals. Further, it should be noted that the components described above with regard to the fluid treatment system 40 are exemplary components and may include additional or fewer components as shown.

[0046] FIG. 3 is a block diagram of a process 100 for generating a treatment fluid 42, in accordance with aspects of the present disclosure. The blocks of the process 100 may be performed by the fluid treatment system 40 of FIGS. 1 and 2. In some embodiments, the controller 60 of the fluid treatment system 40 may control generation of the treatment fluid 42 through control of one or more valves, one or more pumps, and / or additional components of the fluid treatment system 40.

[0047] At block 102 of the process 100, the fluid treatment system 40 may receive a scavenger chemistry 104 and an additive formulation 106 (e.g., the solids control additive) and generate the treatment fluid 42 by combining the scavenger chemistries 104, the additive formulation 106, and one or more additional additives. The scavenger chemistries 104 may include one or more chemicals that may be used to react with one or more undesirable component of a production fluid. As such, the scavenger chemistries 104 may be used to reduce an amount of an undesired species from the produced fluid. The scavenger chemistries 104 may include sulfide scavengers such as polyols, hemiacetals (e.g., EDDM), triazine, aldehydes, oxazolidines, and the like. The additive formulation 106 may include an anionic surfactant such as diphenyl oxide disulfonates. In some embodiments, the one or more additional additives may include one or more anti-foaming additives, corrosion inhibitors, alkalinity control additives, wetting agents, surfactants, temperature stabilizers, shale inhibitors, lubricants, viscosifying agents, and the like.IS24.1495-WO-PCT

[0048] In some embodiments, the treatment fluid 42 may include a liquid, a solid, a gas, and combinations thereof. The treatment fluid 42 may take the form of a solution, an emulsion, a slurry, or any other form. In some embodiments, the treatment fluid 42 may contain a carrying medium. The carrying medium may be any matter that is substantially continuous under a given condition. Examples of the carrying medium include, but are not limited to, water, hydrocarbon, gas, liquefied gas, etc. In some embodiments, the carrying medium may optionally include a viscosifying agent. Some non-limiting examples of the carrying medium include hydratable gels (e.g. guars, poly-saccharides, xanthan, diutan, hydroxy-ethyl-cellulose, etc ), a cross-linked hydratable gel, a viscosified acid (e g. gelbased), an emulsified acid (e.g. oil outer phase or oil internal phase), an energized fluid (e.g. an N2 or CO2 based foam), a viscoelastic surfactant (VES) viscosified fluid, and an oil-based fluid including a gelled, foamed, or otherwise viscosified oil. Additionally, the carrier medium may be a brine or may include a brine. The scavenger chemistries 104 and the additive formulation 106 may be suspended within the carrying medium. For example, the scavenger chemistries 104 and the additive formulation 106 may dissolve or otherwise becomes a constituent portion of the carrying fluid under a given condition for less than 10%, sometimes less than 20%, of the weight of substance when it is not in contact of the carrying medium.

[0049] FIG. 4 is a flow diagram of a process 120 for pretreating a production stream, in accordance with aspects of the present disclosure. The blocks of the process 120 may be performed by the fluid treatment system 40 of FIGS. 1 and 2. In some embodiments, the controller 60 of the fluid treatment system 40 may perform the blocks of the process 120 by controlling one or more valves, one or more pumps, and / or additional components of the fluid treatment system 40.

[0050] At block 122 of the process 120, the fluid treatment system 40 receives an additive formulation 124 and injects the additive formulation 124 into a production stream to form a pretreated production stream. The additive formulation 124 may include an anionic surfactant such as diphenyl oxide disulfonates. An amount of the additive formulation 124 added to the production fluid may be based on a concentration of sulfide species present inIS24.1495-WO-PCT the production fluid. The additive formulation 124 may be introduced to the production stream at any suitable point within the hydrocarbon well site 10. For example, the additive formulation 124 may be provided to the production stream at a wellhead of a wellbore.

