TRACER INJECTION AND ANALYSIS CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This application claims priority to U.S. Provisional Application 63/401,753, filed on August 29, 2022, the contents of which is hereby incorporated by reference in its entirety. STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT [0002] Not applicable. TECHNICAL FIELD [0003] The disclosed embodiments relate generally to techniques for tracer injection and analysis. BACKGROUND [0004] Traditionally, the availability of different tracer types has been and continues to be limited in the industry. Thus, there is a need in the art for improvements related to tracers. SUMMARY [0005] In accordance with some embodiments, a method of tracer injection during hydraulic fracturing of a subsurface formation using a plurality of hydraulic fracturing stages is provided herein. The method includes (a) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a subset of the hydraulic fracturing stages via a wellbore drilled into the subsurface formation utilizing a plurality of injection schemes, such that substantially similar fluid segments and substantially similar proppant segments of the subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. The method includes (b) repeating at least a portion of the plurality of injection schemes applied to the subset of the hydraulic fracturing stages to inject substantially similar liquid tracer types into fluid segments and substantially similar solid tracer types into proppant segments of additional hydraulic fracturing stages via the wellbore drilled into the subsurface formation. [0006] In accordance with some embodiments, a method of tracer injection is provided herein. The method includes injecting first tracer types into first segments and second tracer types into second segments via a wellbore drilled into the subsurface formation, such that substantially similar first segments and substantially similar second segments are injected with substantially similar first tracer types and substantially similar second tracer types, respectively. [0007] In accordance with some embodiments, a method of tracer analysis is provided herein. The method includes obtaining concentration profile data for a plurality of tracer types, wherein the concentration profile data comprises a concentration profile as a function of time for each tracer type in a plurality of samples produced from a subsurface formation. Each tracer type was injected into the subsurface formation via a corresponding segment. The method includes estimating swept volume for each tracer type using the corresponding concentration profile as a function of time. [0008] In accordance with some embodiments, a system of tracer analysis is provided herein. The system includes one or more processors; memory; and one or more programs. The one or more programs are stored in the memory and configured to be executed by the one or more processors, the one or more programs including instructions that when executed by the one or more processors cause the system to obtain concentration profile data for a plurality of tracer types. The concentration profile data comprises a concentration profile as a function of time for each tracer type in a plurality of samples produced from a subsurface formation. Each tracer type was injected into the subsurface formation via a corresponding segment. The one or more programs include instructions that when executed by the one or more processors cause the system to estimate swept volume for each tracer type using the corresponding concentration profile as a function of time. [0009] In accordance with some embodiments, a method of tracer analysis is provided herein. The method includes obtaining a plurality of samples produced from a subsurface formation; and analyzing the plurality of samples to generate concentration profile data for a plurality of tracer types. The concentration profile data comprises a concentration profile as a function of time for each tracer type in the plurality of samples produced from the subsurface formation. Each tracer type was injected into the subsurface formation via a corresponding segment. The method includes estimating swept volume for each tracer type using the corresponding concentration profile as a function of time. BRIEF DESCRIPTION OF THE DRAWINGS [0010] The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements. [0011] FIG.1A shows a field system, including a wellbore, with which example embodiments may be used. [0012] FIGS.1B and 1C illustrate detailed views of FIG.1A according to certain example embodiments. [0013] FIGS.1D-1, 1D-2, 1D-3, and 1D-4 illustrate a tracer injection for a wellbore_a (similar to the wellbore 120 of FIG 1A) in a running example according to certain example embodiments. [0014] FIGS.1E-1, 1E-2, 1E-3, and 1E-4 illustrate a tracer injection for a wellbore_b (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. [0015] FIGS.1F-1, 1F-2, 1F-3, and 1F-4 illustrate a tracer injection for a wellbore_c (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. [0016] FIGS.1G-1, 1G-2, 1G-3, and 1G-4 illustrate a tracer injection for a wellbore_d (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. [0017] FIG.2 illustrates one embodiment of a method 200 of tracer injection during hydraulic fracturing of a subsurface formation using a plurality of hydraulic fracturing stages. [0018] FIG.3 shows an alternative wellbore with which example embodiments may be used. [0019] FIG.4 illustrates a system of tracer analysis (e.g., a computing system) in accordance with certain example embodiments. [0020] FIG.5 illustrates an example process 500 for tracer analysis. [0021] FIG.6A illustrates a diagram of an expected response. FIGS.6B, 6C, 6D, and 6E illustrate a concentration profiles as a function of time for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. [0022] FIG.7A illustrates a diagram of an expected response. FIG.7B, 7C, 7D, and 7E illustrate a concentration profile as a function of time for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. [0023] FIG.8 illustrates various equations for tracer analysis in accordance with certain example embodiments. [0024] FIG.9A, 9C, 9E, and 9G illustrate diagrams of swept volume for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. [0025] FIG.9B, 9D, 9F, and 9H illustrate diagrams of fracture area/volume growth rate for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. [0026] FIG.10A, 10C, 10E, and 10G illustrate diagrams of swept volume for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. [0027] FIG.10B, 10D, 10F, and 10H illustrates diagrams of fracture area/volume growth rate for wellbore_a, wellbore_b, wellbore_c, and wellbore_d, respectively, in accordance with certain example embodiments. DETAILED DESCRIPTION [0028] Embodiments for tracer injection and tracer analysis are provided herein. These embodiments may be utilized to quantify creation and drainage of hydraulic fracture geometry and/or conductive frac area and their growth rate with incremental fracturing fluid volume and proppant quantity. [0029] In hydraulic fracturing of conventional and unconventional resources, fractures are created with injection of fluid above fracturing pressure and proppant materials are injected to keep the fracture open and conductive. To optimize the fracture design and other development and completion decisions like well spacing, well placement, spacing between fracture, volume of fracturing fluid, quantity of proppant, pump rate, drawdown during production, etc., it is beneficial to quantify the fracture geometry created, conductive regions created, and/or its growth rate as function of incremental fracturing fluid volume and proppant quantity, as well as drainage area with time during production. [0030] Traditionally, liquid and solid tracers are injected with the fracturing fluid and proppant, but their injection and analysis method limit the learning opportunities to quantify the creation and drainage of hydraulic fracture geometry and/or conductive area and their growth rate with incremental fracturing fluid volume and proppant quantity. Other diagnostic technologies (non-tracer based technology) available in industry may provide some data regarding this topic, but those are limited and typically do not provide the detailed growth rate of fracture area created and/or drainage area with respect to incremental fracturing fluid volume and proppant quantity. [0031] Traditionally, tracers are injected during each hydraulic fracture stage pumping for individual fracture design, and analysis is performed of the sample collected during production and flowback of same or offset wells to quantify the fracture/drainage volume and mostly qualitative assessment of interwell communication corresponding to the total fracture fluid volume and proppant mass injected. Traditional tracer injection and analysis methodologies limit the learning capability and quantification of growth rate of fracture volume/area created and/or drainage area/volume for incremental fracturing fluid volume and proppant quantity. [0032] Embodiments of tracer injection (e.g., during hydraulic fracturing in conventional and unconventional resources) and analysis are provided herein that can provide data and information to quantify the creation and drainage of hydraulic fracture geometry, conductive frac area, and/or their growth rate with incremental frac fluid volume and proppant quantity. In some embodiments, a combination of unique liquid and solid tracers (e.g., both oil and water tracers) may be injected in each incremental frac fluid volume and proppant mass of an individual hydraulic frac stage (e.g., each 10 - 20% of frac fluid volume and proppant mass of individual frac stage may have different unique liquid and solid tracer types, respectively). The tracer injection design (tracer type, quantity and concentration, count of tracers for each frac stage, incremental volume for varying tracer type, etc.) may be optimized for each appropriate design change in fracture design of wellbore based on preliminary modeling work of fracture fluid and proppant placement mechanism inside fracture, and the return profile of tracer of collected samples from injected and offset wells. [0033] The frac design variation within a well or wells or across well pad / area / basin, etc. with application of different tracers and its optimized design further allows efficient data collection, quantification of impact of incremental volume of frac fluid volume and proppant quantity on the frac geometry and drainage growth rate. The analysis of the tracer data based on the enhanced injection of tracers in the field may depend on the mean residence time of each of the unique tracers pumped in the incremental frac fluid volumes and proppant mass respectively for both the offsets and the fractured well. This combined with Jain, Lokendra, Doorwar, Shashvat, and Daniel Emery. "Analytical Tracer Interpretation Model for Fracture Flow Characterization and Swept Volume Estimation in Unconventional Wells." URTEC-2021-5357-MS. Paper presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, Houston, Texas, USA, July 2021, which is incorporated by reference herein, may allow quantification of the frac and drainage area growth rate as a function of the frac fluid volume and proppant injected by assessing the incremental area/volume generated by each incremental portion of the frac fluid and proppant injected. The accompanying figures provide example embodiments and a running example for tracer injection and tracer analysis. [0034] Reference will now be made in detail to various embodiments, examples of which are illustrated in the accompanying drawings. