OPTIMIZING CHEMICAL TREATMENT AT THE SUBSURFACE FOR IMPROVED WELL PERFORMANCE

A method for evaluating a chemical treatment at a subsurface for improved well performance may include obtaining information about a post-reaction fluid that results from a fluid flowing through a testing vessel for a period of time, where the testing vessel comprises a plurality of materials, where the plurality of materials is designed to be representative of the subsurface, and where the plurality of materials comprises rock and proppant. The method may also include performing, using the information, a compatibility test on the post-reaction fluid and the plurality of materials after the period of time. The method may further include evaluating, after performing the compatibility test, an effect of the post-reaction fluid on the plurality of materials.

TECHNICAL FIELD

The present application is related to subterranean field operations and, more particularly, to optimizing chemical treatment at the subsurface for improved well performance.

BACKGROUND

Some subterranean formations, such as shale and tight formations, may produce subterranean resources through techniques such as horizontal drilling and fracturing. Over time, the production pathways such as fractures may become restricted or blocked because of the accumulation of scales and/or other solids (e.g., formation fines). Preventing or mitigating the development and growth of these scales and/or solids may lead to enhanced extraction of the subterranean resources for an extended period of time.

SUMMARY

In general, in one aspect, the disclosure relates to a method for evaluating a chemical treatment at a subsurface for improved well performance. The method may include obtaining information about a post-reaction fluid that results from an initial fluid flowing through a testing vessel for a period of time, where the testing vessel includes a plurality of materials, and where the plurality of materials is designed to be representative of a subterranean formation within the subsurface, and where the plurality of materials comprises rock and proppant. The method may also include performing, using the information, a compatibility test on the post-reaction fluid and the plurality of materials after the period of time. The method may further include evaluating, after performing the compatibility test, an effect of the post-reaction fluid on the plurality of materials.

In another aspect, the disclosure relates to a system for evaluating a chemical treatment at a subsurface for improved well performance. The system may include a post-reaction fluid collection system that is configured to receive a post-reaction fluid from a reaction module, where the post-reaction fluid includes an initial fluid after the initial fluid flows through a plurality of materials in a testing vessel of the reaction module, where the plurality of materials includes rock and proppant, where the plurality of materials is designed to be representative of a subterranean formation at the subsurface, and where the reaction module is further configured to provide the initial fluid that flows through plurality of materials in the testing vessel for a period of time.

In yet another aspect, the disclosure relates to a method for evaluating a chemical treatment at a subsurface for improved well performance. The method may include combining an initial fluid and a plurality of materials in a testing vessel for a period of time, where the plurality of materials is designed to be representative of the subsurface, and where the plurality of materials comprises rock and proppant. The method may also include removing a post-reaction fluid from the testing vessel after the period of time, where the post-reaction fluid results after combining the initial fluid and the plurality of materials. The method may further include performing a compatibility test on the post-reaction fluid and the plurality of materials after the period of time. The method may also include evaluating, based on results of the compatibility test, an effect of the post-reaction fluid on the plurality of materials.

DESCRIPTION OF THE INVENTION

The example embodiments discussed herein are directed to systems, apparatus, methods, and devices for optimizing chemical treatment at the subsurface for improved well performance. The subterranean resources captured using example embodiments may include, but are not limited to, oil and natural gas. Creating one or more wellbores with induced fractures and/or using such wellbores with example embodiments may be designed to comply with certain standards and/or requirements. Example embodiments may be used for wellbores drilled in conventional and/or unconventional (e.g., tight shale) subterranean formations and reservoirs.

The use of the terms “about”, “approximately”, and similar terms applies to all numeric values, whether or not explicitly indicated. These terms generally refer to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term may be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% may be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

A “subterranean formation” refers to practically any volume under a surface. For example, it may be practically any volume under a terrestrial surface (e.g., a land surface), practically any volume under a seafloor, etc. Each subsurface volume of interest may have a variety of characteristics, such as petrophysical rock properties, reservoir fluid properties, reservoir conditions, hydrocarbon properties, or any combination thereof. For example, each subsurface volume of interest may be associated with one or more of: temperature, porosity, salinity, permeability, water composition, mineralogy, hydrocarbon type, hydrocarbon quantity, reservoir location, pressure, etc. Those of ordinary skill in the art will appreciate that the characteristics are many, including, but not limited to: shale gas, shale oil, tight gas, tight oil, tight carbonate, carbonate, vuggy carbonate, unconventional (e.g., a permeability of less than 25 millidarcy (mD) such as a permeability of from 0.000001 mD to 25 mD)), diatomite, geothermal, mineral, etc. The terms “formation”, “subsurface formation”, “hydrocarbon-bearing formation”, “reservoir”, “subsurface reservoir”, “subsurface area of interest”, “subsurface region of interest”, “subsurface volume of interest”, and the like may be used synonymously. The term “subterranean formation” is not limited to any description or configuration described herein.

A “well” or a “wellbore” refers to a single hole, usually cylindrical, that is drilled into a subsurface volume of interest. A well or a wellbore may be drilled in one or more directions. For example, a well or a wellbore may include a vertical well, a horizontal well, a deviated well, and/or other type of well. A well or a wellbore may be drilled in the subterranean formation for exploration and/or recovery of resources. A plurality of wells (e.g., tens to hundreds of wells) or a plurality of wellbores are often used in a field depending on the desired outcome.

A well or a wellbore may be drilled into a subsurface volume of interest using practically any drilling technique and equipment known in the art, such as geosteering, directional drilling, etc. Drilling the well may include using a tool, such as a drilling tool that includes a drill bit and a drill string. Drilling fluid, such as drilling mud, may be used while drilling in order to cool the drill tool and remove cuttings. Other tools may also be used while drilling or after drilling, such as measurement-while-drilling (MWD) tools, seismic-while-drilling tools, wireline tools, logging-while-drilling (LWD) tools, or other downhole tools. After drilling to a predetermined depth, the drill string and the drill bit may be removed, and then the casing, the tubing, and/or other equipment may be installed according to the design of the well. The equipment to be used in drilling the well may be dependent on the design of the well, the subterranean formation, the hydrocarbons, and/or other factors.

A well may include a plurality of components, such as, but not limited to, a casing, a liner, a tubing string, a sensor, a packer, a screen, a gravel pack, artificial lift equipment (e.g., an electric submersible pump (ESP)), and/or other components. If a well is drilled offshore, the well may include one or more of the previous components plus other offshore components, such as a riser. A well may also include equipment to control fluid flow into the well, control fluid flow out of the well, or any combination thereof. For example, a well may include a wellhead, a choke, a valve, and/or other control devices. These control devices may be located on the surface, in the subsurface (e.g., downhole in the well), or any combination thereof. In some embodiments, the same control devices may be used to control fluid flow into and out of the well. In some embodiments, different control devices may be used to control fluid flow into and out of a well. In some embodiments, the rate of flow of fluids through the well may depend on the fluid handling capacities of the surface facility that is in fluidic communication with the well. The equipment to be used in controlling fluid flow into and out of a well may be dependent on the well, the subsurface region, the surface facility, and/or other factors. Moreover, sand control equipment and/or sand monitoring equipment may also be installed (e.g., downhole and/or on the surface). A well may also include any completion hardware that is not discussed separately. The term “well” may be used synonymously with the terms “borehole,” “wellbore,” or “well bore.” The term “well” is not limited to any description or configuration described herein.

In some cases, optimizing chemical treatment at the subsurface for improved well performance may include reducing deposition of scales and/or other solids. As defined herein, reducing deposition of scales and/or other solids may involve any of a number of different actions. For example, reducing deposition of scales and/or other solids may include minimizing the accumulation or deposition of scales and/or other solids without completely eliminating the scales and/or other solids. As another example, reducing deposition of scales and/or other solids as defined herein may additionally or alternatively mean preventing the development of scale depositions and/or other solids. As yet another example, reducing deposition of scales and/or other solids as defined herein may additionally or alternatively mean completely eliminating scales and/or other solids that have previously developed.

Example embodiments of optimizing chemical treatment at the subsurface for improved well performance may be at a subsurface (e.g., within and adjacent to a wellbore in a subterranean formation). Example embodiments of optimizing chemical treatment at the subsurface for improved well performance may additionally or alternatively be used in any of a number of other applications. For instance, example embodiments may be used to optimize chemical treatment for improved performance in surface equipment. Such surface equipment may include, but is not limited to, heat exchangers and conduit or other pipes (e.g., a pipeline, a drain pipe) used to transport fluid (e.g., natural gas).

Example embodiments may also be used for saltwater disposal (SWD) injection wells. Example embodiments may also be used for carbon capture and/or sequestration applications. For instance, water may be produced from a subterranean formation, and the produced water may be disposed via downhole water injection. Scale formation and solid plugging issues may be a significant cause for injectivity decrease/and other challenges for the water disposal wells. The performance/injectivity of the SWD wells may play a key role on the sustainability of CO2injection. The workflow/method in example embodiments may be used to optimize chemical treatments for improving injection well performance.

Example embodiments may also be used for geothermal applications. For instance, geothermal assets may be used in a high temperature environment (as what exists in a wellbore), which may lead to severe scaling issues and incompatibility issue between fluid and chemicals. Chemical treatment using example embodiments may be evaluated and/or optimized, including evaluation and optimization of solids (e.g., formation rock, sand).

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure may be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component may be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit number or a four-digit number, and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

Example embodiments of optimizing chemical treatment at the subsurface for improved well performance will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of optimizing chemical treatment at the subsurface for improved well performance are shown. Optimizing chemical treatment at the subsurface for improved well performance may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of optimizing chemical treatment at the subsurface for improved well performance to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

Terms such as “first”, “second”, “primary,” “secondary,” “above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of optimizing chemical treatment at the subsurface for improved well performance. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

FIGS.1A through1Cshow a field system199, including details thereof, with which example embodiments may be used. Specifically,FIG.1Ashows a schematic diagram of a land-based field system199in which a wellbore120has been drilled in a subterranean formation110.FIG.1Bshows a detail of a substantially horizontal section103of the wellbore120ofFIG.1A.FIG.1Cshows a detail of an induced fracture101ofFIG.1B. The field system199in this example includes a wellbore120disposed in a subterranean formation110using field equipment109(e.g., a derrick, a tool pusher, a clamp, a tong, drill pipe, casing pipe, a drill bit, a wireline tool, a fluid pumping system) located above a surface108and within the wellbore120. Once the wellbore120is drilled, a casing string125is inserted into the wellbore120to stabilize the wellbore120and allow for the extraction of subterranean resources (e.g., natural gas, oil) from the subterranean formation110.

The surface108may be ground level for an onshore application and the sea floor/lakebed for an offshore application. For offshore applications, at least some of the field equipment may be located on a platform that sits above the water level. The point where the wellbore120begins at the surface108may be called the wellhead. While not shown inFIGS.1A and1B, there may be multiple wellbores120, each with its own wellhead but that is located close to the other wellheads, drilled into the subterranean formation110and having substantially horizontal sections103that are close to each other. In such a case, the multiple wellbores120may be drilled at the same pad or at different pads. When the drilling process is complete, other operations, such as fracturing operations, may be performed. The fractures101are shown to be located in the horizontal section103of the wellbore120inFIG.1B. The fractures101, whether induced and/or naturally occurring, may additionally or alternatively be located in other sections (e.g., a substantially vertical section, a transition area between a vertical section and a horizontal section) of the wellbore120. Example embodiments may be used along any portion of the wellbore120where fractures101are located.

The subterranean formation110may include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. In certain embodiments, a subterranean formation110may include one or more reservoirs in which one or more resources (e.g., oil, natural gas, water, steam) may be located. One or more of a number of field operations (e.g., fracturing, coring, tripping, drilling, setting casing, extracting downhole resources) may be performed to reach an objective of a user with respect to the subterranean formation110.