[0051] For example, a fluid conduit may be used to deliver the additive formulation 124 to a wellsite, and / or capable to deliver produced fluid from a wellbore positioned at the wellsite to a blending facility for pretreatment. For example, the fluid conduit may include a size, material, and pressure rating capable to perform the operations of delivering the additive formulation 124 to the wellsite, and / or to deliver produced fluids from the wellsite to the blending facility. The fluid compositions, pressures, temperatures, flow rates, and other characteristics of the production stream utilized will vary with the characteristics of the formation, job designs, and other considerations that are generally known to one of skill in the art contemplating a particular wellsite, wellbore, and target formations. The flow rates of the fluid flowing to the wellsite may be sufficient to support an ongoing real-time operation such as a fracture treatment, and / or the wellsite location may include storage tanks or other features to allow for the additive formulation 124 to be transported to the wellsite before and / or during the treatment operations. In certain embodiments, the additive formulation 124, or any other treatment fluid may be provided to the production stream on a continuous basis and / or during real-time during a treatment.

[0052] At block 126 of the process 120, the fluid treatment system 40 receives a hemiacetal -based scavenger chemistry formulation 128 and injects the hemiacetal-based scavenger chemistry formulation to the pretreated production stream. The hemiacetal based may be introduced to the pretreated production stream subsequent to treatment of the production stream with the additive formulation 124. Without wishing to be bound by theory, pretreatment of the production stream may increase the solubility of hemiacetal reaction production with sulfide species such as H2S in the production fluid reducing restrictions or plugging.

[0053] FIG. 5 is a flow diagram of a process 140 for inhibiting solid and / or insoluble polymer formation in a production stream, in accordance with aspects of the present disclosure. The blocks of the process 140 may be performed by the fluid treatment systemIS24.1495-WO-PCT40 of FIGS. 1 and 2. In some embodiments, the controller 60 of the fluid treatment system 40 may perform the blocks of the process 140 by controlling one or more valves, one or more pumps, and / or additional components of the fluid treatment system 40.

[0054] At block 142 of the process 140, the fluid treatment system 40 may introduce a treatment fluid into a production stream. For example, the treatment fluid may be introduced via an inlet of a pipeline associated with the production stream. The production stream may include a brine, fuels (e.g., kerosene), and / or additional oil and gas production streams. The treatment fluid may include a solids control additive and a sulfide scavenger. The solids control additive may include an anionic surfactant such as diphenyl oxide disulfonates. The sulfide scavenger may include an ethylendioxy dimethanol (EDDM) formulation. The amount of the treatment fluid introduced into the production stream may be based on a concentration of H2S in a production stream. For example, the production stream may include 1,000 ppm sulfide species. The treatment fluid may range from about 750 to 1,000 ppm of the production stream. The treatment fluid may be introduced at a temperature ranging from about 70 to 115°C at a pressure ranging from about 280 to 1,000 kPag.

[0055] At block 144 of the process 400, the fluid treatment system 40 may reduce, via the treatment fluid, a concentration of H2S in the production stream. The sulfide scavenger of the treatment fluid may react with H2S in the production stream to reduce the presence of H2S and / or one or more additional sulfide species. In some embodiments, one or more sensors of the fluid treatment system 40 may be used to monitor the concentration of H2S in the production stream during treatment and provide sensor feedback data as output.

[0056] At block 146 of the process 400, the fluid treatment system 40 may inhibit solid formation within the production stream. Solid formation may be inhibited and / or reduced by solubilizing reaction products of the sulfide scavenger with H2S. For example, oligomers and / or polymers formed as a product of under and / or over treatment of the production stream may be solubilized in the production stream to reduce solid formation during treatment of the production stream. In some embodiments, the concentration of H2S in the production stream may be similar with or without the solids control additive present in the treatment fluid. The solids control additive may be selective to the H2S within the production stream. It shouldIS24.1495-WO-PCT be noted, blocks 144 and 146 of the process 140 may be performed concurrently based on reaction kinetics and / or the like.

[0057] The solids control additive disclosed herein may reduce the formation of solids from the reaction of EDDM with H2S to reduce solid formation during treatment of fluids with chemical scavenger formulations. Example scavenging performance of H2S using the solids control additive are described below. The examples provided herein are exemplary and are not meant to limit the scope of the disclosed processes.