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure and the embodiments described herein. However, embodiments described herein may be practiced without these specific details. In other instances, well-known methods, procedures, components, and mechanical apparatus have not been described in detail so as not to unnecessarily obscure aspects of the embodiments. [0035] TRACER INJECTION: FIG.1A shows a field system 199 with which example embodiments may be used. For simplicity, a single wellbore 120 is illustrated in FIG.1A. Tracer injection may be performed via the single wellbore 120, and a plurality of samples may be obtained from the fluid exiting the single wellbore 120 for tracer analysis. However, a plurality of wellbores may be drilled into a subsurface formation, and tracer injection and tracer analysis may be performed via the plurality of wellbores. Indeed, the running example utilized herein explains tracer injection and tracer analysis via for four wellbores, with each wellbore similar to the wellbore 120 of FIG.1A. Tracer analysis is discussed further hereinbelow in the tracer analysis section. [0036] Specifically, FIG.1A shows a schematic diagram of a land-based field system 199 in which a wellbore 120 has been drilled in a subsurface formation 110 and may be utilized for tracer injection. FIG.1B shows a detail of a substantially horizontal section 103 of the wellbore 120 of FIG.1A. FIG.1C shows a detail of a fracture 101 of FIG.1B. The field system 199 of FIG.1A may include field equipment 109 (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, wellhead, a tanks, a pump, etc.) located above a surface 108 and/or within the wellbore 120. Example embodiments may be applied to practically any wellbore of any configuration (e.g., wellbore with a substantially horizontal section as in FIG.1A) in which tracer injection may be performed. [0037] With respect to the system 199 of FIG.1A, once the wellbore 120 is drilled, a casing string 125 is inserted into the wellbore 120 to stabilize the wellbore 120 and allow for the extraction of subsurface resources (e.g., natural gas, oil, produced water) from the subsurface formation 110. Field equipment 109, located at the surface 108, is used to drill, encase, fracture, produce, and/or perform any other part of a field operation with respect to the wellbore 120. The wellbore 120 of FIG.1A starts out as substantially vertical, and then has a substantially horizontal section 103. [0038] The surface 108 may be ground level for an onshore application and the sea floor (or other similar floor under a body of water) for an offshore application. A body of water may include, but it not limited to, sea water, brackish water, flowback or produced water, wastewater (e.g., reclaimed or recycled), brine (e.g., reservoir or synthetic brine), fresh water (e.g., fresh water comprises < 1,000 ppm TDS), any other type of water, or any combination thereof. 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 wellbore 120 begins at the surface 108 may include a wellhead. [0039] While the subsurface formation 110 may have naturally-occurring fractures and some fractures that may have been created when drilling the wellbore 120, these fractures may need to be enlarged and elongated, and additional fractures may need to be created, in order to extract additional subsurface resources 111 (e.g., oil, natural gas) from the subsurface formation 110. In such cases, hydraulic fracturing processes may be utilized to accomplish these goals. The fractures 101 are shown to be located in the horizontal section 103 of the wellbore 120 in FIG.1B. The fractures 101, whether created 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 a wellbore 120. [0040] The subsurface formation 110 may 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 subsurface formation 110 may include one or more reservoirs in which one or more resources (e.g., oil, natural gas, water) 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 subsurface formation 110. [0041] The wellbore 120 may have one or more of a number of portions or hole portions, where each portion or hole portion 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 wellbore 120, a curvature of the wellbore 120, a total vertical depth of the wellbore 120, a measured depth of the wellbore 120, and a horizontal displacement of the wellbore 120. There may be multiple overlapping casing strings of various sizes (e.g., length, outer diameter) contained within and between these portions or hole portions to ensure the integrity of the wellbore construction. In this case, one or more of the portions of the subsurface wellbore 120 is the substantially horizontal section 103. [0042] As discussed above, inserted into and disposed within the wellbore 120 of FIGS.1A and 1B are a number of casing pipes that are coupled to each other end-to-end to form the casing string 125. 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 string 125 may be indirectly mechanically coupled to each other using a coupling device, such as a coupling sleeve. [0043] Each casing pipe of the casing string 125 may 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, 4-1/2 inches, 7 inches, 7-5/8 inches, 8-5/8 inches, 10-3/4 inches, 13-3/8 inches, and 14 inches. [0044] The size (e.g., width, length) of the casing string 125 may be based on the information (e.g., diameter of the borehole drilled) gathered using field equipment with respect to the wellbore 120. The walls of the casing string 125 and the casing string 225 have an inner surface that forms a cavity that traverses the length of the casing string 125. Each casing pipe may be made of one or more of a number of suitable materials, including but not limited to steel. Cement is poured into the wellbore 120 through the cavity and then forced upward between the outer surface of the casing string 125 and the wall of the wellbore 120. In some cases, a liner may additionally be used with, or alternatively be used in place of, some or all of the casing pipes. [0045] Referring to FIGS.1A, 1B, and 1C, once the cement dries and cures, a number of fractures 101 are created in the subsurface formation 110. The fractures 101 may be created in any of a number of ways known in the industry, including but not limited to hydraulic fracturing. The hydraulic fracturing process involves the injection of fracturing fluid and proppant 112 (e.g., sand, ceramic pellets) into the subsurface formation 110 from the wellbore 120 to create fracture networks. Even if a subsurface formation 110 naturally has fractures 101, these naturally occurring fractures 101 have inconsistent characteristics (e.g., length, spacing) and so in some cases cannot be relied upon for extracting subsurface resources without having additional fractures 101, such as what is shown in FIG.1B, created in the subsurface formation 110 such as through hydraulic fracturing. [0046] Turning to hydraulic fracturing, this may entail preparing an injection fluid (oftentimes referred to a fracturing fluid) and injecting that fracturing fluid into the wellbore 120 at a sufficient rate and pressure to open existing fractures and/or create fractures in the subsurface formation 110. The fractures 101 permit hydrocarbons to flow more freely into the wellbore 120. The fracturing fluid may also include proppant 112. The proppant 112, such as sand or other particles, are meant to hold the fractures 101 open so that hydrocarbons can more easily flow to the wellbore 120. The fracturing fluid and the proppant 112 may be stored in separate tanks and blended together using at least one blender (not shown). The fracturing fluid may also include other components in addition to the proppant 112. The wellbore 120 and the subsurface formation 110 proximate to the wellbore 120 are in fluid communication (e.g., via perforations), and the fracturing fluid with the proppant 112 is injected into the wellbore 120 into the subsurface formation 110 through a wellhead of the wellbore 120 using at least one pump (oftentimes called a fracturing pump). The fracturing fluid with the proppant 112 is injected at a sufficient rate and pressure to open existing fractures and/or create fractures in the subsurface formation 110. As fractures become sufficiently wide to allow proppant 112 to flow into those fractures 101, proppant 112 in the fracturing fluid are deposited in those fractures 101 during injection of the fracturing fluid. After the hydraulic fracturing process is completed, the fracturing fluid is removed by flowing or pumping it back out of the wellbore 120 as the wellbore 120 is put on production so that the fracturing fluid does not block the flow of hydrocarbons to the wellbore 120. The hydrocarbons will typically enter the same wellbore 120 from the subsurface formation 110 and go up to the surface 108 for further processing. [0047] As shown in FIG.1C, the proppant 112 is designed to become lodged inside at least some of the fractures 101 to keep those fractures 101 open after the fracturing operation is complete so that produced fluid containing subsurface resources 111 (e.g., hydrocarbons) can flow through the fractures 101 to the wellbore 120. Sizes (e.g., 40/70 mesh, 50/140 mesh) of the proppant 112 may vary. While the shape of the proppant 112 is shown as being uniformly spherical, and the size is substantially identical among the proppant 112, the actual sizes and shapes of the proppant 112 may vary. If the proppant 112 is too small, the proppant 112 will not be effective at keeping the fractures 101 open enough to effectively allow produced fluid containing subsurface resources 111 (e.g., hydrocarbons) to flow through the fractures 101 from the rock matrices 162 in the subsurface formation 110 to the wellbore 120. If the proppant 112 is too large, the proppant 112 may plug up the fractures 101, blocking the flow of the produced fluid containing subsurface resources 111 through the fractures 101. During hydraulic fracturing, the fluid flows in the opposite direction shown in FIG.1C. [0048] The use of proppant 112 in certain types of subsurface formations 110, such as shale, is useful. Shale formations typically have permeabilities on the order of microdarcys (µD) to nanodarcys (nD). When fractures 101 are created in such formations with low permeabilities, it is useful to sustain the fractures 101 and their permeability and conductivity for an extended period of time in order to extract more of the subsurface resources 111. [0049] The created fractures 101 may be spaced a distance 192 apart from each other by using stages or stage groups in the hydraulic fracturing process. Each stage group includes a plurality of stages. Further, the created fractures 101 create a volume 190 within the subsurface formation 110 where the rock matrix 162 of the subsurface formation 110 is connected to the high conductivity fractures 101 located a short distance away. [0050] Each fracture 101, whether created or naturally occurring, is defined by a wall 102, also called a frac face 102 herein. The frac face 102 provides a transition between the paths formed by the rock matrices 162 in the subsurface formation 110 and the fracture 101. The subsurface resources 111 flow through the paths formed by the rock matrices 162 in the subsurface formation 110 into the fracture 101. [0051] In short, fractures created through hydraulic fracturing may contribute to the viability and successful production of subsurface resources from a subsurface formation. However, there may be some uncertainty regarding fracture geometry and growth rate. With vertical and lateral heterogeneity of rock properties, frac growth and resultant frac geometry may be an uncertainty. The uncertainty may include (i) how does frac grow (growth rate vertically and laterally) and/or (ii) where do the fracturing fluid and proppant injected at different time of frac stage travel in a subsurface formation. Reducing this uncertainty may assist with decisions regarding well spacing (vertical and horizontal) and/or wine-rack (staggering). Reducing this uncertainty may assist with decisions regarding optimization of slurry volume per cluster (SVC) and/or fracturing fluid to proppant ratio. [0052] There may also be some uncertainty regarding fracture drainage mapping. Generated fracture properties may change with time and rock properties, and the overall drainage mapping of created fractures and subsurface formation may have uncertainty. Uncertainty may include: (i) how much of fracture is effectively cleaning up (and from where (e.g., near wellbore, far-field, etc.), (ii) how much of fracture area (near wellbore vs far-field) is effectively draining and producing (and its variation with time), and/or (iii) what is more important (fracturing fluid or proppant quantity) for given rock properties and reservoir fluid type. Reducing this uncertainty may assist with decisions regarding well spacing (vertical and horizontal) and/or wine-rack (staggering). Reducing this uncertainty may assist with decisions regarding optimization of slurry volume per cluster (SVC) and/or fracturing fluid to proppant ratio. [0053] Indeed, in hydraulic fracturing, fractures are created