The wellbore120may have one or more of a number of segments or hole sections, where each segment or hole section may have one or more of a number of dimensions. Examples of such dimensions may include, but are not limited to, a size (e.g., diameter) of the wellbore120, a curvature of the wellbore120, a total vertical depth of the wellbore120, a measured depth of the wellbore120, and a horizontal displacement of the wellbore120. There may be multiple overlapping casing strings of various sizes (e.g., length, outer diameter) contained within and between these segments or hole sections to ensure the integrity of the wellbore construction. In this case, one or more of the segments of the subterranean wellbore120is the substantially horizontal section103.

As discussed above, inserted into and disposed within the wellbore120ofFIGS.1A and1Bare a number of casing pipes that are coupled to each other end-to-end to form the casing string125. In this case, each end of a casing pipe has mating threads (a type of coupling feature) disposed thereon, allowing a casing pipe to be directly or indirectly mechanically coupled to another casing pipe in an end-to-end configuration. The casing pipes of the casing string125may be indirectly mechanically coupled to each other using a coupling device, such as a coupling sleeve.

Each casing pipe of the casing string125may have a length and a width (e.g., outer diameter). The length of a casing pipe may vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe may be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe may also vary and may depend on the cross-sectional shape of the casing pipe. For example, when the shape of the casing pipe is cylindrical, the width may refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe. Examples of a width in terms of an outer diameter may include, but are not limited to, 4½ inches, 7 inches, 7⅝ inches, 8⅝ inches, 10¾ inches, 13⅜ inches, and 14 inches.

The size (e.g., width, length) of the casing string125may be based on the information (e.g., diameter of the borehole drilled) gathered using field equipment with respect to the subterranean wellbore120. The walls of the casing string125have an inner surface that forms a cavity that traverses the length of the casing string125. Each casing pipe may be made of one or more of a number of suitable materials, including but not limited to steel. Cement109is poured into the wellbore120through the cavity and then forced upward between the outer surface of the casing string125and the wall of the subterranean wellbore120. In some cases, a liner may additionally be used with, or alternatively be used in place of, some or all of the casing pipes.

Once the cement dries to form concrete, a number of fractures101are induced in the subterranean formation110. The fractures101may be induced in any of a number of ways known in the industry, including but not limited to hydraulic fracturing, fracturing using electrodes, and/or other methods of inducing fractures. The hydraulic fracturing process involves the injection of large quantities of fluids containing water, chemical additives, and proppants112into the subterranean formation110from the wellbore120to create fracture networks. An example of fracturing using electrodes may be found in U.S. Pat. No. 9,840,898 issued on Dec. 12, 2017, to Kasevich et al., the entirety of which is herein incorporated by reference. A subterranean formation110naturally has fractures101, but these naturally occurring fractures101have inconsistent characteristics (e.g., length, spacing) and so in some cases cannot be relied upon for extracting subterranean resources without having additional fractures101, such as what is shown inFIG.1B, induced in the subterranean formation110.

Induced fractures101may propagate toward lower stress rock and in the direction perpendicular to the current (at the time of a fracturing operation) least principal horizontal stress. Operations that induce fractures101in the subterranean formation110use any of a number of fluids that include proppant112(e.g., sand, ceramic pellets). When proppant112is used, some of the fractures101(also sometimes called principal or primary fractures) receive proppant112, while a remainder of the fractures101(also sometimes called secondary fractures) do not have any proppant112in them.

As shown inFIG.1C, the proppant112is designed to become lodged inside at least some of the induced fractures101to keep those fractures101open after the fracturing operation is complete. The size of the proppant112is an important design consideration. Sizes (e.g., 40/70 mesh, 50/140 mesh) of the proppant112may vary. While the shape of the proppant112is shown as being uniformly spherical, and the size is substantially identical among the proppant112, the actual sizes and shapes of the proppant112may vary. If the proppant112is too small, the proppant112will not be effective at keeping the fractures101open enough to effectively allow subterranean resources111to flow through the fractures101from the rock matrices162in the subterranean formation110to the wellbore120. If the proppant112is too large, the proppant112may plug up the fractures101, blocking the flow of the subterranean resources111through the fractures101.

The use of proppant112in certain types of subterranean formation110, such as shale and other tight formations, is important. Shale formations typically have permeabilities on the order of microdarcys (μD) to nanodarcys (nD). When fractures101are induced in such formations with low permeabilities, it is important to sustain the fractures101and their conductivity for an extended period of time in order to extract more of the subterranean resource111.

The various induced fractures101that originate at the wellbore120and extend outward into the rock matrices162in the subterranean formation110in this case may have consistent penetration lengths perpendicular to the wellbore120and have consistent coverage along at least a portion of the lateral length (substantially horizontal section) of the wellbore120. For example, induced fractures101may be 50 meters high and 200 meters long. Further, the induced fractures101may be spaced a distance192apart from each other. The distance192(e.g., 25 meters, 5 meters, 12 meters) may be optimized based on the permeability and the porosity of the rock matrix162of the subterranean formation110.

The induced fractures101create a volume190within the subterranean formation110where the rock matrix162of the subterranean formation110is connected to the high conductivity fractures101located a short distance away. In addition to different configurations of the fractures101, other factors that may contribute to the viability of the subterranean formation110may include, but are not limited to, permeability of the rock matrix162, capillary pressure, and the temperature and pressure of the subterranean formation110. Each fracture101, whether induced or naturally occurring, is defined by a wall102, also called a frac face102herein. The frac face102provides a transition between the paths formed by the rock matrices162in the subterranean formation110and the fracture101. The subterranean resources101flow through the paths formed by the rock matrices162in the subterranean formation110into the fracture101.

FIG.2shows the detail ofFIG.1Cat a subsequent point in time according to certain example embodiments.FIG.3shows the detail ofFIG.2at a subsequent point in time according to certain example embodiments. For example,FIG.2may show the detail ofFIG.1Csix months later than the time captured inFIG.1Cafter flowing a fluid having a scale enhancer therethrough, andFIG.3may show the detail ofFIG.2four year later than the time captured inFIG.2after continuing to flow the fluid having the scale enhancer therethrough. Referring toFIGS.1A through3, the detail inFIG.2shows, in addition to the proppant112within the fracture101, a subterranean resource111(e.g., natural gas, oil) is shown flowing within the fracture101from the rock matrix162, around the proppant112in the fracture101, and on to the wellbore120.

As the subterranean resource111flows within the paths formed by the rock matrices162and around the proppant112in the fracture101, scale depositions213may occur (e.g., scale particles formed during the shut-in stage before the well is put into production) on the within the rock matrices162, on the proppant112, and/or on the frac face102. Over time, the scale depositions213may begin to accumulate on the rock matrices162, on the proppant112, and/or on the frac face102. Each of the scale depositions213is an inorganic deposit from ionic materials in water that attaches to solid surfaces. Hydrocarbons may be adsorbed on scale depositions213. Under field conditions, scale depositions213may be a mixture of inorganic and organic components. In some cases, scale depositions213may be or include rust or other forms of corrosion. In some cases, scale depositions213may be or include a calcium-based accumulation.

Scale depositions213may be initiated during a prior phase (e.g., completion) of a field operation, where fluids and chemicals used downhole may interact with formation rock (e.g., the frac face102, the rock matrices162) and comingle with formation water in and/or near perforations and along the fractures101, resulting in the mobilization and release of elements from the rock matrices162adjacent to the fractures101. Later, in a subsequent phase (e.g., shutting in) of the field operation, the rock-fluid interaction and the commingling of different fluids may lead to the formation (crystallization) and growth of scale depositions213in or near the perforations, the rock matrices162, and the fractures101. In yet another subsequent phase (e.g., production) of the field operation, the degradation in the conductivity and production flow path integrity over time in the rock matrices162and the fractures101, caused by agglomerate build-up of scale depositions213, may lead to plugging in or near the perforations, rock matrices162, fractures101, and completion tools.

The scale depositions213that accumulate within the rock matrices162and the fractures101may be composed of one or more of any of a number of compounds, including but not limited to calcium carbonate, barium sulfate, calcium sulfate, strontium sulfate, iron carbonate, iron oxide, iron sulfide, other oxides, other sulfides, other carbonates, other sulfates, halides, and/or hydroxides. While the scale depositions213may additionally or alternatively be composed of other compounds (e.g., gas hydrates, organic deposits (e.g., asphaltenes, waxes, acid induced accumulations), and naphthenates), example embodiments focus on the reduction of scale depositions213caused by inorganic deposits. The scale depositions213may be caused by one or more of any of a number of factors, including but not limited to supersaturation, mixing incompatible ions, changes in temperature, changes in pressure, carbon dioxide evolution, and a change in the pH of water in the fluid.

Scale depositions213may form during the shut-in stage prior to the well being put into production, as shown inFIG.2. In such a case, the scale depositions213disposed on the rock matrices162, on the proppant112, and on the frac face102are small and spotty. As a result, the scale depositions213do not contribute much to inhibiting the flow of the subterranean resource111through the paths within the rock matrices162and around the proppant112within the fracture101formed by the frac face102. In the portion of the fracture101shown at the time captured inFIG.2, there are 2 separate scale depositions213within the rock matrices162,8scale depositions213on the proppant112, and4scale depositions213on the frac face102. The number, size, and location of the scale depositions213within the rock matrices162and the fracture101may vary.

When the well is put into production, some scale particles213may stay at their original position, while some scale particles may move/migrate together with the produced water and deposit at another location along the production pathway. As more water is produced, the existing scale depositions213may increase in size and new scale depositions213may develop over time. An example of this is captured inFIG.3, which shows that the scale depositions213become larger and less spotty. As a result, the scale depositions213inFIG.3begin to contribute to inhibiting the flow of the subterranean resource111along the paths formed by the rock matrices162, through the frac face102(impacting migration of the hydrocarbon111from the rock matrix162), and around the proppant112(combined with the scale depositions213on the proppant112and on the frac face102) within the fracture101.

In the portion of the fracture101shown at the time captured inFIG.3, there are 25 separate scale depositions213within the rock matrices162, at the frac face102, and on the proppant112, many of which are significantly larger than the size of the scale depositions213shown inFIG.2. Also, some of the scale depositions213inFIG.3have migrated to a new location relative to their location inFIG.2. Again, the number, size, and location of the scale depositions213within the fracture101may vary.

In the current art, fluids (e.g., acids, chelants) are injected from the wellbore120into the fractures101to remove scale, clear perforations, and/or generate other results that may enhance production. However, as these fluids react with the fractures, proppant, rock matrices, and other elements in the volume190, the fluids change in structure. Such changes in structure of the fluids used to enhance production of the subterranean resource111within the volume190may actually have adverse effects (e.g., create other types of blockage in the fractures101) on production capability. Example embodiments are designed to analyze the post-reaction composition of various fluids that may be used within a volume190of known composition and determine a fluid that both enhances production of the subterranean resource111within the volume190in its original form and also minimizes adverse effects on the enhanced production of the subterranean resource111within the volume190in its post-reaction form. Example embodiments are also designed to determine the optimal way to use a fluid, both in its original form and in its post-reaction form, to enhance production in the volume190by mitigating the adverse effects that could develop from one or more components of the post-reaction form of the fluid in that particular field operation.

FIG.4shows a diagram of a system400for optimizing chemical treatment at the subsurface for improved well performance according to certain example embodiments. The system400ofFIG.4includes one or more fluid component sources428, one or more injection systems438, a reaction module470, a post-reaction fluid collection system450, one or more optional mixing modules465, one or more controllers404, one or more sensor devices460, one or more users451(including one or more optional user systems455), a network manager480, piping488, and one or more valves485. The reaction module470includes a testing vessel472.

The components shown inFIG.4are not exhaustive, and in some embodiments, one or more of the components shown inFIG.4may not be included in the example testing system400. Any component of the testing system400may be discrete or combined with one or more other components of the testing system400. Also, one or more components of the testing system400may have different configurations. For example, one or more sensor devices460may be disposed within or disposed on other components (e.g., the piping488, a valve485, the reaction module470, the post-reaction fluid collection system450). As another example, a controller404, rather than being a stand-alone device, may be part of one or more other components (e.g., reaction module470, the post-reaction fluid collection system450, an injection system438) of the testing system400.