[0058] Scavenging performance of H2S was assessed using a High Temperature, High Pressure (HTHP) autoclave. The solids control additive and the EDDM scavenger chemistry was dispersed into a brine medium. The autoclave is equipped with a pressure burst disc. Magnetic stirring using an impeller was used to produce bulk fluid homogeneity within the autoclave. A thermocouple probe, held by a Hastelloy sleeve is used to measure a temperature of fluid in the autoclave. An electronic controller was used to maintain temperature and stir rate throughout the experiment and to display the pressure inside the autoclave. Outlet gas concentration was analyzed by gas chromatography, reported as the volume of scavenger required to react with H2S by weight. The autoclave test performed is based on a method by A. Bonfim and A. Magalhaes (Magalhaes, A., and A. Bonfim., Artigo tecnico, Revista Corrosao & Prote^ao-ABRACO, 8.36, 28-32, (2011)). and designed to evaluate the experimental H2S uptake capacity of scavengers in fluid form. The conditions for autoclave testing are summarized in Table 1.Table 1: Autoclave Test Conditions

[0059] The test fluids used in the autoclave test include kerosene and brine. The test fluid composition is based on an oil and gas production facility. For example, the test fluid mayIS24.1495-WO-PCT include salt solutions. In some embodiments, the test fluid may include cations such as barium, calcium, potassium, magnesium, strontium, sodium, lithium, zing, and the like. The test fluid may include anions such as chloride, sulfate, carbonate, bicarbonate, nitrate, phosphate, and the like. The test fluid occupied about 75% of the total internal volume of the autoclave. An aliquot of test fluids before introduction of the treatment fluids (e.g., solids control additive and the EDDM scavenger chemistry) was collected for comparison. The mass of H2S that the treatment fluid was able to capture was calculated from the variation in H2S concentration (e.g., H2S mole percent) versus time shown in FIG. 6. The autoclave test was terminated when the H2S concentration equilibrated to the input concentration. The autoclave was purged of adsorbed H2S by flow of N2 and the solids were removed for quantitation.

[0060] Utilizing the experimental additive formulation (e.g., the additive formulation 106) in conjunction with a scavenger sample demonstrates improved H2S uptake as compared to using a scavenger alone. FIG. 6 is a graph 200 of a percentage (e.g., molar percentage) of H2S in a test fluid versus time for a scavenger sample 202 and an experimental additive formulation 204, in accordance with aspects of the present disclosure. The graph 200 includes an x-axis 206 representative of experiment time in minutes (min.) and a y-axis 208 representative of H2S mole percent. The scavenger sample 202 includes EDDM scavenger chemistry. The experimental additive formulation 204 includes the EDDM scavenger chemistry and the solids control additive. As shown, the scavenger sample 202 achieved a lower H2S concentration minimum than experimental additive formulation 204. The reduction in H2S concentration corresponds with the dilution effect from the presence of the solids control additive in the experimental additive formulation 204. The reaction kinetics are also slightly faster for scavenger sample 202 given the initial reduction in H2S has a slightly steeper drop illustrated by arrow 210, resulting in reduced activity of the experimental additive formulation 204 by about 10% compared to the scavenger sample 202. That is, the difference in uptake is specific to H2S as carbon dioxide uptake is consistent between both the scavenger sample 202 and the experimental additive formulation 204. H2S uptake values, from the first hour of the autoclave reaction, are summarized in Table 3.IS24.1495-WO-PCTTable 3: Uptake Results

[0061] FIG. 7 is a graph 220 of a percentage of carbon dioxide (CO2) in the test fluid of FIG. 6 versus time for the scavenger sample 202 and the experimental additive formulation 204, in accordance with aspects of the present disclosure. The graph 220 includes an x-axis 222 representative of experiment time in minutes (min.) and a y-axis 224 representative of CO2 mole percent. As shown, the CO2 concentration was consistent (e.g., varying between about 90% to about 95%) throughout the duration of the autoclave test for both the scavenger sample 202 and the experimental additive formulation 204.