with injection of fracturing fluid above fracturing pressure and proppant materials to keep the fracture open and conductive. To optimize the fracture design and other development and completion decisions like well spacing, well placement, spacing between fracture, volume of fracturing fluid, quantity of proppant, pump rate, drawdown during production, etc., it is beneficial to quantify the fracture geometry created, conductive regions created, and/or its growth rate as function of incremental fracturing fluid volume and proppant quantity, as well as drainage area with time during production. [0054] Traditionally, the availability of different tracer types has been and continues to be limited in the industry, and as such, traditional tracer injection and analysis methodologies limit the learning capability. For example, traditionally, liquid and solid tracers are injected with the fracturing fluid and proppant, but their injection and analysis method limit the learning opportunities to quantify the creation and drainage of hydraulic fracture geometry and/or conductive area and their growth rate with incremental fracturing fluid volume and proppant quantity. Other diagnostic technologies (non-tracer-based technology) available in industry may provide some data regarding this topic, but those are limited and typically do not provide the detailed growth rate of fracture area created and/or drainage area with respect to incremental fracturing fluid volume and proppant quantity. [0055] Traditionally, tracers were injected during each hydraulic fracture stage pumping for individual fracture design, and analysis was performed of the sample collected during production and flowback of same or offset wells to quantify the fracture/drainage volume and mostly qualitative assessment of interwell communication corresponding to the total fracture fluid volume and proppant mass injected. Traditional tracer injection and analysis methodologies limit the learning capability and quantification of growth rate of fracture volume/area created and/or drainage area/volume for incremental fracturing fluid volume and proppant quantity. But again, traditionally, the availability of different tracer types has been and continues to be limited in the industry, and as such, traditional tracer injection and analysis methodologies limit the learning capability. [0056] Provided herein are methods and systems of tracer injection that may be utilized to reduce uncertainty, improve quantification, and improve decision making. One embodiment of a method of tracer injection during hydraulic fracturing of a subsurface formation using a plurality of hydraulic fracturing stages includes (a) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a subset of the hydraulic fracturing stages via a wellbore drilled into the subsurface formation utilizing a plurality of injection schemes, such that substantially similar fluid segments and substantially similar proppant segments of the subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. The embodiment of the method also includes (b) repeating at least a portion of the plurality of injection schemes applied to the subset of the hydraulic fracturing stages to inject substantially similar liquid tracer types into fluid segments and substantially similar solid tracer types into proppant segments of additional hydraulic fracturing stages via the wellbore drilled into the subsurface formation. [0057] Practically any liquid tracer may be utilized, such as, but not limited to, oil liquid tracers and/or water liquid tracers. Practically any solid tracer may be utilized, such as, but not limited to, oil solid tracers and/or water solid tracers. The plurality of injection schemes define (a) the amount of fracturing fluid to inject per wellbore including amount of fluid fracturing per fluid segment and sequence of fluid segments, (b) the amount of proppant to inject per wellbore including amount of proppant per proppant segment and sequence of proppant segments, and (c) total tracer mass for injection across all the wellbores for each tracer type and corresponding tracer mass per segment for each tracer type. However, the particular tracer types injected differ per wellbore. More information is provided in FIGS. 1D-1 to 1D-4 for wellbore_a, FIGS.1E-1 to 1E-4 for wellbore_b, FIGS.1F-1 to 1F-4 for wellbore_c, and FIGS.1G-1 to 1G-4 for wellbore_d. [0058] FIGS.1D-1, 1D-2, 1D-3, and 1D-4 illustrate a tracer injection for a wellbore_a 120a (similar to the wellbore 120 of FIG 1A) in a running example according to certain example embodiments. FIGS.1E-1, 1E-2, 1E-3, and 1E-4 illustrate a tracer injection for a wellbore_b 120b (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. FIGS.1F-1, 1F-2, 1F-3, and 1F-4 illustrate a tracer injection for a wellbore_c 120c (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. FIGS.1G-1, 1G-2, 1G-3, and 1G-4 illustrate a tracer injection for a wellbore_d 120d (similar to the wellbore 120 of FIG 1A) in the running example according to certain example embodiments. In the running example, the wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d 120d are on the same pad and same area with same completions designs. For simplicity, the letter “a” was added to various items from FIG.1A to simplify the discussion of the wellbore_a. the letter “b” was added to various items from FIG.1A to simplify the discussion of the wellbore_b. the letter “c” was added to various items from FIG.1A to simplify the discussion of the wellbore_c. and the letter “d” was added to various items from FIG.1A to simplify the discussion of the wellbore_d. Each stage group has a plurality of stages, either five or four stages, in the running example. Each stage in a particular stage group is treated in a substantially similar manner in the running example. [0059] The wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d 120d in the running example have 73 stages each, and tracer injection (and tracer analysis) is illustrated herein even with the limited availability of different tracer types in the industry. The availability of different tracer types has been and continues to be limited, therefore, tracer injection via more than one wellbore with 73 stages would be unlikely using traditional tracer injection methodologies because a user would simply be close to using up all of the available tracer types in the industry (and would likely be cost prohibitive as well). However, the running example illustrates tracer injection via four wellbores with seventy three stages each (e.g., utilizing 38 out of available 42 oil liquid tracer types) consistent with the principles of this disclosure. [0060] Wellbore_a: Turning to FIGS.1D-1, 1D-2, 1D-3, and 1D-4, these figures illustrate the tracer injection for the wellbore_a 120a (similar to the wellbore 120 of FIG 1A) in the running example. Wellbore_a 120a includes field equipment 109a, which includes a fracturing fluid tank, proppant tank, pump, and wellhead as well as seven liquid tracer tanks for liquid tracer1-liquid tracer7, seven solid tracer tanks for solid tracerA-solid tracerG, and a tracer pump. The wellbore_a 120a includes a casing string 125a, a substantially horizontal section 103a of the wellbore_a 120a, a volume 190a within the subsurface formation 110 where the rock matrix 162 of the subsurface formation 110 is connected to the high conductivity fractures 101 located a short distance away, and stage groups/stages illustrated in FIGS.1D-1, 1D-2, 1D-3. [0061] FIG.1D-1 illustrates tracer injection during hydraulic fracturing of the subsurface formation 110 of the first five stage groups closest to the toe of the wellbore_a 120a. The 1 ^st stage group includes stage 1, stage 2, stage 3, stage 4, and stage 5. The 2 ^nd stage group includes stage 6, stage 7, stage 8, stage 9, and stage 10. The 3 ^rd stage group includes stage 11, stage 12, stage 13, stage 14, and stage 15. The 4 ^th stage group includes stage 16, stage 17, stage 18, stage 19, and stage 20. The 5 ^th stage group includes stage 21, stage 22, stage 23, stage 24, and stage 25. [0062] Each stage in each stage group of the 1 ^st through 5 ^th stage groups in FIG.1D-1 was subdivided into a plurality of fluid segments and a plurality of proppant segments utilizing the plurality of injection schemes. Each stage in the 1 ^st stage group closest to the toe of the wellbore_a was subdivided into seven fluid segments (i.e., fluid segment1, fluid segment2, fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation2 / Design #5. Each stage in the 2 ^nd stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation4 / Design #4. Each stage in the 3 ^rd stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and five proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, and proppant segment5) according to the injection scheme referred to as Baseline / Design #3. Each stage in the 4 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation3 / Design #2. Each stage in the 5 ^th stage group was subdivided into three fluid segments (i.e., fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation1 / Design #1. In the running example, each fluid segment corresponds to about 10K gallons of fracturing fluid. In the running example, each proppant segment corresponds to about 10K pounds of the proppant 112. [0063] The tracer injection via wellbore_a includes (a) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a subset of the hydraulic fracturing stages via wellbore_a drilled into the subsurface formation 110 (e.g., 25 stages of the first five stage groups of the 73 stages of wellbore_a) utilizing a plurality of injection schemes (e.g., 5 injection schemes), such that substantially similar fluid segments and substantially similar proppant segments of the subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. The five different injection schemes in the running example that are utilized for all four wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d120 d are referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1. However, the particular liquid tracer types and solids tracer types used across the injection schemes for each wellbore may differ (as illustrated in the figures corresponding to wellbore_b 120b (FIGS.1E-1, 1E-2, 1E-3, 1E-4), wellbore_c 120c (FIGS.1F-1, 1F-2, 1F-3, 1F-4), and wellbore_d 120d (FIGS.1G-1, 1G-2, 1G-3, 1G-4)). [0064] For wellbore_a 120a, liquid tracer1 is injected into fluid segment1 across the five injection schemes, liquid tracer2 is injected into fluid segment2 across the five injection schemes, liquid tracer3 is injected into fluid segment3 across the five injection schemes, liquid tracer4 is injected into fluid segment4 across the five injection schemes, liquid tracer5 is injected into fluid segment5 across the five injection schemes, liquid tracer6 is injected into fluid segment6 across the five injection schemes, and liquid tracer7 is injected into fluid segment7 across the five injection schemes. For wellbore_a 120a, solid tracerA is injected into proppant segment1 across the five injection schemes, solid tracerB is injected into proppant segment2 across the five injection schemes, solid tracerC is injected into proppant segment3 across the five injection schemes, solid tracerD is injected into proppant segment4 across the five injection schemes, solid tracerE is injected into proppant segment5 across the five injection schemes, solid tracerF is injected into proppant segment6 across the five injection schemes, and solid tracerG is injected into proppant segment7 across the five injection schemes. [0065] As illustrated in FIG.1D-1, for wellbore_a 102a, each liquid tracer type may be stored in its own tank and each solid tracer type may be stored in its own tank. For instance, liquid tracer1 may be stored in liquid tracer1 tank, liquid tracer2 may be stored in liquid tracer2 tank, liquid tracer3 may be stored in liquid tracer3 tank, liquid tracer4 may be stored in liquid tracer4 tank, liquid tracer5 may be stored in liquid tracer5 tank, liquid tracer6 may be stored in liquid tracer6 tank, and liquid tracer7 may be stored in liquid tracer7 tank. Similarly, solid tracerA may be stored in solid tracerA tank, solid tracerB may be stored in liquid tracerB tank, solid tracerC may be stored in solid tracerC tank, solid tracerD may be stored in solid tracerD tank, solid tracerE may be stored in solid tracerE tank, solid tracerF may be stored in solid tracerF tank, and