Referring toFIGS.1A through4, a fluid437(in this case, a fluid in at least partially liquid form) is pushed through the testing vessel472of the reaction module470to chemically treat the material475inside the testing vessel472. The fluid437(e.g., HCl, CH3COOH, HCOOH, boric acid, HF, a chelant, etc.) may be made up of multiple fluid components427(e.g., water, chlorine, boron, fluoride) that are mixed together before reaching the reaction module470. A fluid component427may be in solid, liquid, and/or gaseous form. Two or more fluid components427may be mixed together in the piping488at a header489as those fluid components427interact with each other to form a fluid437(also sometimes called an initial fluid437herein) and flow toward the reaction module470. Alternatively, the testing system400may include one or more of the optional mixing modules465that mix two or more fluid components427together before the fluid components427reach the reaction module470as a fluid437. The fluid437has a chemistry composition of one or more fluid components427each having a concentration. A mixing module465may include one or more of a number of features used to mix two or more fluid components427together. Such features may include, but are not limited to, a vessel, a sensor device460, a controller404, an agitator, a paddle, a circulating system, an aerator, a vibrating mechanism, and a centrifuge. A mixing module465and the header489may each be referred to as a common vessel herein.

There may be one or more fluid component sources428. In certain example embodiments, there are at least two fluid component sources428. As shown inFIG.4, the system400includes fluid component source428-1(which holds fluid component427-1) through fluid component source428-N (which holds fluid component427-N). Each fluid component427(e.g., an additive) may be or include a fluid. A single fluid component427or a mixture of multiple fluid components427(but not the fluid437) may be disposed in a fluid component source428.

To control the chemistry composition of the fluid437at a given point in time, the amount of the individual fluid components427that are released or withdrawn from a fluid component source428may be regulated in real time. This regulation may be performed automatically by a controller404or manually by a user451(including an associated user system455). This regulation may be performed using equipment such as the injection systems438, valves485, regulators, sensor devices460, and meters. Examples of a fluid component source428may include, but are not limited to, a natural vessel and a man-made storage tank or other vessel. A fluid component427of a fluid component source428may have any of a number of different compositions that are naturally occurring or man-made. In some cases, a fluid component427of the fluid437includes water.

Each injection system438is configured to extract a fluid component427from a fluid component source428and push the fluid component427toward the reaction module470. The number of injection systems438in the testing system400may vary. In this case, there are N injection systems438(injection438-1through438-N). In some embodiments, there may be one injection system438for each fluid component source428. In alternative embodiments, there may be one injection system438for multiple fluid component sources428. Each injection system438may include one or more of a number of pieces of equipment to perform its function. Examples of such equipment may include, but are not limited to, a compressor, a motor, a pump, piping (e.g., piping488), a valve (e.g., valve485), a controller (e.g., controller404), and a sensor device (e.g., sensor device460).

The piping488(including the header489) may include multiple pipes, ducts, elbows, joints, sleeves, collars, and similar components that are coupled to each other (e.g., using coupling features such as mating threads) to establish a network for transporting the fluid components427from the fluid component sources428, through the injection systems438, to the header489(where the fluid components427mix together to form a fluid437), to the reaction module470, and finally from the reaction module470to the post-reaction fluid collection system450. Each component of the piping488may have an appropriate size (e.g., inner diameter, outer diameter) and be made of an appropriate material (e.g., steel, PVC) to safely and efficiently handle the pressure, temperature, flow rate, and other characteristics of the fluid components427or the fluid437, as applicable.

There may be a number of valves485placed in-line with the piping488at various locations (including at the header489) in the testing system400to control the flow of fluid components427and/or each fluid437therethrough. A valve485may have one or more of any of a number of configurations, including but not limited to a guillotine valve, a ball valve, a gate valve, a butterfly valve, a pinch valve, a needle valve, a plug valve, a diaphragm valve, and a globe valve. One valve485may be configured the same as or differently compared to another valve485in the testing system400. Also, one valve485may be controlled (e.g., manually, automatically by the controller404) the same as or differently compared to another valve485in the testing system400.

The reaction module470is configured to house or host one or more testing vessels472. Examples of a reaction module470may be or include, but are not limited to, a pressurized vessel, a laboratory, a rack, a table, and a non-pressurized vessel. The reaction module470receives a fluid437from the header489, runs the fluid437through a testing vessel472, and sends the post-reaction fluid457to the post-reaction fluid collection system450. In certain example embodiments, the testing vessels472are passive objects that have a fluid437pass through them without the testing vessels472being modified or taking action during this process. The reaction module470may control various aspects (e.g., temperature, pressure, flow rate) of the fluid437and/or the testing vessel472. In some cases, the reaction module470is designed to subject the materials475in the testing vessel472to conditions (e.g., pressure, temperature, flow rate) that simulate the corresponding downhole conditions of the fractures101and rock matrix in the subterranean formation110adjacent to the wellbore120. The reaction module470may include one or more of a number of pieces of equipment to perform these functions. Examples of such equipment may include, but are not limited to, a motor, a pump, a compressor, piping (e.g., piping488), a valve (e.g., valve485), a controller (e.g., controller404), and a sensor device (e.g., sensor device460).

A testing vessel472is a vessel (e.g., a column, a bottle, a test tube) inside of which various materials475(e.g., rock, proppant112) are disposed. The materials475in a testing vessel472may be designed to simulate induced fractures101in a subterranean formation110adjacent to a wellbore120. In some cases, the materials475placed in a testing vessel472are taken from the subterranean formation110. For example, cuttings or other loose rock that circulate to the surface108during a field operation (e.g., drilling, completion) may be removed from the mud circulating system (part of the field equipment109) and placed in a testing vessel472. As another example, a core sample may be taken of the subterranean formation110by a tool (e.g., a wireline tool) placed in the wellbore120adjacent to the induced fractures101. In such a case, the core sample may be retrieved from the tool when the tool is brought to the surface108and subsequently placed in a testing vessel472. As still another example, proppant112used to prop open the induced fractures101adjacent to the wellbore120may be used as some of the materials475in the testing vessel472.

In some cases, the reaction module470may be configured to simulate downhole conditions. In any case, the material475in the testing vessel472is chemically treated with a fluid437that flows through the materials475in the testing vessel472. In order to accomplish this, the testing vessel472may be made of any of a number of appropriate material (e.g., glass, lined stainless steel) that may withstand the conditions (e.g., pressure, temperature) simulated by the reaction module470. After a period of time, the testing process may be paused or stopped so that the materials475in the testing vessel472and the post-reaction fluid457in the post-reaction fluid collection system450may be evaluated. In some example embodiments, the fluid437may be designed to eliminate or reduce scaling that may appear and grow on some of the materials475(e.g., the proppant112and/or rock) in the testing vessel472. In addition, or in the alternative, the fluid437may be designed to clear perforations and/or otherwise enhance production of the subterranean resource111from the volume190.

Evaluation of the materials475in the testing vessel472may include determining the amount of scale depositions213disposed on the proppant112, rock, and/or other materials475in a testing vessel472over time. This evaluation may then be correlated to how effective the fluid437used during that phase of testing may be at reducing or eliminating scale depositions213in the induced fractures101adjacent to the wellbore120. Further, evaluation of the post-reaction fluid457in the post-reaction fluid collection system450may determine the chemistry components (e.g., Fe, Ca, Mg, Al, Si, Ba, K, P, Mn, S, etc.) that are added to the post-reaction fluid457and/or the chemistry components that have a different concentration after the fluid437chemically treats the materials475. In addition, evaluation of the post-reaction fluid457in the post-reaction fluid collection system450may also determine the impact of these added chemistry components on the materials475, which may translate to the impact of these added chemistry components on well production performance after flowing the fluid437through the fractures101and rock matrices in the volume190of the subterranean formation110.

Regardless of the goal of a fluid437(e.g., reaction module470to determine the general timeframe for when scale induction occurs on the materials475, to determine if a non-scaling fluid437may pass through the materials475in the testing vessel472without disturbing the proppant112, to demonstrate that a particular fluid437decreases formation of scale depositions213and other blockage in the materials475within the testing vessel472, interaction between a fluid437and the materials475versus accumulation of scale depositions213, interaction between a fluid437and debris from fractures101versus interaction between the fluid437and proppant112in the materials475), example embodiments analyze the post-reaction fluid457that gathers in the post-reaction fluid collection system450reaction module.

In some cases, the reaction module470may include one or more features (e.g., a spectrograph, a gas chromatograph, a camera with a high zoom lens, a controller404, one or more sensor devices460) that perform some or all of the evaluation of materials475within a testing vessel472that have been tested. The testing vessel472may be removable (e.g., by a user451) from and insertable into the reaction module470. The reaction module470may include one or more features (e.g., a clamp, a latched lid) that ensure that a testing vessel472is secure within the reaction module470.

The post-reaction fluid collection system450is configured to receive the post-reaction fluid457, which is the byproduct of the fluid437that has flowed through the materials475in one or more testing vessels472of the reaction module470. The post-reaction fluid457may, in some cases, be spent acid, spent brine, and/or fluid after the materials475(e.g., formation rock, proppants112, downhole materials) and the fluid437interact with each other in one or more testing vessels472of the reaction module470. The post-reaction fluid457may be analyzed to measure cation/anion concentration and residue chemical concentration to understand fluid-rock interaction.

The post-reaction fluid collection system450may include a vessel to contain some or all of the post-reaction fluid457. In some cases, such a vessel may be a testing vessel472or a vessel that is configured similar to a testing vessel472. In certain example embodiments, the post-reaction fluid collection system450is configured to simulate downhole conditions. In order to accomplish this, the part of the post-reaction fluid collection system450that receives the post-reaction fluid457may be made of any of a number of appropriate material (e.g., glass, lined stainless steel) that may withstand the conditions (e.g., pressure, temperature) simulated by the post-reaction fluid collection system450.

In some cases, the post-reaction fluid collection system450may also be configured to perform one or more tests on the post-reaction fluid457. In such cases, the post-reaction fluid collection system450may include one or more of a number of features (e.g., a motor, a pump, a compressor, piping (e.g., piping488), a valve (e.g., valve485), a spectrograph, a gas chromatograph, a camera with a high zoom lens, a controller404, one or more sensor devices460) to conduct such testing.

As a result of the testing on the post-reaction fluid457, the post-reaction fluid collection system450may determine or reveal one or more chemistry components (e.g., Fe, Ca, Mg, Al, Si, Ba, K, P, Mn, S) that are in the post-reaction fluid457but not in the fluid437. In other words, the post-reaction fluid collection system450may determine or reveal one or more chemistry components that is picked up by the fluid437as the fluid437interacts with the materials475in a testing vessel472of the reaction module470. In certain example embodiments, the post-reaction fluid collection system450may further determine the impact of the one or more chemistry components on the production performance of the fractures101and rock matrices in the volume190.

In some cases, the post-reaction fluid collection system450may also include one or more of the materials475in a collection vessel to determine the compatibility of the one or more chemistry components on some or all of the materials475over a period of time. In other words, rather than the materials475being exposed to the fluid437on a relatively brief basis in testing vessel472in the reaction module470, the some or all of the materials475may be exposed to some or all of the post-reaction fluid457(and more specifically, one or more of the chemistry components thereof) over a relatively longer period of time.

In certain example embodiments, the post-reaction fluid collection system450can, by collecting and analyzing the contents of the post-reaction fluid457, determine the reaction of the fluid437with scales, fines, solids, rock, proppant, and/or other parts of the materials475. Particle size analysis of the post-reaction fluid457may be included. With this information, the post-reaction fluid collection system450may characterize the fluid chemistry and the solid phase of the post-reaction fluid457. The post-reaction fluid collection system450may also conduct one or more compatibility tests on the post-reaction fluid457. Such compatibility tests may include, but are not limited to, fluid-rock-chemical compatibility tests and comparability tests of the post-reaction fluid457with water, oil, fluids, and/or chemicals injected into the volume190of the subterranean formation110.