[0062] Returning to Table 3, the scavenger sample 202 had an increased amount of solids after one hour of reaction compared to the experimental additive formulation 204. The experimental additive formulation 204, reduced the solids by about 31% even though the activity was 10% lower than the scavenger sample 202. The reduction in activity correlates with the about 13% decrease in H2S uptake by the experimental additive formulation 204 as compared to the scavenger sample 202. As such, the solids control additive present in the experimental additive formulation 204 reduced solid formation from the reaction of EDDM and H2S. Without wishing to be bound by theory, the reduction of solids in the test fluids treated with the experimental additive formulation 204 indicates that the solids control additive reduced an amount of insoluble polymer present in solution by increasing solubility of reaction products of the scavenger.

[0063] Technical effects of the disclosed embodiments include a fluid treatment system to treat fluid using a treatment fluid including scavenger chemistries and a solids control additive. As described herein, a presence of the solids control additive in production streams during fluid treatment processes using sulfide scavengers such as EDDM may reduce solid formation due to generation of reaction products and / or promote one or more side reactions. Advantageously, use of the solids control additive reduces an amount of solids produced byIS24.1495-WO-PCT solubilizing oligomers and / or polymers formed during sulfide scavenger reaction with sulfide species within production streams. The disclosed techniques may reduce impacts on flow dynamics of the production streams and improve processability (e.g., solubility) of the production streams without additional of filtration processes to reduce and / or prevent solid build-up in equipment of the hydrocarbon well site. As such, deployment of the presently disclosed techniques may provide improved efficiency and performance of fluid treatment processes.

[0064] The subject matter described in detail above may be defined by one or more clauses, as set forth below.

[0065] A fluid composition includes a sulfide scavenger formulation to reduce a concentration of one or more sulfide species in a production stream and a solids control additive to reduce solid formation in the production steam as a result of reaction of the sulfide scavenger formulation and the one or more sulfide species.

[0066] The fluid composition of the preceding clause, wherein the sulfide scavenger formulation comprises ethylenedioxy (dimethanol) (EDDM).

[0067] The fluid composition of any of the preceding clauses, wherein the solids control additive comprises a diphenyl oxide disulfonate.

[0068] The fluid composition of any of the preceding clauses, wherein the fluid composition is a treatment fluid composition.

[0069] The fluid composition of any of the preceding clauses, wherein the solids control additive is configured to solubilize one or more products of the reaction the sulfide scavenger formulation and the one or more sulfide species.

[0070] The fluid composition of any of the preceding clauses, wherein a temperature of the treatment fluid is about 50°C to 100°C.

[0071] The fluid composition of any of the preceding clauses, including a production stream, wherein solids control additive and the sulfide scavenger formulation are present inan amount between about 0.4% to about 10% of the production stream, comprising a production stream, wherein solids control additive and the sulfide scavenger formulation are present in an amount between about 0.4% to about 10% of the production stream.

[0072] The fluid composition of any of the preceding clauses, wherein the solids control additive is alkyldiphenyloxide disulfonate.

[0073] A method includes introducing a treatment fluid at an inlet of a production stream, wherein the treatment fluid comprises a sulfide scavenger and a solids control additive, reducing, via the sulfide scavenger of the treatment fluid, a concentration of H2S in the production stream and inhibiting, via the solids control additive of the treatment fluid, solids formation in the production stream.

[0074] The method of the preceding clause, including pretreating the production stream with the solids control additive.

[0075] The method of any of the preceding clauses, including extracting an aliquot of the production stream after receiving the treatment fluid.

[0076] The method of any of the preceding clause, wherein the aliquot has a reduced mass of solids relative to a second treatment fluid without the solids control additive.

[0077] The method of any of the preceding clauses, wherein the solids control additive is alkyldiphenyloxide disulfonate.

[0078] The method of any of the preceding clauses, including reducing a concentration of one or more additional sulfide species.

[0079] The method of any of the preceding clauses, including receiving the treatment fluid at the inlet at a temperature of about 50°C to 100°C.