solid tracerG may be stored in solid tracerG tank. Fourteen tanks are illustrated in FIG.1D-1, with a tank for each different tracer type, and each tank of the fourteen tanks may be in fluidic communication with a least one pump (illustrated as a tracer pump) for injecting the fourteen tracer types into the wellbore_a via the wellhead. At least one valve (not shown) may be opened to allow a particular tracer type from a particular tracer tank to be injected into the wellhead of the wellbore_a 120a via the tracer pump. At least one valve (not shown) may be closed to stop a particular tracer type from a particular tracer tank to be injected into the wellhead of the wellbore_a 120a via the tracer pump. [0066] For fluid segment1 of wellbore_a 120a in FIG.1D-1, liquid tracer1 from the liquid tracer1 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment2 of wellbore_a 120a in FIG. 1D-1, liquid tracer2 from the liquid tracer2 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment3 of wellbore_a 120a in FIG.1D-1, liquid tracer3 from the liquid tracer3 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment4 of wellbore_a 120a in FIG.1D-1, liquid tracer4 from the liquid tracer4 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment5 of wellbore_a 120a in FIG.1D-1, liquid tracer5 from the liquid tracer5 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment6 of wellbore_a 120a in FIG.1D-1, liquid tracer6 from the liquid tracer6 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment7 of wellbore_a 120a in FIG. 1D-1, liquid tracer7 from the liquid tracer7 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. [0067] For proppant segment1 of wellbore_a 120a in FIG.1D-1, solid tracerA from the solid tracerA tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds of proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment2 of wellbore_a 120a in FIG.1D-1, solid tracerB from the solid tracerB tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment3 of wellbore_a 120a in FIG.1D-1, solid tracerC from the solid tracerC tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment4 of wellbore_a 120a in FIG.1D-1, solid tracerD from the solid tracerD tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment5 of wellbore_a 120a in FIG.1D-1, solid tracerE from the solid tracerE tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment6 of wellbore_a 120a in FIG.1D-1, solid tracerF from the solid tracerF tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment7 of wellbore_a 120a in FIG.1D-1, solid tracerG from the solid tracerG tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. [0068] The tracer injection during hydraulic fracturing may occur in a substantially similar sequence across the five injection schemes as illustrated in FIG.1D-1. For instance, the sequence may be injecting liquid tracer1 into fluid segment1 first, then injecting liquid tracer2 into fluid segment2 next after injection into fluid segment1 has completed, then injecting liquid tracer3 into fluid segment3 next after injection into fluid segment2 has completed, etc. For instance, the sequence may be injecting solid tracerA into proppant segment1 first, then injecting solid tracerB into proppant segment2 next after injection into proppant segment1 has completed, then injecting solid tracerC into proppant segment3 next after injection into proppant segment2 has completed, etc. Moreover, a fluid segment and a proppant segment may commence and/or end at different times depending on how long the injection takes for that segment. For instance, even though fluid segment7 with liquid tracer7 is illustrated next to proppant segment7 with solid tracerG for simplicity, the fluid segment7 with liquid tracer7 may complete faster than the proppant segment7 with solid tracerG. [0069] Turning to FIG.1D-2, the tracer injection may include (b) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_a) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer1 in fluid segment1, liquid tracer2 in fluid segment2, etc. of wellbore_a) and substantially similar solid tracer types into proppant segments (e.g., solid tracerA in proppant segment1, solid tracerB in proppant segment2, etc. of wellbore_a) of additional hydraulic fracturing stages (e.g., 6 ^th stage group that includes stages 26-30, 7 ^th stage group that includes stages 31-35, etc. of wellbore_a) via the wellbore_a 102a drilled into the subsurface formation 110. [0070] FIG.1D-2 illustrates tracer injection during hydraulic fracturing of the subsurface formation 110 of the next five stage groups of the wellbore_a 120a. The 6 ^th stage group includes stage 26, stage 27, stage 28, stage 29, and stage 30. The 7 ^th stage group includes stage 31, stage 32, stage 33, stage 34, and stage 35. The 8 ^th stage group includes stage 36, stage 37, stage 38, stage 39, and stage 40. The 9 ^th stage group includes stage 41, stage 42, stage 43, stage 44, and stage 45. The 10 ^th stage group includes stage 46, stage 47, stage 48, stage 49, and stage 50. [0071] Each stage in each stage group of the 6 ^th through 10 ^th stage groups in FIG.1D- 2 was subdivided into a plurality of fluid segments and a plurality of proppant segments utilizing the plurality of injection schemes similar to the 1 ^st through 5 ^th stage groups in FIG. 1D-1. Each stage in the 6 ^th stage group of the wellbore_a was subdivided into seven fluid segments (i.e., fluid segment1, fluid segment2, fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation2 / Design #5. Each stage in the 7 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation4 / Design #4. Each stage in the 8 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and five proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, and proppant segment5) according to the injection scheme referred to as Baseline / Design #3. Each stage in the 9 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation3 / Design #2. Each stage in the 10 ^th stage group was subdivided into three fluid segments (i.e., fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation1 / Design #1. Again, in the running example, each fluid segment corresponds to about 10K gallons of fracturing fluid. In the running example, each proppant segment corresponds to about 10K pounds of the proppant 112. [0072] For fluid segment1 of wellbore_a 120a in FIG.1D-2, liquid tracer1 from the liquid tracer1 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment2 of wellbore_a 120a in FIG. 1D-2, liquid tracer2 from the liquid tracer2 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment3 of wellbore_a 120a in FIG.1D-2, liquid tracer3 from the liquid tracer3 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment4 of wellbore_a 120a in FIG.1D-2, liquid tracer4 from the liquid tracer4 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment5 of wellbore_a 120a in FIG.1D-2, liquid tracer5 from the liquid tracer5 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment6 of wellbore_a 120a in FIG.1D-2, liquid tracer6 from the liquid tracer6 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment7 of wellbore_a 120a in FIG. 1D-2, liquid tracer7 from the liquid tracer7 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. [0073] For proppant segment1 of wellbore_a 120a in FIG.1D-2, solid tracerA from the solid tracerA tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds of proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment2 of wellbore_a 120a in FIG.1D-2, solid tracerB from the solid tracerB tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment3 of wellbore_a 120a in FIG.1D-2, solid tracerC from the solid tracerC tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment4 of wellbore_a 120a in FIG.1D-2, solid tracerD from the solid tracerD tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment5 of wellbore_a 120a in FIG.1D-2, solid tracerE from the solid tracerE tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment6 of wellbore_a 120a in FIG.1D-2, solid tracerF from the solid tracerF tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment7 of wellbore_a 120a in FIG.1D-2, solid tracerG from the solid tracerG tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. [0074] Turning to FIG.1D-3, optionally, the tracer injection may include (b) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_a) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer1 in fluid segment1, liquid tracer2 in fluid segment2, etc. of wellbore_a) and substantially similar solid tracer types into proppant segments (e.g., solid tracerA in proppant segment1, solid tracer in proppant segment2, etc. of wellbore_a) of additional hydraulic fracturing stages (e.g., 11 ^th stage group that includes stages 51-55, 12 ^th stage group that includes stages 56-59, etc. of wellbore_a) via the wellbore_a 102a drilled into the subsurface formation 110. [0075] FIG.1D-3 illustrates tracer injection during hydraulic fracturing of the subsurface formation 110 of the next five stage groups closest to the heel of the wellbore_a 120a. The 11 ^th stage group includes stage 51, stage 52, stage 53, stage 54, and stage 55. The 12 ^th stage group includes stage 56, stage 57, stage 58, and stage 59. The 13 ^th stage group includes stage 60, stage 61, stage 62, stage 63, and stage 64. The 14 ^th stage group includes stage 65, stage 66, stage 67, and stage 68. The 15 ^th stage group includes stage 69, stage 70, stage 71, stage 72, and stage 73. The 12 ^th and 14 ^th stage groups have four stages each instead of five stages. [0076] Each stage in each stage group of the 11 ^th through 15 ^th stage groups in FIG. 1D-3 was subdivided into a plurality of fluid segments and a plurality of proppant segments utilizing the plurality of injection schemes similar to the 1 ^st through 5 ^th stage groups in FIG. 1D-1. Each stage in the 11 ^th stage group of the wellbore_a was subdivided into seven fluid segments (i.e., fluid segment1, fluid segment2, fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation2 / Design #5. Each stage in the 12 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and seven proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, proppant segment5, proppant segment6, and proppant segment7) according to the injection scheme referred to as Variation4 / Design #4. Each stage in the 13 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and five proppant segments (i.e., proppant segment1, proppant segment2, proppant segment3, proppant segment4, and proppant segment5) according to the injection scheme referred to as Baseline / Design #3. Each stage in the 14 ^th stage group was subdivided into five fluid segments (i.e., fluid segment3, fluid segment4, fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation3 / Design #2. Each stage in the 15 ^th stage group was subdivided into three fluid segments (i.e., fluid segment5, fluid segment6, and fluid segment7) and three proppant segments (i.e., proppant segment1, proppant segment2, and proppant segment3) according to the injection scheme referred to as Variation1 / Design #1. Again, in the running example, each fluid segment corresponds to about 10K gallons of fracturing fluid. In the running example, each proppant segment corresponds to about 10K pounds of the proppant 112. [0077] For fluid segment1 of wellbore_a 120a in FIG.1D-3, liquid tracer1 from the liquid tracer1 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment2 of wellbore_a 120a in FIG. 1D-3, liquid tracer2 from the liquid tracer2 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment3 of wellbore_a 120a in FIG.1D-3, liquid tracer3 from the liquid tracer3 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment4 of wellbore_a 120a in FIG.1D-3, liquid tracer4 from the liquid tracer4 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment5 of wellbore_a 120a in FIG.1D-3, liquid tracer5 from the liquid tracer5 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment6 of wellbore_a 120a in FIG.1D-3, liquid tracer6 from the liquid tracer6 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. For fluid segment7 of wellbore_a 120a in FIG. 1D-3, liquid tracer7 from the liquid tracer7 tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K gallons of fracturing fluid from the fracturing fluid tank into the wellhead of the wellbore_a using the pump. [0078] For proppant segment1 of wellbore_a 120a in FIG.1D-3, solid tracerA from the solid tracerA tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds of proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment2 of wellbore_a 120a in FIG.1D-3, solid tracerB from the solid tracerB tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment3 of wellbore_a 120a in FIG.1D-3, solid tracerC from the solid tracerC tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment4 of wellbore_a 120a in FIG.1D-3, solid tracerD from the solid tracerD tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment5 of wellbore_a 120a in FIG.1D-3, solid tracerE from the solid tracerE tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment6 of wellbore_a 120a in FIG.1D-3, solid tracerF from the solid tracerF tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. For proppant segment7 of wellbore_a 120a in FIG.1D-3, solid tracerG from the solid tracerG tank may be injected into the wellhead of the wellbore_a using the tracer pump during injection of the 10K pounds proppant from the proppant tank into the wellhead of the wellbore_a using the pump. [0079] Turning to FIG.1D-4, the particular amount of a particular liquid tracer type to be injected into a particular fluid segment of wellbore_a 120a may be based on a total tracer mass for that particular liquid tracer and number of fluid segments to receive that particular liquid tracer type according to the plurality of injection schemes, including specifics regarding repetition. Similarly, the particular amount of a particular solid tracer type to be injected into a particular proppant segment of wellbore_a 120a may be based on a total tracer mass for that particular solid tracer and number of proppant segments to receive that particular solid tracer type according to the plurality of injection schemes, including specifics regarding repetition. Indeed, the plurality of injection schemes define (a) the amount of fracturing fluid to inject per wellbore including amount of fluid fracturing per fluid segment and sequence of fluid segments, (b) the amount of proppant to inject per wellbore including amount of proppant per proppant segment and sequence of proppant segments, and (c) total tracer mass for injection across all the wellbores for each tracer type and corresponding tracer mass per segment for each tracer type. However, the particular tracer types injected differ per wellbore. A user may determine up front before hydraulic fracturing and before tracer injection the value of total mass of a particular liquid tracer or a particular solid tracer for tracer injection based on experience, physics regarding flow, and/or ability to inject enough of the particular tracer such that the particular tracer gets produced in a sufficient quantity to be detected in a lab to generate a tracer concentration profile for that particular tracer. [0080] FIG.1D-4 illustrates total mass for a particular tracer type, mass per segment for a particular tracer type, number of segments that received a particular tracer type, etc. for the fourteen tracer types injected via wellbore_a 120a as discussed in connection with FIGS. 1D-1, 1D-2, and 1D-3. For instance, a user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer1 to inject via wellbore_a is about 25.92 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 1.73 kg (25.92 kg / 15 = 1.728 kg) was injected into each fluid segment1 of the 15 fluid segment1 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer2 to inject via wellbore_a is about 25.92 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 1.73 kg (25.92 kg / 15 = 1.728 kg) was injected into each fluid segment2 of the 15 fluid segment2 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer3 to inject via wellbore_a is about 22.27 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.38 kg (22.27 kg / 58 = 0.383 kg) was injected into each fluid segment3 of the 58 fluid segment3 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer4 to inject via wellbore_a is about 22.27 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.38 kg (22.27 kg / 58 = 0.383 kg) was injected into each fluid segment4 of the 58 fluid segment4 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer5 to inject via wellbore_a is about 26.59 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.38 kg (26.59 kg / 73 = 0.364 kg) was injected into each fluid segment5 of the 73 fluid segment5 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer6 to inject via wellbore_a is about 26.59 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.38 kg (26.59 kg / 73 = 0.364 kg) was injected into each fluid segment6 of the 73 fluid segment6 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of liquid tracer7 to inject via wellbore_a is about 28.03 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.38 kg (28.03 kg / 73 = 0.383 kg) was injected into each fluid segment7 of the 73 fluid segment7 in the running example. [0081] For instance, a user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerA to inject via wellbore_a is about 5.85 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.08 kg (5.85 kg / 73 = 0.080 kg) was injected into each proppant segment1 of the 73 proppant segment1 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerB to inject via wellbore_a is about 5.48 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.08 kg (5.48 kg / 73 = 0.075 kg) was injected into each proppant segment2 of the 73 proppant segment2 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerC to inject via wellbore_a is about 6.2 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.08 kg (6.2 kg / 73 = 0.084 kg) was injected into each proppant segment3 of the 73 proppant segment3 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerD to inject via wellbore_a is about 5.85 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.13 kg (5.85 kg / 44 = 0.132 kg) was injected into each proppant segment4 of the 44 proppant segment4 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerE to inject via wellbore_a is about 5.85 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.13 kg (5.85 kg / 44 = 0.132 kg) was injected into each proppant segment5 of the 44 proppant segment5 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerF to inject via wellbore_a is about 5.8 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.2 kg (5.8 kg / 29 = 0.2 kg) was injected into each proppant segment6 of the 29 proppant segment6 in the running example. A user may determine up front before hydraulic fracturing and before tracer injection that the total mass of solid tracerG to inject via wellbore_a is about 5.8 kg. Across the 73 stages of wellbore_a and across the five injection schemes, about 0.2 kg (5.8 kg / 29 = 0.2 kg) was injected into each proppant segment7 of the 29 proppant segment7 in the running example. [0082] As illustrated in FIGS.1D-1, 1D-2, and 1D-3, at least one hydraulic fracturing stage of the wellbore_a is representative of a stage group, and wherein an injection scheme is utilized via the wellbore_a for each hydraulic fracturing stage of the stage group. Furthermore, FIGS.1D-1, 1D-2, 1D-3, and 1D-4 illustrate tracer injection into all 73 stages of the 1 ^st -15 ^th stage groups of wellbore_a 120a. Thus, liquid tracer types and solid tracer types were injected into fluid segments and proppant segments, respectively, of all hydraulic fracturing stages (e.g., 73 stages) via the wellbore_a 120a drilled into the subsurface formation 110 by (a) and (b). However, in some embodiments, tracer injection may be performed according to steps (a) and (b) in fewer than all of the hydraulic fracturing stages, such as performed for stages 1-25 of the 1 ^st – 5 ^th stage groups (FIG.1D-1) and repeated for stages 26-50 of the 6 ^th – 10 ^th stage groups (FIG.1D-2) and not repeated for stages 51-73 of the 11 ^th – 15 ^th stage groups (FIG.1D-3). [0083] Wellbore_b: Turning to FIGS.1E-1, 1E-2, 1E-3, and 1E-4, these figures illustrate the tracer injection for the wellbore_b 120b (similar to the wellbore 120 of FIG 1A) in the running example. Wellbore_b 120b includes field equipment 109b, which includes a fracturing fluid tank, proppant tank, pump, and wellhead as well as seven liquid tracer tanks for liquid tracer8-liquid tracer14, seven solid tracer tanks for solid tracerH-solid tracerN, and a tracer pump. The tracer pump for wellbore_b may be different than the tracer pump for one or more of the wellbore_a, wellbore_c, and wellbore_d to inject tracer types into multiple wellbores at about the same time. The tracer pump for wellbore_b may be the same as the tracer pump for one or more of the wellbore_a, wellbore_c, and wellbore_d to inject tracer types into one wellbore at a time. The wellbore_b 120b includes a casing string 125b, a substantially horizontal section 103b of the wellbore_b 120b, a volume 190b within the subsurface formation 110 where the rock matrix 162 of the subsurface formation 110 is connected to the high conductivity fractures 101 located a short distance away, and stage groups/stages illustrated in FIGS.1E-1, 1E-2, 1E-3. Wellbore_b has 15 stage groups, and each stage group has five stages except that the 11 ^th and 13 ^th stage groups have four stages each instead of five stages for wellbore_b. [0084] As illustrated in FIG.1E-1, the tracer injection via wellbore_b includes (i) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a second subset of hydraulic fracturing stages via the second wellbore drilled into the subsurface formation 110 (e.g., 25 stages of the first five stage groups of the 73 stages of wellbore_b) utilizing the plurality of injection schemes (e.g., 5 injection schemes utilized for wellbore_a), such that substantially similar fluid segments and substantially similar proppant segments of the second subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. Again, the five different injection schemes in the running example that are utilized for all four wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d 120d are referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1. However, the particular liquid tracer types and solids tracer types used across the injection schemes for each wellbore may differ (as illustrated in the figures corresponding to wellbore_b 120b (FIGS.1E-1, 1E-2, 1E-3, 1E-4), wellbore_c 120c (FIGS.1F-1, 1F-2, 1F-3, 1F-4), and wellbore_d 120d (FIGS.1G-1, 1G-2, 1G-3, 1G-4)). The liquid tracer types used via wellbore_b are liquid tracer8-liquid tracer14 and solid tracerH-solid tracerN. [0085] Turning to FIG.1E-2, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_b) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer8 in fluid segment1, liquid tracer9 in fluid segment2, etc. of wellbore_b) and substantially similar solid tracer types into proppant segments (e.g., solid tracerH in proppant segment1, solid tracerI in proppant segment2, etc. of wellbore_b) of additional hydraulic fracturing stages (e.g., 6 ^th stage group that includes stages 26-30, 7 ^th stage group that includes stages 31-35, etc. of wellbore_b) via the wellbore_b 102b drilled into the subsurface formation 110. [0086] Turning to FIG.1E-3, optionally, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_b) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer8 in fluid segment1, liquid tracer9 in fluid segment2, etc. of wellbore_b) and substantially similar solid tracer types into proppant segments (e.g., solid tracerH in proppant segment1, solid tracerI in proppant segment2, etc. of wellbore_b) of additional hydraulic fracturing stages (e.g., 11 ^th stage group that includes stages 51-54, 12 ^th stage group that includes stages 55-59, etc. of wellbore_b) via the wellbore_b 102b drilled into the subsurface formation 110. [0087] FIG.1E-4 illustrates total mass for a particular tracer type, mass per segment for a particular tracer type, number of segments that received a particular tracer type, etc. for the fourteen tracer types injected via wellbore_a 120a as discussed in connection with FIGS. 1E-1, 1E-2, and 1E-3. Different liquid tracer types are injected into fluid segments of the wellbore_a 120a and the wellbore_b 120b, and different solid tracer types are injected into proppant segments of the wellbore_a 120a and the wellbore_b 120b. [0088] As illustrated in FIGS.1E-1, 1E-2, and 1E-3, at least one hydraulic fracturing stage of the wellbore_b is representative of a stage group, and wherein an injection scheme is utilized via the wellbore_b for each hydraulic fracturing stage of the stage group. Furthermore, FIGS.1E-1, 1E-2, 