For example, for treatment of the volume190using a fluid437during fracturing at a completion stage of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and crude oil (or other subterranean resource111) with rock, a mixture of the post-reaction fluid457and crude oil without rock, a mixture of the post-reaction fluid457and displacement fluid with rock, a mixture of the post-reaction fluid457and displacement fluid without rock, a mixture of the post-reaction fluid457and the fracturing fluid with rock, a mixture of the post-reaction fluid457and the fracturing fluid without rock, a mixture of the post-reaction fluid457and the formation water with rock, a mixture of the post-reaction fluid457and the formation water without rock, a mixture of the post-reaction fluid457and the completion brine with rock, and a mixture of the post-reaction fluid457and the completion brine without rock.

As another example, for treatment of the volume190using a fluid437for production enhancement during the production stage of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and crude oil (or other subterranean resource111) with rock, a mixture of the post-reaction fluid457and crude oil (a type of subterranean resource111) without rock, a mixture of the post-reaction fluid457and the formation water with rock, a mixture of the post-reaction fluid457and the formation water without rock, a mixture of the post-reaction fluid457and the completion brine with rock, and a mixture of the post-reaction fluid457and the completion brine without rock.

As yet another example, for treatment of the volume190using a fluid437for saltwater disposal (SWD) well injectivity enhancement of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and the injection water with rock, a mixture of the post-reaction fluid457and the injection water without rock, a mixture of the post-reaction fluid457and the formation water with rock, and a mixture of the post-reaction fluid457and the formation water without rock.

As a more specific example, when the fluid437is or includes an acid, when the fluid437interacts with the materials475, a byproduct of that reaction may be Fe′. When this occurs, the Fe′ may cause fouling within the materials475, which may close flow paths within the materials475. When applied to the fractures101and rock within the volume190of the subterranean formation110, the formation of Fe′ may cause more blockage than what the fluid437is designed to clear.

Based on the compatibility tests and other analysis of the post-reaction fluid457, the post-reaction fluid collection system450may conduct one or more integrated tests on the post-reaction fluid457(or components thereof, such as the one or more added chemistry components). Such integrated tests may result in determining what may react, be dissolved, and/or be mobilized and in determining reaction kinetics. This information may help to assess the impact (e.g., scale modeling results for fluid comingling scenarios) of the post-reaction fluid457(or components thereof) on scale, asphaltene, and/or other types of accumulations on the volume190in the subterranean formation110during well intervention, shutting in, and/or post-treatment production.

Based on the results integration and analysis, the post-reaction fluid collection system450may determine an optimized fluid437or stages of fluids437to be used downhole. For example, the post-reaction fluid collection system450may set and/or adjust the design and/or field treatment protocols of the volume190using a fluid437to optimize the efficiency of the well production performance. The post-reaction fluid collection system450may additionally consider the results from standard industry tests (e.g., re-gained permeability from core-flood tests) and other factors in determining well optimization. Well optimization may apply to one or more phases of a field operation, including but not limited to fluid (e.g., acid) treatment of fractures101at the completion stage of fracturing, fluid treatment as a special job for scales or fines removal, treatment using a fluid437for production enhancement during the production stage, and for SWD well injectivity enhancement.

One or more sensor devices460may be integrated with the reaction module470and the post-reaction fluid collection system450. For example, two sensor devices460in the form of or including pressure sensors may be positioned before the testing vessel472and after the testing vessel472to provide a differential pressure value across the testing vessel472. The differential pressure value may provide information as to, for example, a change in permeability, an accumulation of scale depositions213, and/or plugging in the material475. In some cases, in order to ensure that the post-reaction fluid collection system450receives the post-reaction fluid457from the reaction module470at an appropriate pressure, a pressure regulator (or other similar equipment) may be installed between the testing vessel472and the post-reaction fluid collection system450.

The testing system400may include one or more controllers404. A controller404of the testing system400communicates with and in some cases controls one or more of the other components (e.g., a sensor device460, an injection system438, the reaction module470, the post-reaction fluid collection system450) of the testing system400. A controller404performs a number of functions that include obtaining and sending data, evaluating data, following protocols, running algorithms, and sending commands. A controller404may include one or more of a number of components. As discussed below with respect toFIG.5, such components of a controller404may include, but are not limited to, a control engine, a communication module, a timer, a counter, a power module, a storage repository, a hardware processor, memory, a transceiver, an application interface, and a security module. When there are multiple controllers404(e.g., one controller404for one or more injection systems438, another controller404for the reaction module470, yet another controller404for the post-reaction fluid collection system450), each controller404may operate independently of each other. Alternatively, one or more of the controllers404may work cooperatively with each other. As yet another alternative, one of the controllers404may control some or all of one or more other controllers404in the testing system400. Each controller404may be considered a type of computer device, as discussed below with respect toFIG.6.

Each sensor device460includes one or more sensors that measure one or more parameters (e.g., pressure, flow rate, temperature, humidity, fluid content, voltage, current, permeability, porosity, rock characteristics, chemical elements in a fluid, chemical elements in a solid). Examples of a sensor of a sensor device460may include, but are not limited to, a temperature sensor, a flow sensor, a pressure sensor, a gas spectrometer, a voltmeter, an ammeter, a permeability meter, a porosimeter, and a camera. A sensor device460may be integrated with or measure a parameter associated with one or more components of the testing system400. For example, a sensor device460may be configured to measure a parameter (e.g., flow rate, pressure, temperature) of a fluid component427, a fluid437, and/or a post-reaction fluid457flowing through the piping488at a particular location (e.g., between a fluid component source428and a corresponding injection system438, between the header489and the reaction module470, between the reaction module470and the post-reaction fluid collection system450).

As another example, a sensor device460may be configured to determine how open or closed a valve485within the testing system400is. As yet another example, one or more sensor devices460may be used to identify an amount of scale depositions213that has accumulated on proppant112in a testing vessel472. As still another example, one or more sensor devices460may be used to identify a chemistry composition (e.g., one or more different chemistry components in the post-reaction fluid457that are not in the fluid437, one or more of the same chemistry components with different concentrations in the post-reaction fluid457relative to the concentrations in the fluid437) in the post-reaction fluid457that differs from the chemistry composition of the fluid437before flowing through the materials475. In some cases, a number of sensor devices460, each measuring a different parameter, may be used in combination to determine and confirm whether a controller404should take a particular action (e.g., operate a valve485, operate or adjust the operation of the post-reaction fluid collection system450). When a sensor device460includes its own controller404(or portions thereof), then the sensor device460may be considered a type of computer device, as discussed below with respect toFIG.6.

A user451may be any person that interacts, directly or indirectly, with a controller404and/or any other component of the testing system400. Examples of a user451may include, but are not limited to, a business owner, an engineer, a company representative, a geologist, a consultant, a drilling engineer, a contractor, and a manufacturer's representative. A user451may use one or more user systems455, which may include a display (e.g., a GUI). A user system455of a user451may interact with (e.g., send data to, obtain data from) the controller404via an application interface and using the communication links405. The user451may also interact directly with the controller404through a user interface (e.g., keyboard, mouse, touchscreen).

The network manager480is a device or component that controls all or a portion (e.g., a communication network, the controller404) of the testing system400. The network manager480may be substantially similar to the controller404, as described above. For example, the network manager480may include a controller that has one or more components and/or similar functionality to some or all of the controller404. Alternatively, the network manager480may include one or more of a number of features in addition to, or altered from, the features of the controller404. As described herein, control and/or communication with the network manager480may include communicating with one or more other components of the same testing system400or another system. In such a case, the network manager480may facilitate such control and/or communication. The network manager480may be called by other names, including but not limited to a master controller, a network controller, and an enterprise manager. The network manager480may be considered a type of computer device, as discussed below with respect toFIG.6.

Interaction between each controller404, the sensor devices460, the users451(including any associated user systems455), the network manager480, and other components (e.g., the valves485, an injection system438, the reaction module470, and the post-reaction fluid collection system450) of the testing system400may be conducted using communication links405and/or power transfer links487. Each communication link405may include wired (e.g., Class 1 electrical cables, Class 2 electrical cables, electrical connectors, Power Line Carrier, RS485) and/or wireless (e.g., Wi-Fi, Zigbee, visible light communication, cellular networking, Bluetooth, Bluetooth Low Energy (BLE), ultrawide band (UWB), WirelessHART, ISA100) technology. A communication link405may transmit signals (e.g., communication signals, control signals, data) between each controller404, the sensor devices460, the users451(including any associated user systems455), the network manager480, and the other components of the testing system400.

Each power transfer link487may include one or more electrical conductors, which may be individual or part of one or more electrical cables. In some cases, as with inductive power, power may be transferred wirelessly using power transfer links487. A power transfer link487may transmit power between each controller404, the sensor devices460, the users451(including any associated user systems455), the network manager480, and the other components of the testing system400. Each power transfer link487may be sized (e.g., 12 gauge, 18 gauge, 4 gauge) in a manner suitable for the amount (e.g., 480V, 24V, 120V) and type (e.g., alternating current, direct current) of power transferred therethrough.

FIG.5shows a system diagram of a controller404according to certain example embodiments. Referring toFIGS.1A through5, the controller404may be substantially the same as a controller404discussed above with respect toFIG.4. The controller404includes multiple components. In this case, the controller404ofFIG.5includes a control engine506, a communication module507, a timer535, a power module530, a storage repository531, a hardware processor521, a memory522, a transceiver524, an application interface526, and, optionally, a security module523. The controller404(or components thereof) may be located at or near the various components of the testing system400. In addition, or in the alternative, the controller404(or components thereof) may be located remotely from (e.g., in the cloud, at an office building) the various components of the testing system400.

The storage repository531may be a persistent storage device (or set of devices) that stores software and data used to assist the controller404in communicating with one or more other components of a system, such as the users451(including associated user systems455), each injection system438, the reaction module470, each post-reaction fluid collection system450, the network manager480, and the sensor devices460of the testing system400ofFIG.4above. In one or more example embodiments, the storage repository531stores one or more protocols532, algorithms533, and stored data534.

The protocols532of the storage repository531may be any procedures (e.g., a series of method steps) and/or other similar operational processes that the control engine506of the controller404follows based on certain conditions at a point in time. The protocols532may include any of a number of communication protocols that are used to send and/or obtain data between the controller404and other components of a system (e.g., testing system400). Such protocols532used for communication may be a time-synchronized protocol. Examples of such time-synchronized protocols may include, but are not limited to, a highway addressable remote transducer (HART) protocol, a wirelessHART protocol, and an International Society of Automation (ISA) 100 protocol. In this way, one or more of the protocols532may provide a layer of security to the data transferred within a system (e.g., testing system400). Other protocols532used for communication may be associated with the use of Wi-Fi, Zigbee, visible light communication (VLC), cellular networking, BLE, UWB, and Bluetooth.

The algorithms533may be any formulas, mathematical models, forecasts, simulations, and/or other similar tools that the control engine506of the controller404uses to reach a computational conclusion. For example, one or more algorithms533may be used, in conjunction with one or more protocols532, to assist the controller404to determine when to start, adjust, and/or stop the operation of the reaction module470and/or the post-reaction fluid collection system450. As another example, one or more algorithms533may be used, in conjunction with one or more protocols532, to assist the controller404to determine when to start, adjust, and/or stop the operation of an injection system438. As yet another example, one or more algorithms533may be used, in conjunction with one or more protocols532, to assist the controller404to identify an optimal formulation of a fluid to reduce or eliminate scale depositions213on proppant112within a testing vessel472. As still another example, one or more algorithms533may be used, in conjunction with one or more protocols532, to assist the controller404in identifying one or more chemistry components in the post-reaction fluid457that are not present in the fluid437before flowing through the materials475and evaluating the effect of those one or more chemistry components on some or all of the materials475over time.

An example of an algorithm533is represented by the formula: Q=[kA(Pi−Po)]÷μL, where Q is a flow rate (in cm3/s), Piis inlet fluid pressure (in Pa), Pois outlet fluid pressure (in Pa), μ is dynamic viscosity of the fluid (poise or Pa. S), L is the length of the material in the testing vessel472(in cm), k is the permeability of the materials475in the testing vessel472(in cm2), and A is the area of the k is the permeability of the materials475in the testing vessel472(in md).