[0080] The method of any of the preceding clauses, wherein introducing the treatment fluid into the production stream comprises dosing the treatment fluid from 0.4% to 10% of the production fluid.IS24.1495-WO-PCT

[0081] A system includes a fluid treatment system including one or more tanks, a fluid injector, and a controller. The controller is configured to receive a sulfide scavenger at the one or more tanks and receive a solids control additive at the one or more tanks. The controller is also configured to generate a treatment fluid based on mixing the sulfide scavenger and the solids control additive and inject, via the fluid injector, the treatment fluid into a pipeline comprising a production stream, wherein injection of the treatment fluid is configured to reduce a concentration of H2S in the production stream and reduce solids formation in the production stream.

[0082] The system of the preceding clause, wherein the solids control additive is alkyldiphenyloxide disulfonate.

[0083] The system of the preceding clause, wherein the sulfide scavenger comprises ethylenedioxy (dimethanol) (EDDM).

[0084] The system of any of the preceding clauses, wherein the treatment fluid comprises about 0.4% to 7.5% of the treatment fluid.

[0085] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and / or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.

[0086] Finally, the techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical.IS24.1495-WO-PCTFurther, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function]...” or “step for [perform]ing [a function], . it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Claims

IS24.1495-WO-PCTCLAIMS1. A fluid composition comprising: a sulfide scavenger formulation configured to reduce a concentration of one or more sulfide species in a production stream; and a solids control additive configured to reduce solid formation in the production stream as a result of reaction of the sulfide scavenger formulation and the one or more sulfide species.

2. The fluid composition of claim 1, wherein the sulfide scavenger formulation comprises ethylenedioxy (dimethanol) (EDDM).

3. The fluid composition of claim 1, wherein the solids control additive comprises a diphenyl oxide disulfonate.

4. The fluid composition of claim 1, wherein the fluid composition is a treatment fluid composition.

5. The fluid composition of claim 1, wherein the solids control additive is configured to solubilize one or more products of the reaction the sulfide scavenger formulation and the one or more sulfide species.

6. The fluid composition of claim 1, wherein a temperature of the fluid is about 50°C to 100°C.

7. The fluid composition of claim 1, comprising a production stream, wherein solids control additive and the sulfide scavenger formulation are present in an amount between about 0.4% to about 10% of the production stream.IS24.1495-WO-PCT8. The fluid composition of claim 1, wherein the solids control additive is alkyldiphenyloxide disulfonate.

9. A method comprising: introducing a treatment fluid into a production stream, wherein the treatment fluid comprises a sulfide scavenger and a solids control additive; reducing, via the sulfide scavenger of the treatment fluid, a concentration of H2S in the production stream; and inhibiting, via the solids control additive of the treatment fluid, solids formation in the production stream.

10. The method of claim 9, comprising pretreating the production stream with the solids control additive.

11. The method of claim 9, comprising extracting an aliquot of the production stream after receiving the treatment fluid.

12. The method of claim 11, wherein the aliquot has a reduced mass of solids relative to a second treatment fluid without the solids control additive.

13. The method of claim 9, wherein the solids control additive is alkyldiphenyloxide disulfonate.

14. The method of claim 9, comprising reducing a concentration of one or more additional sulfide species.

15. The method of claim 9, comprising receiving the treatment fluid at an inlet of the production stream at a temperature of about 50°C to 100°C.IS24.1495-WO-PCT16. The method of claim 9, wherein introducing the treatment fluid into the production stream comprises dosing the treatment fluid from 0.4% to 10% of the production stream.

17. A system, comprising: a fluid treatment system, comprising: one or more tanks; a fluid injector; and a controller configured to: receive a sulfide scavenger at the one or more tanks; receive a solids control additive at the one or more tanks; generate a treatment fluid based on mixing the sulfide scavenger and the solids control additive; and inject, via the fluid injector, the treatment fluid into a pipeline comprising a production stream, wherein injection of the treatment fluid is configured to reduce a concentration of H2S in the production stream and reduce solids formation in the production stream.

18. The system of claim 17, wherein the solids control additive is alkyldiphenyloxide disulfonate.

19. The system of claim 18, wherein the sulfide scavenger comprises ethylenedioxy (dimethanol) (EDDM).

20. The system of claim 17, wherein the treatment fluid comprises about 0.4% to 7.5% of the treatment fluid.

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