1E-3, and 1E-4 illustrate tracer injection into all 73 stages of the 1 ^st -15 ^th stage groups of wellbore_b 120b. Thus, liquid tracer types and solid tracer types were injected into fluid segments and proppant segments, respectively, of all hydraulic fracturing stages (e.g., 73 stages) via the wellbore_b 120b drilled into the subsurface formation 110 by (i) and (ii). However, in some embodiments, tracer injection may be performed according to steps (i) and (ii) in fewer than all of the hydraulic fracturing stages, such as performed for stages 1-25 of the 1 ^st – 5 ^th stage groups (FIG.1E-1) and repeated for stages 26-50 of the 6 ^th – 10 ^th stage groups (FIG.1E-2) and not repeated for stages 51-73 of the 11 ^th – 15 ^th stage groups (FIG.1E-3). [0089] Wellbore_c: Turning to FIGS.1F-1, 1F-2, 1F-3, and 1F-4, these figures illustrate the tracer injection for the wellbore_c 120c (similar to the wellbore 120 of FIG 1A) in the running example. Wellbore_c 120c includes field equipment 109c, which includes a fracturing fluid tank, proppant tank, pump, and wellhead as well as seven liquid tracer tanks for liquid tracer15-liquid tracer21, seven solid tracer tanks for solid tracerO-solid tracerU, and a tracer pump. The tracer pump for wellbore_c may be different than the tracer pump for one or more of the wellbore_a, wellbore_b, and wellbore_d to inject tracer types into multiple wellbores at about the same time. The tracer pump for wellbore_c may be the same as the tracer pump for one or more of the wellbore_a, wellbore_b, and wellbore_d to inject tracer types into one wellbore at a time. The wellbore_c 120c includes a casing string 125c, a substantially horizontal section 103c of the wellbore_c 120c, a volume 190c within the subsurface formation 110 where the rock matrix 162 of the subsurface formation 110 is connected to the high conductivity fractures 101 located a short distance away, and stage groups/stages illustrated in FIGS.1F-1, 1F-2, 1F-3. Wellbore_c has 15 stage groups, and each stage group has five stages except that the 12 ^th and 14 ^th stage groups have four stages each instead of five stages for wellbore_c. [0090] As illustrated in FIG.1F-1, the tracer injection via wellbore_c includes (i) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a third subset of hydraulic fracturing stages via the third wellbore drilled into the subsurface formation 110 (e.g., 25 stages of the first five stage groups of the 73 stages of wellbore_c) utilizing the plurality of injection schemes (e.g., 5 injection schemes utilized for wellbore_a and wellbore_b), such that substantially similar fluid segments and substantially similar proppant segments of the third subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. Again, the five different injection schemes in the running example that are utilized for all four wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d 120d are referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1. However, the particular liquid tracer types and solids tracer types used across the injection schemes for each wellbore may differ (as illustrated in the figures corresponding to wellbore_b 120b (FIGS.1E-1, 1E-2, 1E-3, 1E-4), wellbore_c 120c (FIGS.1F-1, 1F-2, 1F-3, 1F-4), and wellbore_d 120d (FIGS.1G-1, 1G-2, 1G-3, 1G-4)). The liquid tracer types used via wellbore_c are liquid tracer15-liquid tracer21 and solid tracerO-solid tracerU. [0091] Turning to FIG.1F-2, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_c) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer15 in fluid segment1, liquid tracer16 in fluid segment2, etc. of wellbore_c) and substantially similar solid tracer types into proppant segments (e.g., solid tracerO in proppant segment1, solid tracerP in proppant segment2, etc. of wellbore_c) of additional hydraulic fracturing stages (e.g., 6 ^th stage group that includes stages 26-30, 7 ^th stage group that includes stages 31- 35, etc. of wellbore_c) via the wellbore_c 102c drilled into the subsurface formation 110. [0092] Turning to FIG.1F-3, optionally, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_b) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer15 in fluid segment1, liquid tracer16 in fluid segment2, etc. of wellbore_c) and substantially similar solid tracer types into proppant segments (e.g., solid tracerO in proppant segment1, solid tracerP in proppant segment2, etc. of wellbore_c) of additional hydraulic fracturing stages (e.g., 11 ^th stage group that includes stages 51-55, 12 ^th stage group that includes stages 56-59, etc. of wellbore_c) via the wellbore_c 102c drilled into the subsurface formation 110. [0093] FIG.1F-4 illustrates total mass for a particular tracer type, mass per segment for a particular tracer type, number of segments that received a particular tracer type, etc. for the fourteen tracer types injected via wellbore_c 120c as discussed in connection with FIGS. 1F-1, 1F-2, and 1F-3. Different liquid tracer types are injected into fluid segments of the wellbore_a 120a and the wellbore_b 120b and the wellbore_c 120c, and different solid tracer types are injected into proppant segments of the wellbore_a 120a and the wellbore_b 120b and the wellbore_c 120c. [0094] As illustrated in FIGS.1F-1, 1F-2, and 1F-3, at least one hydraulic fracturing stage of the wellbore_c is representative of a stage group, and wherein an injection scheme is utilized via the wellbore_c for each hydraulic fracturing stage of the stage group. Furthermore, FIGS.1F-1, 1F-2, 1F-3, and 1F-4 illustrate tracer injection into all 73 stages of the 1 ^st -15 ^th stage groups of wellbore_c 120c. Thus, liquid tracer types and solid tracer types were injected into fluid segments and proppant segments, respectively, of all hydraulic fracturing stages (e.g., 73 stages) via the wellbore_c 120c drilled into the subsurface formation 110 by (i) and (ii). However, in some embodiments, tracer injection may be performed according to steps (i) and (ii) in fewer than all of the hydraulic fracturing stages, such as performed for stages 1-25 of the 1 ^st – 5 ^th stage groups (FIG.1F-1) and repeated for stages 26-50 of the 6 ^th – 10 ^th stage groups (FIG.1F-2) and not repeated for stages 51-73 of the 11 ^th – 15 ^th stage groups (FIG.1F-3). [0095] Wellbore_d: Turning to FIGS.1G-1, 1G-2, 1G-3, and 1G-4, these figures illustrate the tracer injection for the wellbore_d 120d (similar to the wellbore 120 of FIG 1A) in the running example. Wellbore_d 120d includes field equipment 109d, which includes a fracturing fluid tank, proppant tank, pump, and wellhead as well as seven liquid tracer tanks for liquid tracer22-liquid tracer28, seven solid tracer tanks for solid tracerV-solid tracerAB, and a tracer pump. The tracer pump for wellbore_d may be different than the tracer pump for one or more of the wellbore_a, wellbore_b, and wellbore_c to inject tracer types into multiple wellbores at about the same time. The tracer pump for wellbore_d may be the same as the tracer pump for one or more of the wellbore_a, wellbore_b, and wellbore_c to inject tracer types into one wellbore at a time. The wellbore_d 120d includes a casing string 125d, a substantially horizontal section 103d of the wellbore_d 120d, a volume 190d within the subsurface formation 110 where the rock matrix 162 of the subsurface formation 110 is connected to the high conductivity fractures 101 located a short distance away, and stage groups/stages illustrated in FIGS.1G-1, 1G-2, 1G-3. Wellbore_d has 15 stage groups, and each stage group has five stages except that the 11 ^th and 14 ^th stage groups have four stages each instead of five stages for wellbore_d. [0096] As illustrated in FIG.1G-1, the tracer injection via wellbore_d includes (i) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a fourth subset of hydraulic fracturing stages via the third wellbore drilled into the subsurface formation 110 (e.g., 25 stages of the first five stage groups of the 73 stages of wellbore_d) utilizing the plurality of injection schemes (e.g., 5 injection schemes utilized for wellbore_a and wellbore_b and wellbore_c), such that substantially similar fluid segments and substantially similar proppant segments of the fourth subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes. Each injection scheme defines a unique combination of liquid tracers and solid tracers. Again, the five different injection schemes in the running example that are utilized for all four wellbore_a 120a, wellbore_b 120b, wellbore_c 120c, and wellbore_d 120d are referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1. However, the particular liquid tracer types and solids tracer types used across the injection schemes for each wellbore may differ (as illustrated in the figures corresponding to wellbore_b 120b (FIGS.1E-1, 1E-2, 1E-3, 1E-4), wellbore_c 120c (FIGS. 1F-1, 1F-2, 1F-3, 1F-4), and wellbore_d 120d (FIGS.1G-1, 1G-2, 1G-3, 1G-4)). The liquid tracer types used via wellbore_d are liquid tracer22-liquid tracer28 and solid tracerV-solid tracerAB. [0097] Turning to FIG.1G-2, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_d) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer22 in fluid segment1, liquid tracer23 in fluid segment2, etc. of wellbore_d) and substantially similar solid tracer types into proppant segments (e.g., solid tracerV in proppant segment1, solid tracerW in proppant segment2, etc. of wellbore_d) of additional hydraulic fracturing stages (e.g., 6 ^th stage group that includes stages 26-30, 7 ^th stage group that includes stages 31- 35, etc. of wellbore_d) via the wellbore_d 102d drilled into the subsurface formation 110. [0098] Turning to FIG.1G-3, optionally, the tracer injection may include (ii) repeating at least a portion of the plurality of injection schemes (e.g., repeating all five injection schemes referred to as Variation2 / Design #5, Variation4 / Design #4, Baseline / Design #3, Variation3 / Design #2, and Variation1 / Design #1) applied to the subset of the hydraulic fracturing stages (e.g., stages 1-25 of the 1 ^st stage group to the 5 ^th stage group of wellbore_d) to inject substantially similar liquid tracer types into fluid segments (e.g., liquid tracer22 in fluid segment1, liquid tracer23 in fluid segment2, etc. of wellbore_d) and substantially similar solid tracer types into proppant segments (e.g., solid tracerV in proppant segment1, solid tracerW in proppant segment2, etc. of wellbore_d) of additional hydraulic fracturing stages (e.g., 11 ^th stage group that includes stages 51-54, 12 ^th stage group that includes stages 55-59, etc. of wellbore_d) via the wellbore_d 102d drilled into the subsurface formation 110. [0099] FIG.1G-4 illustrates total mass for a particular tracer type, mass per segment for a particular tracer type, number of segments that received a particular tracer type, etc. for the fourteen tracer types injected via wellbore_d 120d as discussed in connection with FIGS. 1G-1, 1G-2, and 1G-3. Different liquid tracer types are injected into fluid segments of the wellbore_a 120a and the wellbore_b 120b and the wellbore_c 120c and the wellbore_d 120d, and different solid tracer types are injected into proppant segments of the wellbore_a 120a and the wellbore_b 120b and the wellbore_c 120c and the wellbore_d 120d. [00100] As illustrated in FIGS.1G-1, 1G-2, and 1G-3, at least one hydraulic fracturing stage of the wellbore_d is representative of a stage group, and wherein an injection scheme is utilized via the wellbore_d for each hydraulic fracturing stage of the stage group. Furthermore, FIGS.1G-1, 1G-2, 1G-3, and 1G-4 illustrate tracer injection into all 73 stages of the 1 ^st -15 ^th stage groups of wellbore_d 120d. Thus, liquid tracer types and solid tracer types were injected into fluid segments and proppant segments, respectively, of all hydraulic fracturing stages (e.g., 73 stages) via the wellbore_d 120d drilled into the subsurface formation 110 by (i) and (ii). However, in some embodiments, tracer injection may be performed according to steps (i) and (ii) in fewer than all of the hydraulic fracturing stages, such as performed for stages 1-25 of the 1 ^st – 5 ^th stage groups (FIG.1G-1) and repeated for stages 26-50 of the 6 ^th – 10 ^th stage groups (FIG.1G-2) and not repeated for stages 51-73 of the 11 ^th – 15 ^th stage groups (FIG.1G-3). [00101] Turning to FIGS.1D-4, 1E-4, 1F-4, and 1G-4 in more detail, these figures illustrate total mass values in kg for various tracer types as well as segment mass values in kg for various tracer types for four wellbores. For example, for the wellbore_a, steps (a) and (b) may include injecting a substantially similar amount (e.g., 1.73 kg) of a particular liquid tracer type (e.g., liquid tracer1) in each fluid segment (e.g., each fluid segment1 of 15 fluid segment1) corresponding to the particular liquid tracer type (e.g., liquid tracer1) to receive the particular liquid tracer type (e.g., liquid tracer1) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_a). The substantially similar amount of a particular liquid tracer type may be the same amount. The substantially similar amount of a particular liquid tracer type 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4. [00102] As another example, for the wellbore_a, the amount (e.g., 1.73 kg) of the particular liquid tracer type (e.g., liquid tracer1) to be injected in each fluid segment (e.g., each fluid segment1 of 15 fluid segment1) corresponding to the particular liquid tracer type (e.g., liquid tracer1) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_a) is determined by dividing a total mass (e.g., 25.92 kg) for the particular liquid tracer type (e.g., liquid tracer1) by number of fluid segments corresponding to the particular liquid tracer type (e.g., 15 fluid segment1) to receive the particular liquid tracer type (e.g., liquid tracer1) via the wellbore (e.g., wellbore_a). If the liquid tracer1 was injected into fewer than 15 fluid segment1 in wellbore_a, then that lower count may be utilized instead of 15 in the division. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4. [00103] As another example, for the wellbore_a, steps (a) and (b) may include injecting a substantially similar amount (e.g., 0.08 kg) of a particular solid tracer type (e.g., solid tracerA) in each proppant segment (e.g., each proppant segment1 of 73 proppant segment1) corresponding to the particular solid tracer type (e.g., solid tracerA) to receive the particular solid tracer type (e.g., solid tracerA) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_a). The substantially similar amount of a particular solid tracer type may be the same amount. The substantially similar amount of a particular solid tracer type 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other solid tracer types as illustrated in FIG.1D-4. [00104] As another example, for the wellbore_a, the amount (e.g., 0.08 kg) of the particular solid tracer type (e.g., solid tracerA) to be injected in each proppant segment (e.g., each proppant segment1 of 73 proppant segment1) corresponding to the particular solid tracer type (e.g., solid tracerA) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_a) is determined by dividing a total mass (e.g., 5.85 kg) for the particular solid tracer type (e.g., solid tracerA) by number of proppant segments corresponding to the particular solid tracer type (e.g., 73 proppant segment1) to receive the particular solid tracer type (e.g., solid tracerA) via the wellbore (e.g., wellbore_a). If the solid tracerA was injected into fewer than 73 proppant segment1 in wellbore_a, then that lower count may be utilized instead of 73 in the division. A similar approach may be utilized for the other solid tracer types as illustrated in FIG.1D-4. [00105] A similar approach may be applied to another wellbore, such as wellbore_b. For example, for the wellbore_b, steps (i) and (ii) may include injecting a substantially similar amount (e.g., 1.73 kg) of a particular liquid tracer type (e.g., liquid tracer8) in each fluid segment (e.g., each fluid segment1 of 14 fluid segment1) corresponding to the particular liquid tracer type (e.g., liquid tracer8) to receive the particular liquid tracer type (e.g., liquid tracer8) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_b). The substantially similar amount of a particular liquid tracer type may be the same amount. The substantially similar amount of a particular liquid tracer type 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1E-4. [00106] As another example, for the wellbore_b, the amount (e.g., 1.73 kg) of the particular liquid tracer type (e.g., liquid tracer8) to be injected in each fluid segment (e.g., each fluid segment1 of 14 fluid segment1) corresponding to the particular liquid tracer type (e.g., liquid tracer8) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_b) is determined by dividing a total mass (e.g., 24.19 kg) for the particular liquid tracer type (e.g., liquid tracer8) by number of fluid segments corresponding to the particular liquid tracer type (e.g., 14 fluid segment1) to receive the particular liquid tracer type (e.g., liquid tracer8) via the wellbore (e.g., wellbore_b). If the liquid tracer10 was injected into fewer than 14 fluid segment1 in wellbore_b, then that lower count may be utilized instead of 14 in the division. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1E-4. [00107] As another example, for the wellbore_b, steps (i) and (ii) may include injecting a substantially similar amount (e.g., 0.08 kg) of a particular solid tracer type (e.g., solid tracerH) in each proppant segment (e.g., each proppant segment1 of 73 proppant segment1) corresponding to the particular solid tracer type (e.g., solid tracerH) to receive the particular solid tracer type (e.g., solid tracerH) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_b). The substantially similar amount of a particular solid tracer type may be the same amount. The substantially similar amount of a particular solid tracer type 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other solid tracer types as illustrated in FIG.1D-4. [00108] As another example, for the wellbore_b, the amount (e.g., 1.73 kg) of the particular solid tracer type (e.g., solid tracerH) to be injected in each proppant segment (e.g., each proppant segment1 of 73 proppant segment1) corresponding to the particular solid tracer type (e.g., solid tracerH) across the plurality of injection schemes (e.g., 5 injection schemes) via the wellbore (e.g., wellbore_b) is determined by dividing a total mass (e.g., 5.83 kg) for the particular solid tracer type (e.g., solid tracerH) by number of proppant segments corresponding to the particular solid tracer type (e.g., 73 proppant segment1) to receive the particular solid tracer type (e.g., solid tracerH) via the wellbore (e.g., wellbore_b). If the solid tracerH was injected into fewer than 73 proppant segment1 in wellbore_b, then that lower count may be utilized instead of 73 in the division. A similar approach may be utilized for the other solid tracer types as illustrated in FIG.1E-4. [00109] As another example, substantially similar fluid segments of the wellbore and the second wellbore (e.g., 15 fluid segment1 of wellbore_a and 14 fluid segment1 of wellbore_b) across the plurality of injection schemes (e.g., 5 injection schemes) are injected with a substantially similar amount of different liquid tracer types (1.73 kg). Substantially similar fluid segments may have the same or similar sequence position in the plurality of injection schemes across multiple wellbores, such as 58 fluid segment3 of wellbore_a and 58 fluid segment3 of wellbore_b, 73 fluid segment7 of wellbore_a and 73 fluid segment7 of wellbore_b, etc. The substantially similar amount may be the same amount. The substantially similar amount 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4 and FIG.1E-4. [00110] As another example, the amount of different liquid tracer types (e.g., liquid tracer1 for wellbore_a and liquid tracer8 for wellbore_b) to be injected in substantially similar fluid segments of the wellbore and the second wellbore (e.g., 15 fluid segment1 of wellbore_a and 14 fluid segment1 of wellbore_b) across the plurality of injection schemes (e.g., 5 injection schemes) is based on a substantially similar total mass (e.g., 25.92 kg for wellbore_a and 24.19 kg for wellbore_b). The substantially similar total mass may be the same amount. The substantially similar total mass 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4 and FIG.1E-4. [00111] As another example, substantially similar proppant segments of the wellbore and the second wellbore (e.g., 73 proppant segment1 of wellbore_a and 73 proppant segment1 of wellbore_b) across the plurality of injection schemes (e.g., 5 injection schemes) are injected with a substantially similar amount of different solid tracer types (0.8 kg). Substantially similar proppant segments may have the same or similar sequence position in the plurality of injection schemes across multiple wellbores, such as 73 proppant segment3 of wellbore_a and 73 proppant segment3 of wellbore_b, 29 proppamt segment7 of wellbore_a and 29 proppant segment7 of wellbore_b, etc. The substantially similar amount may be the same amount. The substantially similar amount 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4 and FIG.1E-4. [00112] As another example, the amount of different solid tracer types (e.g., solid tracerA for wellbore_a and solid tracerH for wellbore_b) to be injected in substantially similar fluid segments of the wellbore and the second wellbore (e.g., 73 proppant segment1 of wellbore_a and 73 proppant segment1 of wellbore_b) across the plurality of injection schemes (e.g., 5 injection schemes) is based on a substantially similar total mass (e.g., 5.85 kg for wellbore_a and 5.83 kg for wellbore_b). The substantially similar total mass may be the same amount. The substantially similar total mass 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% can 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 0.9% to 1.1% (i.e., range of 0.9%-1.1%) includes 0.9% and also includes 1.1%, and includes percentages in between 0.9% and 1.1%, unless explicitly stated otherwise herein. A similar approach may be utilized for the other liquid tracer types as illustrated in FIG.1D-4 and FIG.1E-4. [00113] FIG.2 illustrates one embodiment of a method 200 of tracer injection during hydraulic fracturing of a subsurface formation using a plurality of hydraulic fracturing stages. At 205, the method 200 includes (a) injecting liquid tracer types into fluid segments and solid tracer types into proppant segments of a subset of the hydraulic fracturing stages via a wellbore drilled into the subsurface formation utilizing a plurality of injection schemes, such that substantially similar fluid segments and substantially similar proppant segments of the subset of the hydraulic fracturing stages are injected with substantially similar liquid tracer types and substantially similar solid tracer types, respectively, across the plurality of injection schemes, and wherein each injection scheme defines a unique combination of liquid tracers and solid tracers. More information is provided in FIG.1D-1 of the running example discussed hereinabove. [00114] At 210, the method 200 includes (b) repeating at least a portion of the plurality of injection schemes applied to the subset of the hydraulic fracturing stages to inject substantially similar liquid tracer types into fluid segments and substantially similar solid tracer types into proppant segments of additional hydraulic fracturing stages via the wellbore drilled into the subsurface formation. More information is provided in FIG.1D-2 and FIG. 1D-3 of the running example discussed hereinabove. At 215, the method 200 includes (c) placing the wellbore on production. At 220, the method 200 includes (d) obtaining a plurality of samples as a function of time from the wellbore after the wellbore is placed on production. The plurality of samples may be obtained from a wellhead of the wellbore. The samples may be analyzed, for instance, in a laboratory setting. Tracer analysis is discussed in a separate section herein. [00115] Various alternatives may be made to embodiments and examples in the tracer injection section. For instance, a method of tracer injection may include injecting first tracer types into first segments and second tracer types into second segments via a wellbore drilled into the subsurface formation, such that substantially similar first segments and substantially similar second segments are injected with substantially similar first tracer types and substantially similar second tracer types, respectively. For instance, the first tracer types into the first segments are liquid tracer types into fluid segments and the second tracer types into second segments are gas tracer types into gas segments. For instance, the