Stored data534may be any data associated with a field (e.g., the subterranean formation110, the induced fractures101within the volume190adjacent to a wellbore120, the characteristics of proppant112used in a field operation), other fields (e.g., other wellbores and subterranean formations), the other components (e.g., the user systems455, the reaction module470, the materials475in the testing vessel472, the post-reaction fluid collection system450), including associated equipment (e.g., motors, pumps, compressors), of the testing system400, measurements made by the sensor devices460, threshold values, tables, results of previously run or calculated algorithms533, updates to protocols532, user preferences, and/or any other suitable data. Such data may be any type of data, including but not limited to historical data, present data, and future data (e.g., forecasts). The stored data534may be associated with some measurement of time derived, for example, from the timer535.

Examples of a storage repository531may include, but are not limited to, a database (or a number of databases), a file system, cloud-based storage, a hard drive, flash memory, some other form of solid-state data storage, or any suitable combination thereof. The storage repository531may be located on multiple physical machines, each storing all or a portion of the communication protocols532, the algorithms533, and/or the stored data534according to some example embodiments. Each storage unit or device may be physically located in the same or in a different geographic location.

The storage repository531may be operatively connected to the control engine506. In one or more example embodiments, the control engine506includes functionality to communicate with the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components in the testing system400. More specifically, the control engine506sends information to and/or obtains information from the storage repository531in order to communicate with the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components of the testing system400. As discussed below, the storage repository531may also be operatively connected to the communication module507in certain example embodiments.

In certain example embodiments, the control engine506of the controller404controls the operation of one or more components (e.g., the communication module507, the timer535, the transceiver524) of the controller404. For example, the control engine506may activate the communication module507when the communication module507is in “sleep” mode and when the communication module507is needed to send data obtained from another component (e.g., a sensor device460) in the testing system400. In addition, the control engine506of the controller404may control the operation of one or more other components (e.g., the reaction module470, the post-reaction fluid collection system450, an injection system438), or portions thereof, of the testing system400.

The control engine506of the controller404may communicate with one or more other components of the testing system400. For example, the control engine506may use one or more protocols532to facilitate communication with the sensor devices460to obtain data (e.g., measurements of various parameters, such as temperature, pressure, and flow rate), whether in real time or on a periodic basis and/or to instruct a sensor device460to take a measurement. The control engine506may use measurements of parameters taken by sensor devices460while a post-reaction fluid457flows from the reaction module470to the post-reaction fluid collection system450, as well as one or more protocols532and/or algorithms533, to analyze the contents of the post-reaction fluid457. As yet another example, the control engine506may use one or more algorithms533and/or protocols532to recommend a change to the formulation (e.g., adding a fluid component427, removing a fluid component427, increasing an amount of a fluid component427, decreasing an amount of a fluid component427) of a fluid437, based on the analysis of a prior post-reaction fluid457, in an attempt to optimize operational capability in a particular stage of a field operation.

The control engine506may generate and process data associated with control, communication, and/or other signals sent to and obtained from the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components of the testing system400. In certain embodiments, the control engine506of the controller404may communicate with one or more components of a system external to the testing system400. For example, the control engine506may interact with an inventory management system by ordering replacements for components or pieces of equipment (e.g., a sensor device460, a valve485, a motor) within the testing system400that has failed or is failing. As another example, the control engine506may interact with a contractor or workforce scheduling system by arranging for the labor needed to replace a component or piece of equipment in the testing system400. In this way and in other ways, the controller404is capable of performing a number of functions beyond what could reasonably be considered a routine task.

In certain example embodiments, the control engine506may include an interface that enables the control engine506to communicate with the sensor devices460, the user systems455, the network manager480, and the other components of the testing system400. For example, if a user system455operates under IEC Standard 62386, then the user system455may have a serial communication interface that will transfer data to the controller404. Such an interface may operate in conjunction with, or independently of, the protocols532used to communicate between the controller404and the users451(including corresponding user systems455), the sensor devices460, the network manager480, and the other components of the testing system400.

The control engine506(or other components of the controller404) may also include one or more hardware components and/or software elements to perform its functions. Such components may include, but are not limited to, a universal asynchronous receiver/transmitter (UART), a serial peripheral interface (SPI), a direct-attached capacity (DAC) storage device, an analog-to-digital converter, an inter-integrated circuit (I2C), and a pulse width modulator (PWM).

The communication module507of the controller404determines and implements the communication protocol (e.g., from the protocols532of the storage repository531) that is used when the control engine506communicates with (e.g., sends signals to, obtains signals from) the user systems455, the sensor devices460, the network manager480, and the other components of the testing system400. In some cases, the communication module507accesses the stored data534to determine which communication protocol is used to communicate with another component of the testing system400. In addition, the communication module507may identify and/or interpret the communication protocol of a communication obtained by the controller404so that the control engine506may interpret the communication. The communication module507may also provide one or more of a number of other services with respect to data sent from and obtained by the controller404. Such services may include, but are not limited to, data packet routing information and procedures to follow in the event of data interruption.

The timer535of the controller404may track clock time, intervals of time, an amount of time, and/or any other measure of time. The timer535may also count the number of occurrences of an event, whether with or without respect to time. Alternatively, the control engine506may perform a counting function. The timer535is able to track multiple time measurements and/or count multiple occurrences concurrently. The timer535may track time periods based on an instruction obtained from the control engine506, based on an instruction obtained from a user451, based on an instruction programmed in the software for the controller404, based on some other condition (e.g., the occurrence of an event) or from some other component, or from any combination thereof. In certain example embodiments, the timer535may provide a time stamp for each packet of data obtained from another component (e.g., a sensor device460) of the testing system400.

The power module530of the controller404obtains power from a power supply (e.g., AC mains) and manipulates (e.g., transforms, rectifies, inverts) that power to provide the manipulated power to one or more other components (e.g., the timer535, the control engine506) of the controller404, where the manipulated power is of a type (e.g., alternating current, direct current) and level (e.g., 12V, 24V, 120V) that may be used by the other components of the controller404. In some cases, the power module530may also provide power to one or more of the sensor devices460.

The power module530may include one or more of a number of single or multiple discrete components (e.g., transistor, diode, resistor, transformer) and/or a microprocessor. The power module530may include a printed circuit board, upon which the microprocessor and/or one or more discrete components are positioned. In addition, or in the alternative, the power module530may be a source of power in itself to provide signals to the other components of the controller404. For example, the power module530may be or include an energy storage device (e.g., a battery). As another example, the power module530may be or include a localized photovoltaic power system.

The hardware processor521of the controller404executes software, algorithms (e.g., algorithms533), and firmware in accordance with one or more example embodiments. Specifically, the hardware processor521may execute software on the control engine506or any other portion of the controller404, as well as software used by the users451(including associated user systems455), the network manager480, and/or other components of the testing system400. The hardware processor521may be an integrated circuit, a central processing unit, a multi-core processing chip, SoC, a multi-chip module including multiple multi-core processing chips, or other hardware processor in one or more example embodiments. The hardware processor521may be known by other names, including but not limited to a computer processor, a microprocessor, and a multi-core processor.

In one or more example embodiments, the hardware processor521executes software instructions stored in memory522. The memory522includes one or more cache memories, main memory, and/or any other suitable type of memory. The memory522may include volatile and/or non-volatile memory. The memory522may be discretely located within the controller404relative to the hardware processor521. In certain configurations, the memory522may be integrated with the hardware processor521.

In certain example embodiments, the controller404does not include a hardware processor521. In such a case, the controller404may include, as an example, one or more field programmable gate arrays (FPGA), one or more insulated-gate bipolar transistors (IGBTs), and/or one or more integrated circuits (ICs). Using FPGAs, IGBTs, ICs, and/or other similar devices known in the art allows the controller404(or portions thereof) to be programmable and function according to certain logic rules and thresholds without the use of a hardware processor. Alternatively, FPGAs, IGBTs, ICs, and/or similar devices may be used in conjunction with one or more hardware processors521.

The transceiver524of the controller404may send and/or obtain control and/or communication signals. Specifically, the transceiver524may be used to transfer data between the controller404and the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components of the testing system400. The transceiver524may use wired and/or wireless technology. The transceiver524may be configured in such a way that the control and/or communication signals sent and/or obtained by the transceiver524may be obtained and/or sent by another transceiver that is part of a user system455, a sensor device460, the network manager480, and/or another component of the testing system400. The transceiver524may send and/or obtain any of a number of signal types, including but not limited to radio frequency signals.

When the transceiver524uses wireless technology, any type of wireless technology may be used by the transceiver524in sending and obtaining signals. Such wireless technology may include, but is not limited to, Wi-Fi, Zigbee, VLC, cellular networking, BLE, UWB, and Bluetooth. The transceiver524may use one or more of any number of suitable communication protocols (e.g., ISA100, HART) when sending and/or obtaining signals.

Optionally, in one or more example embodiments, the security module523secures interactions between the controller404, the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components of the testing system400. More specifically, the security module523authenticates communication from software based on security keys verifying the identity of the source of the communication. For example, user software may be associated with a security key enabling the software of a user system455to interact with the controller404. Further, the security module523may restrict receipt of information, requests for information, and/or access to information.

A user451(including an associated user system455), the sensor devices460, the network manager480, and the other components of the testing system400may interact with the controller404using the application interface526. Specifically, the application interface526of the controller404obtains data (e.g., information, communications, instructions, updates to firmware) from and sends data (e.g., information, communications, instructions) to the user systems455of the users451, the sensor devices460, the network manager480, and/or the other components of the testing system400. Examples of an application interface526may be or include, but are not limited to, an application programming interface, a web service, a data protocol adapter, some other hardware and/or software, or any suitable combination thereof. Similarly, the user systems455of the users451, the sensor devices460, the network manager480, and/or the other components of the testing system400may include an interface (similar to the application interface526of the controller404) to obtain data from and send data to the controller404in certain example embodiments.

In addition, as discussed above with respect to a user system455of a user451, one or more of the sensor devices460, the network manager480, and/or one or more of the other components of the testing system400may include a user interface. Examples of such a user interface may include, but are not limited to, a graphical user interface, a touchscreen, a keyboard, a monitor, a mouse, some other hardware, or any suitable combination thereof.

The controller404, the users451(including associated user systems455), the sensor devices460, the network manager480, and the other components of the testing system400may use their own system or share a system in certain example embodiments. Such a system may be, or contain a form of, an Internet-based or an intranet-based computer system that is capable of communicating with various software. A computer system includes any type of computing device and/or communication device, including but not limited to the controller404. Examples of such a system may include, but are not limited to, a desktop computer with a Local Area Network (LAN), a Wide Area Network (WAN), Internet or intranet access, a laptop computer with LAN, WAN, Internet or intranet access, a smart phone, a server, a server farm, an android device (or equivalent), a tablet, smartphones, and a personal digital assistant (PDA). Such a system may correspond to a computer system as described below with regard toFIG.6.

Further, as discussed above, such a system may have corresponding software (e.g., user system software, sensor device software, controller software). The software may execute on the same or a separate device (e.g., a server, mainframe, desktop personal computer (PC), laptop, PDA, television, cable box, satellite box, kiosk, telephone, mobile phone, or other computing devices) and may be coupled by the communication network (e.g., Internet, Intranet, Extranet, LAN, WAN, or other network communication methods) and/or communication channels, with wire and/or wireless segments according to some example embodiments. The software of one system may be a part of, or operate separately but in conjunction with, the software of another system within the testing system400.

FIG.6illustrates one embodiment of a computing device618that implements one or more of the various techniques described herein, and which is representative, in whole or in part, of the elements described herein pursuant to certain example embodiments. For example, a controller404(including components thereof, such as a control engine506, a hardware processor520, a storage repository531, a power module530, and a transceiver524) may be considered a computing device618. Computing device618is one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and/or its possible architectures. Neither should the computing device618be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device618.

The computing device618includes one or more processors or processing units614, one or more memory/storage components615, one or more input/output (I/O) devices616, and a bus617that allows the various components and devices to communicate with one another. The bus617represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. The bus617includes wired and/or wireless buses.

The memory/storage component615represents one or more computer storage media. The memory/storage component615includes volatile media (such as random access memory (RAM)) and/or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). The memory/storage component615includes fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth).

One or more I/O devices616allow a user451to enter commands and information to the computing device618, and also allow information to be presented to the user160and/or other components or devices. Examples of input devices616include, but are not limited to, a keyboard, a cursor control device (e.g., a mouse), a microphone, a touchscreen, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g., a monitor or projector), speakers, outputs to a lighting network (e.g., DMX card), a printer, and a network card.

Various techniques are described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques are stored on or transmitted across some form of computer readable media. Computer readable media is any available non-transitory medium or non-transitory media that is accessible by a computing device. By way of example, and not limitation, computer readable media includes “computer storage media”.

“Computer storage media” and “computer readable medium” include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which is used to store the desired information and which is accessible by a computer.

The computer device618is connected to a network (not shown) (e.g., a LAN, a WAN such as the Internet, cloud, or any other similar type of network) via a network interface connection (not shown) according to some example embodiments. Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means take other forms, now known or later developed, in other example embodiments. Generally speaking, the computer system618includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments.

Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device618is located at a remote location and connected to the other elements over a network in certain example embodiments. Further, one or more embodiments is implemented on a distributed system having one or more nodes, where each portion of the implementation (e.g., an injection system438, the reaction module470, the post-reaction fluid collection system450) is located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node corresponds to a processor with associated physical memory in some example embodiments. The node alternatively corresponds to a processor with shared memory and/or resources in some example embodiments.

FIG.7shows a flowchart758of a method for optimizing chemical treatment at the subsurface for improved well performance according to certain example embodiments. While the various steps in this flowchart758are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and/or performed in a different order.

In addition, a person of ordinary skill in the art will appreciate that additional steps not shown inFIG.7may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computing device, such as the computing device618discussed above with respect toFIG.6, may be used to perform one or more of the steps for the methods shown inFIG.7in certain example embodiments. Any of the functions performed below by a controller404may involve the use of one or more protocols532, one or more algorithms533, and/or stored data534stored in a storage repository531. In addition, or in the alternative, any of the functions in the method may be performed by a user (e.g., user451).

The method shown inFIG.7is merely an example that may be performed by using an example system described herein. In other words, systems for optimizing chemical treatment at the subsurface for improved well performance may perform other functions using other methods in addition to and/or aside from those shown inFIG.7. Referring toFIGS.1A through7, the method shown in the flowchart758ofFIG.7begins at the START step and proceeds to step781, where information about the post-reaction fluid457is obtained. As used herein, the term “obtaining” may include receiving, retrieving, accessing, generating, etc. or any other manner of obtaining the information. The post-reaction fluid457is disposed in the post-reaction fluid collection system450. The post-reaction fluid457is a fluid437that has potentially been modified (e.g., the addition of one or more chemistry components) by the interaction of the fluid437with the materials475in a testing vessel472of the reaction module470.

The information may be obtained by a controller404(or an obtaining component thereof), which may include the controller404ofFIG.5above, using one or more algorithms533and/or one or more protocols532. The information may be obtained from a user451, including an associated user system455. In addition, or in the alternative, the information may be obtained from one or more sensor devices460that measure various parameters. Examples of the information obtained may include, but are not limited to, a composition of the post-reaction fluid457, a temperature of the post-reaction fluid457, a pressure of the post-reaction fluid457, a composition of the fluid437, and a composition (e.g., field scale deposits, simulated scale deposits, cement debris, filtered solids from produced fluids, proppant rock) of the materials475within the testing vessel472before and/or after the materials475are exposed to the fluid437.

Other information that may be obtained may include a reaction time of the fluid437with the materials475, as well as a design configuration of the materials475and the reaction module470. Yet other information that may be obtained may include an analysis of the dissolved ions or elements of the materials475and/or the post-reaction fluid457, the pH and other chemistry characteristics of the post-reaction fluid457, and the mass and percentage of dissolved solid phases after the reaction between the fluid437and the materials475. In certain example embodiments, the materials475include rock and proppant, and the materials475are designed to be representative of the fractured subterranean formation110adjacent to the wellbore120. The information may be obtained at one time (e.g., prior to testing), over a period of time, periodically, or on some other basis. The information may be currently obtained data. In addition, or in the alternative, the data may be historical (e.g., data obtained from a prior field operation of the subterranean formation110).

The fluid437may be made up of multiple fluid components427. Each fluid component427of a fluid437may be drawn from a fluid component source428using an associated injection system438and piping488. The fluid437may be provided to flow through the materials475in a testing vessel472using one or more injection systems438or an independent pumping system. The fluid components427of the fluid437may mix together naturally in a header489of the piping488and/or using a mixing module465. A fluid437may be or include, or a fluid component427may be, an acid (e.g., HCl (hydrochloric acid), CH3COOH (acetic acid), CH2O2(formic acid), HF (hydrofluoric acid), boric acid, etc.), a chelant, and/or some other chemical compound.

The composition (also sometimes referred to as the chemistry composition herein) of the fluid437may be known by a controller404. The composition of the fluid437may include a specific identification of each fluid component427and the amount (e.g., 10 ppm, mg/L) of each fluid component427. For example, a user451, including an associated user system455, may communicate the composition of the fluid437to the controller404. As another example, a controller404, using one or more protocols532and/or one or more algorithms533, may determine the composition of a fluid437that may be tested. In such a case, a controller404may communicate, using one or more protocols532, this composition to a user451so that the user451may manipulate the appropriate fluid component sources428and associated injection systems438to attain the desired fluid437. Alternatively, a controller404may manipulate, using one or more algorithms533and/or one or more protocols532, the appropriate fluid component sources428and associated injection systems438to attain the desired fluid437. The fluid437flows through the materials475in the testing vessel472continually over a period of time (e.g., hours, days, months).

In certain example embodiments, a controller404may also set and/or control the environment to which the materials475in the testing vessel472are exposed using one or more algorithms533and/or one or more protocols532. For example, if a goal of the testing is to subject the materials475in the testing vessel472to conditions found in the subterranean formation110, then the controller404may accordingly control factors such as the temperature and the pressure applied to the testing vessel472.

A chemistry component may be a chemical element or chemical compound that is in the post-reaction fluid457but was not present in the fluid437that interacted with the materials475to generate the post-reaction fluid457or that has a different concentration in the post-reaction fluid457compared to the concentration in the initial fluid437. The post-reaction fluid457may have a chemistry composition having one or more chemistry components. A controller404may be configured to identify and quantify, using measurements made by one or more sensor devices460, one or more algorithms533, and/or one or more protocols532, any chemistry components in the post-reaction fluid457.

In step782, one or more compatibility tests of the post-reaction fluid457are run with some or all of the materials475. Some or all of a compatibility test may be based on the information obtained about the post-reaction fluid457in step781. For example, factors such as time, concentration of the post-reaction fluid457, amount of the materials475, type of testing vessel472used, parameters measured, particular sensor devices460used to measure parameters, and conditions (e.g., temperature, pressure) applied to a testing vessel472may be derived from information obtained about the post-reaction fluid457.

Each compatibility test may be selected and run by a controller404using one or more algorithms533and/or one or more protocols532. A compatibility test may be selected and run based on one or more of a number of factors, including but not limited to a stage (e.g., completion stage, production stage) of a field operation, the one or more chemistry components added to the post-reaction fluid457relative to the fluid437, and the components of the material475. A compatibility test may be performed in one or more testing vessels472(e.g., a column, a bottle, a test tube). A compatibility test may be configured as a coreflood test setup.

A compatibility test may be used to evaluate whether there are negative impacts when substances (e.g., emulsion formation when oil and aqueous phase mix, solid precipitation) are mixed, when fluids and chemicals (e.g., friction reducer, surfactants, scale inhibitor) mix, and/or when precipitation on rock surfaces when fluid and rock (e.g., cutting samples) mix. In some cases, compatibility tests may be conducted in testing vessels472in the form of bottles (as shown inFIGS.15and16below) under target temperatures. If there is sign of reaction (e.g., precipitation formation, fluid color change, gas bubble generation, etc.), the tested components may be deemed as compatible. A decrease in permeability during a compatibility test may be a sign of incompatibility.

A compatibility test may be conducted entirely within the post-reaction fluid collection system450. Alternatively, a compatibility test may be conducted additionally using the reaction module470. In such a case, the post-reaction fluid457of a previous test may be used as a fluid437in a subsequent test using the testing system400. A compatibility test may involve one component, some components, or all of the components of the post-reaction fluid457and/or one component, some components, or all of the components of the materials475.

As discussed above, for treatment of the volume190using a fluid437during fracturing at a completion stage of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and crude oil (or other subterranean resource111) with rock, a mixture of the post-reaction fluid457and crude oil without rock, a mixture of the post-reaction fluid457and displacement fluid with rock, a mixture of the post-reaction fluid457and displacement fluid without rock, a mixture of the post-reaction fluid457and the fracturing fluid with rock, a mixture of the post-reaction fluid457and the fracturing fluid without rock, a mixture of the post-reaction fluid457and the formation water with rock, a mixture of the post-reaction fluid457and the formation water without rock, a mixture of the post-reaction fluid457and the completion brine with rock, and a mixture of the post-reaction fluid457and the completion brine without rock.

As another example, for treatment of the volume190using a fluid437for production enhancement during the production stage of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and crude oil (or other subterranean resource111) with rock, a mixture of the post-reaction fluid457and crude oil (a type of subterranean resource111) without rock, a mixture of the post-reaction fluid457and the formation water with rock, a mixture of the post-reaction fluid457and the formation water without rock, a mixture of the post-reaction fluid457and the completion brine with rock, and a mixture of the post-reaction fluid457and the completion brine without rock.

As yet another example, for treatment of the volume190using a fluid437for SWD well injectivity enhancement of a field operation, compatibility tests may include, but are not limited to, a mixture of the post-reaction fluid457and the injection water with rock, a mixture of the post-reaction fluid457and the injection water without rock, a mixture of the post-reaction fluid457and the formation water with rock, and a mixture of the post-reaction fluid457and the formation water without rock.

In step783, the effects of the post-reaction fluid457on the materials475are evaluated. Some or all of the effects may be based on, for example, parameters measured by one or more sensor devices460and provided to a controller404. Some or all of the effects may be evaluated by a controller404using one or more algorithms533and/or one or more protocols532. Examples of some effects may include, but are not limited to, the loss of a component (e.g., scale, proppant) of the materials475, the addition of a component (e.g., scale) in the materials475, the addition of a chemistry component (e.g., Fe, Ca, Si, etc.) in the post-reaction fluid457relative to the fluid437, a change in the permeability of the materials475in the testing vessel472, a change in the porosity of the materials475in the testing vessel472, and a change in the pH of the post-reaction fluid457. In some cases, the effects may be compared to expected values or results.

The post-reaction fluid457from a compatibility test and/or the effects of the post-reaction fluid457on the materials475during a compatibility test may be evaluated and characterized in any of a number of ways. The following table (Table 1) shows some ways in which post-reaction fluid457may be evaluated and/or characterized based on various non-limiting example analytical methods.

In step784, a determination is made as to whether adjustments need to be made to account for downhole conditions. Such adjustments may include, but are not limited to, the amount of time that the materials475are exposed to the fluid437, the flow rate of the fluid437through the materials475, and the pressure at which the materials475are under when exposed to the fluid437. The determination may be made by a controller404using one or more algorithms533and/or one or more protocols532. The determination may be based, at least in part, on information provided by a user451, data collected from one or more sensor devices460, results of one or more algorithms533, and/or stored data534in the storage repository531. If adjustments need to be made to account for downhole conditions, then the process proceeds to step787. If adjustments do not need to be made to account for downhole conditions, then the process proceeds to step785.

In step785, a determination is made as to whether the post-reaction fluid457is optimal. The determination may be made by a controller404based on the data obtained to that point and using one or more protocols532and/or algorithms533. The decision to adjust the post-reaction fluid457may be based on one or more of a number of factors, including but not limited to the size and/or amount of accumulated scale in the materials475, a change in the shape and/or size of the proppant112within the materials475, the condition of the flow channels through the materials475, and a change in the environment (e.g., pressure, temperature) of the materials475in the testing vessel482.

In some cases, this step785may include providing a recommendation about the post-reaction fluid457. The recommendation may be provided by a controller404(or a recommendation component thereof) using one or more protocols532. The recommendation may be provided to one or more users451(including associated user systems455) and/or the network manager480. The recommendation about the post-reaction fluid457may provide any level of detail about the post-reaction fluid457, including but not limited to the precise composition of the post-reaction fluid457, the positive and/or negative effects of the post-reaction fluid457on the materials475, and the expected results (e.g., improves production by approximately 75%) of using the post-reaction fluid457in the field operation. If the post-reaction fluid457is optimal, then the process proceeds to the END step. If the post-reaction fluid457is not optimal, then the process proceeds to step786.

In step786, the fluid437is adjusted. In other words, at least one aspect (e.g., an amount or concentration of a fluid component427, removal of a fluid component427, addition of a fluid component427) of the fluid437is changed. The fluid437may be adjusted by a controller404(or an adjusting component thereof) using one or more algorithms533and/or one or more protocols532. The controller404may also determine precisely how the fluid437should be adjusted. Alternatively, the fluid437may be adjusted by a user451. In such a case, a controller404may provide instructions to the user451(or an associated user system455) as to how the fluid437should be adjusted. When step786is finished, the process reverts to step781.

In step787, one or more adjustments are made to account for downhole conditions. In some cases, an adjustment may be made by a controller404(or an adjustment component thereof) using one or more algorithms533and/or one or more protocols532. Alternatively, an adjustment may be made by a user451based on information provided to the user451(including an associated user system455) by a controller404. In certain example embodiments, an adjustment is made to an algorithm533and/or a protocol532. In addition, or in the alternative, an adjustment may be made to the environment that the materials475experience in the testing vessel472of the reaction module470. When step787is complete, the process reverts to step781.

FIG.8shows a graph897of production of a subterranean resource111using a fluid437over time in the current art. Referring toFIGS.1A through8, the graph897ofFIG.8has one plot893that is laid out with production per day along the vertical axis and time (in days) along the horizontal axis. A fluid component427of the fluids437used for the plot893in the graph897includes 15% hydrochloric acid (HCl). To generate the plot893in the graph897ofFIG.8, the fluid437is run through fractures101in a subterranean formation110at a rate of 21 gallons per foot. Plot893represents the production of oil in units of barrels. Over the 100-day testing period shown in the graph897, the production of oil ranges between 250 barrels per day and 1000 barrels per day.

FIG.9shows a graph997of production of the same subterranean resource111inFIG.8using the same fluid437as inFIG.8over time in the current art. Referring toFIGS.1A through9, the graph997ofFIG.9has one plot993that is laid out with production per day along the vertical axis and time (in days) along the horizontal axis. As inFIG.8, a fluid component427of the fluids437used for the plot993in the graph997includes 15% hydrochloric acid (HCl). To generate the plot893in the graph997ofFIG.9, the fluid437is run through the fractures101in the subterranean formation110used inFIG.8at a rate of 10 gallons per foot, which is a bit less than half the flow rate used inFIG.8. Plot993represents the production of oil in units of barrels. Over the 100-day testing period shown in the graph997, the production of oil ranges between 1000 barrels per day and 2000 barrels per day, which is more than a 50% increase relative to the production of oil when the flow rate of the fluid437is doubled. These graphs897and997lead to the conclusion that there is an inverse relationship between the production rate of the subterranean resource111(in these cases, oil) and the flow rate of the fluid437through the fractures101in the subterranean formation110.

However, the graph897ofFIG.8and the graph997ofFIG.9do not show the secondary effects of the fluid437(in this example, 15% HCl) on the materials475that include rock in the form of shale.FIG.10shows a graph1098of chemistry components that are released when the fluid ofFIGS.8and9interact with a subterranean formation according to certain example embodiments. Referring toFIGS.1A through10, the graph1098ofFIG.10shows concentration (in mg/L) on a log scale along the vertical axis and eleven (11) chemistry components along the horizontal axis. The graph997shows that interaction between the fluid437and the materials in the volume190releases approximately 30,000 mg/L of calcium (Ca), approximately 3,000 mg/L of magnesium (Mg), approximately 1,100 mg/L of iron (Fe), approximately 500 mg/L of sodium (Na), approximately 300 mg/L of aluminum (Al), approximately 130 mg/L of silicon (Si), approximately 50 mg/L of potassium (K), approximately 12 mg/L of barium (Ba), approximately 110 mg/L of phosphorus (P), approximately 70 mg/L of manganese (Mn), and approximately 105 mg/L of sulfur (S).

FIG.11shows a graph1199of the saturation index of ferric hydroxide Fe(OH)3(or a variation thereof, such as Fe(OH)2.7Cl0.3) according to certain example embodiments. Referring toFIGS.1A through11, the graph1199ofFIG.11one plot1194of the saturation index along the vertical axis and pH values along the horizontal axis. In this example, a post-reaction fluid457includes 1 mg/L of Fe3+in 1M of NaCl at 170° F. The ferric hydroxide is formed when ferrous iron, released as a consequence of a reaction of a fluid437with materials475that includes rock, is oxidized, as shown by the chemical equation: Fe2++O2→Fe3++Fe(OH)3. The results of the plot1194show that the solubility of Fe3+is lower than 1 mg/L in 1M NaCl (TDS 58440 mg/L) fluid at pH 2 and above at 170° F.

FIGS.12through14show graphs of various chemistry components included in post-reaction fluids according to certain example embodiments. Specifically,FIG.12shows a graph1296of calcium in two different post-reaction fluids457.FIG.13shows a graph1396of iron in two other different post-reaction fluids457.FIG.14shows a graph1496of barium in yet two other different post-reaction fluids457. Referring toFIGS.1A through14, the graph1296ofFIG.12shows two plots of the mass (in mg) of calcium in a post-reaction fluid457along the vertical axis versus the volume (in mL) of fluid437(which includes 15% HCl in this case). The calcium is a byproduct of the reaction of the fluid437with materials475that becomes part of the post-reaction fluid457. Plot1288shows that, for one set of materials475, the mass of calcium in the post-reaction fluid457increases linearly as the volume of fluid437is increased until the volume of the fluid437reaches about 8 mL, at which point the increase in the mass of the calcium in the post-reaction fluid457increases more slowly but still linearly with the increase in volume of the fluid437. Plot1289shows that, for a different set of materials475, the mass of calcium in the post-reaction fluid457increases linearly as the volume of fluid437is increased until the volume of the fluid437reaches about 3 mL, at which point the mass of the calcium in the post-reaction fluid457remains around 100 mg with the increase in the volume of the fluid437.

FIG.13shows two plots of the mass (in mg) of iron in a post-reaction fluid457along the vertical axis versus the volume (in mL) of fluid437(which includes 15% HCl in this case). The iron is a byproduct of the reaction of the fluid437with materials475that becomes part of the post-reaction fluid457. Plot1388shows that, for one set of materials475, the mass of iron in the post-reaction fluid457increases linearly at a slow rate as the volume of fluid437is increased, ending at about 3 mg of iron in the post-reaction fluid457when the volume of fluid437is around 16 mL. Plot1389shows that, for a different set of materials475, the mass of iron in the post-reaction fluid457increases linearly and at a steep rate as the volume of fluid437is increased until the volume of the fluid437reaches about 3 mL, at which point the mass of the iron in the post-reaction fluid457increases at a significantly slower rate with further increases in the volume of the fluid437.

FIG.14shows two plots of the mass (in mg) of barium in a post-reaction fluid457along the vertical axis versus the volume (in mL) of fluid437(which includes 15% HCl in this case). The barium is a byproduct of the reaction of the fluid437with materials475that becomes part of the post-reaction fluid457. Plot1488shows that, for one set of materials475, the mass of barium in the post-reaction fluid457increases linearly at a relatively slow rate as the volume of fluid437is increased to about 8 mL, after which the mass of barium in the post-reaction fluid457increases linearly at a faster rate as the volume of fluid437is further increased. Plot1489shows that, for a different set of materials475, the mass of barium in the post-reaction fluid457increases substantially linearly and at a steep rate as the volume of fluid437is increased up to approximately 8 mL.

Similarly, ion type and ion concentration (referring to chemistry components) in produced water may have an influence on asphaltene interactions at liquid-liquid and solid-liquid interfaces within a volume190during a field operation. The generation of divalent/trivalent cations (e.g., Fe3+, Al3+, etc.) as chemistry components from the interaction of a fluid (e.g., an acid) with downhole materials475may promote asphaltene deposition risk.

The results of several experiments show the effectiveness of example embodiments. For example, in one series of experiments, 2 grams of washed and dried drill cuttings (the materials475) react with a fluid437of 2 mL of acid for 2 minutes at 165° F. After the 2 minutes, frac water (another fluid437) is added to the resulting mixture. For purposes of this example, this resulting mixture is the subject of the experiments. In this experiment, the frac water has a pH of 6.3, and at least some of the composition of the frac water is shown in Table 2 below, where the listed elements may be in ionic form:

The frac water (the fluid437) may also include different types of chemical additives, including but not limited to scale inhibitor, fraction reducer, and surfactant. These chemical additives, when present in the fluid437, may vary in their concentrations. Table 3 shows information about 12 different experiments of mixing the subject of the experiments with different versions of the frac water. The designation “PPT” means that scale depositions in the form of white precipitates have visibly formed on the surface of the cuttings.

FIG.15shows several testing vessels1572of a reaction module1570according to certain example embodiments. Specifically, the reaction module1570ofFIG.15shows the results of experiments conducted in four testing vessels1572that are each in the form of bottles. In this case, each testing vessel1572may serve as both a reaction module (e.g., reaction module470) and a post-reaction fluid collection system (e.g., post-reaction fluid collection system450). Referring toFIGS.1A through15, testing vessel1572-1corresponds to experiment number 3 listed in Table 3 above. Testing vessel1572-2corresponds to experiment number 4 listed in Table 3 above. Testing vessel1572-3corresponds to experiment number 5 listed in Table 3 above. Testing vessel1572-4corresponds to experiment number 6 listed in Table 3 above.

Each testing vessel1572has a material1575in the form of rock cuttings. Also, each testing vessel1572is filled (in this case, partially) with a fluid (e.g., fluid437) that interacts with the material1575. Over time, the fluid becomes a post-reaction fluid1557, and scale depositions1513may accumulate on the material1575in each testing vessel1572as a result of the interaction between the material1575and the fluid, which transforms to the post-reaction fluid1557. Specifically, scale depositions1513-1form on the material1575-1immersed in the fluid (and subsequently transforming into the post-reaction fluid1557-1) in testing vessel1572-1for 20 hours. Scale depositions1513-2form on the material1575-2immersed in the fluid (and subsequently transforming into the post-reaction fluid1557-2) in testing vessel1572-2for 20 hours. Scale depositions1513-3form on the material1575-3immersed in the fluid (and subsequently transforming into the post-reaction fluid1557-3) in testing vessel1572-3for 20 hours. Scale depositions1513-4form on the material1575-4immersed in the fluid (and subsequently transforming into the post-reaction fluid1557-4) in testing vessel1572-2for 20 hours.

In the experiments summarized in Table 3, there was no separation of oil and water observed. However, as different chemicals (e.g., different acids, different chelants, a combination of acids, a combination of chelants, a combination of one or more acids and one or more chelants) are added to and/or removed from the solution (e.g., the fluid437, the post-reaction fluid1537), different interactions with those chemicals to the materials1575may lead to different results.

As another example, experiments for example embodiments have shown that the formation of scale depositions (e.g., scale depositions213) may be caused by using a fluid (e.g., fluid437) that includes one or more chemical products (a type of fluid component427) having hydrofluoric acid (HF). In field operations directed to well stimulation, HF-based chemical products are used at times. As a result, based on experiments for example embodiments, calcium fluoride (CaF2) may be a post-reaction fluid457based on a mixture of the spent acid (which contains F−) and formation water (which contains Ca). Table 4 below shows a summary of experiment results that may be achieved by varying the ratio of acid for formation water.

When an acid product containing HF is used for well stimulation and/or the removal of scale depositions213and fines, the resulting chemical reaction with the materials475may result in the formation of CaF2precipitates while dissolving calcite scale.

FIG.16shows several testing vessels1672of another reaction module1670according to certain example embodiments. Specifically, the reaction module1670ofFIG.16shows the results of experiments conducted in five testing vessels1672that are each in the form of bottles. In this case, each testing vessel1672may serve as both a reaction module (e.g., reaction module470) and a post-reaction fluid collection system (e.g., post-reaction fluid collection system450). Referring toFIGS.1A through16, each testing vessel1672has multiple materials (similar to the materials475discussed above), where one material1675is in the form of cuttings from formation rock retrieved from a wellbore, and another material1775is in the form of oil retrieved from the wellbore. Also, each testing vessel1672is filled (in this case, partially) with a fluid (e.g., fluid437) that interacts with the materials1675,1775. Over time (e.g., 24 hours, one month), the fluid becomes a post-reaction fluid1657, and scale depositions1613(e.g., rust) may accumulate on the material1675in a testing vessel1672as a result of the interaction between the materials1675, the materials1775, and the fluid, which transforms to the post-reaction fluid1657.

In this case, testing vessel1672-1shows a compatible system with stable suspended materials1675-1and materials1775-1. Specifically, the materials1675-1, the materials1775-1, and the post-reaction fluid1657-1(which originates as a fluid (e.g., fluid437) that includes a brine and a friction reducer) are comingled with no visually detectable scale depositions. Testing vessel1672-2shows a slightly less compatible system with mostly stable suspended materials1675-2and materials1775-2. Specifically, most of the materials1675-2, the materials1775-2, and the post-reaction fluid1657-2(which originates as a fluid (e.g., fluid437) that includes a brine and a friction reducer of different concentrations compared to the fluid used in the testing vessel1672-1) are comingled. However, small amounts of the materials1675-2and the materials1775-2are settled on the bottom of the testing vessel1672-2, and small amounts of visually detectable scale depositions1613-2have formed on the materials1675-2that have settled to the bottom of the testing vessel1672-2.

Testing vessel1672-3shows an even slightly less compatible system compared to testing vessel1672-2, with mostly stable suspended materials1675-3and materials1775-3. Specifically, most of the materials1675-3, the materials1775-3, and the post-reaction fluid1657-3(which originates as a fluid (e.g., fluid437) that includes a brine and a friction reducer of different concentrations compared to the fluid used in the testing vessel1672-1and the testing vessel1672-2) are comingled. However, larger amounts of the materials1675-3and the materials1775-3are settled on the bottom of the testing vessel1672-3, and larger amounts of visually detectable scale depositions1613-3have formed on the materials1675-3that have settled to the bottom of the testing vessel1672-3.

Testing vessel1672-4shows an incompatible system, with most of the materials1675-4settled on the bottom of the testing vessel1672-4, most of the materials1775-4collecting above the post-reaction fluid1657-4(which originates as a fluid (e.g., fluid437) that includes a brine and a friction reducer of different concentrations compared to the fluid used in the testing vessel1672-1through the testing vessel1672-3), and significant amounts of visually detectable scale depositions1613-4having formed on the materials1675-4that have settled to the bottom of the testing vessel1672-4.

Testing vessel1672-5shows a system, with most of the materials1675-5settled on the bottom of the testing vessel1672-5, most of the materials1775-5collecting above the post-reaction fluid1657-5(which originates as a fluid (e.g., fluid437) that includes a brine and a friction reducer of different concentrations compared to the fluid used in the testing vessel1672-1through the testing vessel1672-4), and significant amounts of visually detectable scale depositions1613-5having formed on the materials1675-5that have settled to the bottom of the testing vessel1672-5. In this case, the post-reaction fluid1657-5is cloudier than the post-reaction fluid1657-4.

FIG.17shows a graph1792of elemental mapping by EDX of filtered solids after a reaction involving HF according to certain example embodiments. Referring toFIGS.1A through17, the graph1792ofFIG.17shows that the filtered solids may include carbon, calcium, chromium, oxygen, fluorine, iron, barium, sodium, magnesium, aluminum, strontium, phosphorous, and sulfur. In alternative cases, the filtered solids may include fewer (e.g., one, three, six) elements than what are shown inFIG.17. In other cases, there may be one or more of a number of additional or alternative solids, including but not limited to zinc and lead. The graph1792also shows that the molar ration of F to Ca is approximately 1.8, which is close to the stoichiometry of CaF2, and that, while calcite is dissolved, CaF2is generated at the same time. A conclusion that may be drawn from the graph1792ofFIG.17is that a fluid437that includes HF may not be an optimal choice for wells with materials475that have calcite scale issues or that have high calcite content in the rock.

FIGS.18A through18Cshow an image of a testing system1800that is modeled after the testing system400ofFIG.4according to certain example embodiments. Specifically,FIG.18Ashows a front view of the testing system1800.FIG.18Bshows a detailed view of part of the testing system1800.FIG.18Cshows a front view of the column2172of the testing system1800. Referring toFIGS.1A through18C, the testing system1800ofFIGS.18A through18Cincludes three fluid component sources1828, three injection systems1838, piping1888, a sensor device1860, a pressure relief valve1885, a testing module1870with a column1872(a form of testing vessel472) having materials (e.g., materials475, hidden from view) disposed therein, and a post-reaction fluid collection system1850. These components of the testing system1800are substantially similar to the corresponding components of the testing system400ofFIG.4.

The first fluid component source1828ofFIG.18Ais in the form of an anion brine source1828-1, which releases an anion brine (a form of a fluid component427) that is moved toward the testing module1870by a pump1838-1(a form of an injection system438) through piping1888. The second fluid component source1828ofFIG.18Ais in the form of a water source1828-2, which releases a water solution (another form of a fluid component427) that is moved toward the testing module1870by a pump1838-2(another form of an injection system438) through piping1888. In some cases, the water solution includes a scale inhibitor. The third fluid component source1828ofFIG.18Ais in the form of a cation brine source1828-3, which releases a cation brine (yet another form of a fluid component427) that is moved toward the testing module1870by a pump1838-3(yet another form of an injection system438) through piping1888.

The three fluid component sources1828combine at a part of the piping1888upstream of the testing module1870that forms a header1889. When the three fluid component sources1828combine in the piping1888, a resulting fluid (similar to the resulting fluid437ofFIG.4), which includes the anion brine, the water solution, and the cation brine, flows through some of the piping1888to the testing module1870. At the testing module1870, the fluid flows through the column1872(a form of testing vessel472). The column1872is filled (e.g., fully (packed), partly) with materials (hidden from view), such as proppant and formation rocks (e.g., cuttings).

The differential pressure sensor1860(a form of a sensor device460) of the system1800measures the difference between the pressure of the fluid entering the column1872and the pressure of the post-testing fluid (substantially the same as the post-testing fluid457ofFIG.4) exiting the column1872. The pressure relief valve1885may be adjusted when the values measured by the differential pressure sensor1860exceed a certain value or fall outside a range of values. The post-testing fluid, upon exiting the column1872, flows through some of the piping1888to the post-reaction fluid collection system1850, which is a form of the post-reaction fluid collection system450ofFIG.4. In this case, the column1872, the differential pressure sensor1860, the pressure relief valve1885, and some of the piping1888, including the header1889, are mounted to a frame1839that is substantially vertical.

As discussed above,FIG.18Cshows an image of the column1872of the testing system1800according to certain example embodiments. The column1872in this case has a body1873having a cylindrical shape. The body1873in this case has an approximate length of 18 inches. In certain example embodiments, the length of the body1873of the column1872may range from 4 inches to 36 inches. The body1873of the column1872in this example is substantially cylindrical in shape with an inner diameter (ID) of approximately ⅛ inches and an approximate outside diameter (OD) of approximately ⅜ inch. In alternative embodiments, the body1873of the column1872may have other shapes that are not fully or partially cylindrical. In certain example embodiments, the ID of the body1873of the column1872may range from ⅛ inches to 2.5 inches, and the OD of the body1873of the column1872may range from ¼ inch to 3 inches.

The body1873of the column1872is designed to withstand the conditions (e.g., pressure, flow rate, acidity) at which the materials (e.g., materials475) disposed therein and the fluid (e.g., fluid437) flowing therethrough are tested. The body1873of the column1872may be made of one or more of any of a number of suitable materials, including but not limited to stainless steel, plexiglass, ceramics, PEEK, PTFE, corrosion resistant alloys (CRAs). In certain example embodiments, the inner walls of the body1873of the column1872may be featureless and smooth. The thickness of the wall of the body1873may be configured (e.g., 1/16thinch thick to ½ inch thick) to withstand a minimum pressure (e.g., 500 psig), a normal testing pressure (e.g., 3000 psig), and/or a maximum pressure (e.g., 6000 psig) that may be used during testing. In some cases, the thickness of the wall of the body1873may be configured to be substantially uniform along its length.

The column1872may include one or more coupling features1874that are configured to couple the column1872to one or more other components (e.g., piping1888) of the testing system1800. For example, in this case, the column1872has two coupling features1874, where one coupling feature1874-1is located toward one end of the body1873of the column1872, and where the other coupling feature1874-2is located toward the opposite end of the body1873of the column1872. In this case, the coupling features1874are configured substantially identically to each other in the form of threaded nuts that mate with complementary threads disposed on the outer perimeter of adjacent piping (e.g., piping1888). In alternative embodiments, one or more of the coupling features1874may have a different configuration. Further, in alternative embodiments, the configuration of one coupling feature1874of the column1872may differ from the configuration of one or more of the other coupling features1874of the column1872. In any case, the coupling features1874are configured to couple to one or more other components of the testing system so that the desired testing conditions (e.g., pressure, flow rate) may be maintained.

In any case, one or more of the dimensions (e.g., the length, the outer diameter, the thread size) of a coupling feature1874may change based on one or more of a number of factors, including but not limited to the characteristics (e.g., outer diameter, length) of the body1873of the column1872and the characteristics (e.g., outer diameter, thread size) of another component (e.g., piping1888) of the testing system1800to which the a coupling feature1874of the column1872is configured to be coupled. For example, a coupling feature1874have an outer diameter that ranges from approximately ¼″ to approximately 3″ and a length that ranges from approximately ½″ to approximately 1.5″. In certain example embodiments, a coupling feature1874has a substantially uniform outer surface.

Example embodiments may be used to identify results (e.g., byproducts, elimination of chemistry components, addition of chemistry components) of the interaction of a fluid (e.g., an acid) with materials (e.g., rock, proppant, produced water) found downhole within a fractured volume within a subterranean formation. In some cases, example embodiments simulate downhole conditions to identify byproducts and/or other aspects of these results. Example embodiments may also analyze the effects of a post-reaction fluid on further interaction with resulting materials. Example embodiments may be used to fully or partially automate the process of identifying byproducts in post-reaction fluids and/or changes to the materials that are subject to an initial fluid, generating different post-reaction fluids from fluid components, providing a post-reaction fluid that itself flows through resulting materials in a testing vessel of a reaction module, and evaluating the effectiveness of the post-reaction fluid at optimizing a phase (e.g., completion, production) of a subterranean field operation. Example embodiments may also communicate the results of an evaluation of a post-reaction fluid, determine alternative post-reaction fluids that may be more effective, generate those alternative post-reaction fluids, and evaluate those alternative post-reaction fluids during and after testing. Using example embodiments, the materials that are tested may be subjected to conditions that mirror those of a subterranean formation (e.g., a fractured subterranean formation). Example embodiments may provide a number of benefits. Such benefits may include, but are not limited to, ease of use, extending the life of a producing well, optimize use of proppant in fractures, flexibility, configurability, and compliance with applicable industry standards and regulations.