first tracer types into the first segments are liquid tracer types into fluid segments and the second tracer types into second segments are other liquid tracer types into other fluid segments (e.g., a liquid tracer for each acid segment and may have multiple acid slugs). Other alternatives are also possible. Other alternatives may be possible, for example, with a vertical wellbore as in FIG. 3. [00116] TRACER ANALYSIS: The methods and systems of the present disclosure may be implemented by a system and/or in a system, such as a system 400 shown in FIG.4. The system 410 may include one or more of a processor 411, an interface 412 (e.g., bus, wireless interface), an electronic storage 413, a graphical display 414, and/or other components. The processor 411 executes a method of tracer analysis, including input such as concentration profile data for a plurality of tracer types. In some embodiments, the output may include (i) an estimate of swept volume for each tracer type, (ii) an estimate of fracture area/volume growth rate for each tracer type, or any combination thereof. [00117] The electronic storage 413 may be configured to include electronic storage medium that electronically stores information. The electronic storage 413 may store software algorithms, information determined by the processor 411, information received remotely, and/or other information that enables the system 410 to function properly. For example, the electronic storage 413 may store information relating to concentration profile data for a plurality of tracer types, data regarding a sample from flowback/produced fluid, and/or other information. The electronic storage media of the electronic storage 413 may be provided integrally (i.e., substantially non-removable) with one or more components of the system 410 and/or as removable storage that is connectable to one or more components of the system 10 via, for example, a port (e.g., a USB port, a Firewire port, etc.) or a drive (e.g., a disk drive, etc.). The electronic storage 413 may include one or more of optically readable storage media (e.g., optical disks, etc.), magnetically readable storage media (e.g., magnetic tape, magnetic hard drive, floppy drive, etc.), electrical charge-based storage media (e.g., EPROM, EEPROM, RAM, etc.), solid-state storage media (e.g., flash drive, etc.), and/or other electronically readable storage media. The electronic storage 413 may include one or more non-transitory computer readable storage medium storing one or more programs. The electronic storage 413 may be a separate component within the system 410, or the electronic storage 413 may be provided integrally with one or more other components of the system 410 (e.g., the processor 411). Although the electronic storage 413 is shown in FIG.4 as a single entity, this is for illustrative purposes only. In some implementations, the electronic storage 413 may comprise a plurality of storage units. These storage units may be physically located within the same device, or the electronic storage 413 may represent storage functionality of a plurality of devices operating in coordination. [00118] The graphical display 414 may refer to an electronic device that provides visual presentation of information. The graphical display 414 may include a color display and/or a non-color display. The graphical display 414 may be configured to visually present information. The graphical display 414 may present information using/within one or more graphical user interfaces. For example, the graphical display 414 may present information relating to (i) concentration profile data, (ii) an estimate of swept volume for each tracer type, (ii) an estimate of fracture area/volume growth rate for each tracer type, or any combination thereof, and/or (iv) other information. [00119] The processor 411 may be configured to provide information processing capabilities in the system 410. As such, the processor 411 may comprise one or more of a digital processor, an analog processor, a digital circuit designed to process information, a central processing unit, a graphics processing unit, a microcontroller, an analog circuit designed to process information, a state machine, and/or other mechanisms for electronically processing information. The processor 411 may be configured to execute one or more machine-readable instructions 400 to facilitate tracer analysis. The machine-readable instructions 400 may include one or more computer program components. The machine- readable instructions 400 may include a concentration profile data component 404, a swept volume estimate component 406, a growth rate estimate component 408, and/or other computer program components. [00120] It should be appreciated that although computer program components are illustrated in Figure 4 as being co-located within a single processing unit, one or more of computer program components may be located remotely from the other computer program components. While computer program components are described as performing or being configured to perform operations, computer program components may comprise instructions which may program processor 411 and/or system 410 to perform the operation. [00121] While computer program components are described herein as being implemented via processor 411 through machine-readable instructions 400, this is merely for ease of reference and is not meant to be limiting. In some implementations, one or more functions of computer program components described herein may be implemented via hardware (e.g., dedicated chip, field-programmable gate array) rather than software. One or more functions of computer program components described herein may be software- implemented, hardware-implemented, or software and hardware-implemented. [00122] Referring again to machine-readable instructions 400, the concentration profile data component 404 may be configured to obtain concentration profile data for a plurality of tracer types. The concentration profile data comprises a concentration profile as a function of time for each tracer type in a plurality of samples produced from a subsurface formation. Each tracer type was injected into the subsurface formation via a corresponding segment. The swept volume estimate component 406 may be configured to estimate swept volume for each tracer type using the corresponding concentration profile as a function of time. The growth rate estimate component 408 may be configured to estimate fracture area/volume growth rate for each tracer type. [00123] The description of the functionality provided by the different computer program components described herein is for illustrative purposes, and is not intended to be limiting, as any of computer program components may provide more or less functionality than is described. For example, one or more of computer program components may be eliminated, and some or all of its functionality may be provided by other computer program components. As another example, processor 411 may be configured to execute one or more additional computer program components that may perform some or all of the functionality attributed to one or more of computer program components described herein. [00124] FIG.5 illustrates an example process 500 for tracer analysis. For ease of understanding, the running example discussed in connection with the tracer injection section herein will also be utilized in the tracer analysis section herein. [00125] At step 505, the process 500 includes obtaining concentration profile data for a plurality of tracer types. The step 505 may be performed by the concentration profile data component 404. The term “obtaining” may include receiving, retrieving, accessing, generating, etc. or any other manner of obtaining data. The concentration profile data may be obtained from the electronic storage 413. The concentration profile data comprises a concentration profile as a function of time for each tracer type in a plurality of samples produced from a subsurface formation. Each tracer type was injected into the subsurface formation via a corresponding segment. A tracer type may be a liquid tracer type or a solid tracer type. The concentration profile of a tracer type may include concentration, time, and corresponding segment. In some embodiments, concentration profiles of various tracer types may be combined according to wellbore, such as in FIGS.6B-6E and FIGS.7B-7E. A corresponding segment may be a fluid segment or a proppant segment, such as, but not limited to, the embodiments and the running example related to tracer injection during hydraulic fracturing of a subsurface formation using a plurality of hydraulic fracturing stages discussed in the tracer injection section herein. A corresponding segment may be a gas segment. A particular tracer type is a liquid tracer type, a solid tracer type, or a gas tracer type. [00126] For instance, various tracer types may be injected into a subsurface formation via a wellbore during an injection process involving segment injection in which a tracer type is injected per segment. After injection, the wellbore may be placed on production. About 10 to 30 samples may be physically obtained from fluid exiting the wellhead of the wellbore. These samples may be analyzed, such as in a lab, to detect the injected tracer types and analyze the detected tracer types to generate the concentration profile data. The generated concentration profiled data may be received from the lab and stored in the electronic storage 413. The quantity of samples needed may depend on the ability to determine an expected response curve and ability to detect the injected tracer types in those samples. Practically any techniques known in the art may be utilized to generate concentration profile data. [00127] Regarding the running example, FIG.6A illustrates a diagram of an expected response. FIG.6B illustrates a concentration profile as a function of time for wellbore_a 120a for the seven fluid segments corresponding to seven liquid tracer types. FIG.6C illustrates a concentration profile as a function of time for wellbore_b 120b for the seven fluid segments corresponding to seven liquid tracer types. FIG.6D illustrates a concentration profile as a function of time for wellbore_c 120c for the seven fluid segments corresponding to seven liquid tracer types. FIG.6E illustrates a concentration profile as a function of time for wellbore_d 120d for the seven fluid segments corresponding to seven liquid tracer types. [00128] Regarding the running example, FIG.7A illustrates a diagram of an expected response. FIG.7B illustrates a concentration profile as a function of time for wellbore_a 120a for the seven proppant segments corresponding to seven solid tracer types. FIG.7C illustrates a concentration profile as a function of time for wellbore_b 120b for the seven proppant segments corresponding to seven solid tracer types. FIG.7D illustrates a concentration profile as a function of time for wellbore_c 120c for the seven proppant segments corresponding to seven solid tracer types. FIG.7E illustrates a concentration profile as a function of time for wellbore_d 120d for the seven proppant segments corresponding to seven solid tracer types. [00129] At step 510, the process 500 includes estimating swept volume for each tracer type using the corresponding concentration profile as a function of time. The step 510 may be performed by the swept volume estimate component 406. Swept volume for each tracer type may be estimated (for a wellbore or even an offset wellbore) using one or more equations in FIG.8 and Jain, Lokendra, Doorwar, Shashvat, and Daniel Emery. "Analytical Tracer Interpretation Model for Fracture Flow Characterization and Swept Volume Estimation in Unconventional Wells." URTEC-2021-5357-MS. Paper presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, Houston, Texas, USA, July 2021, which is incorporated by reference herein. For example, the hypothesis and model section of the paper and table 4 on pages 8-11 may be utilized to calculate volumes discussed herein. [00130] Turning to FIG.8, estimating swept volume for each tracer type may include utilizing Equation (1) below corresponding to the grey portion. Equation (1) may be applied for every two segments together (e.g., every two fluid segments) and corresponds to the grey portion in FIG.8. Equation (1) had been injected in segments N and N+1, C _N-Produced is produced concentration of tracer injected in segment N, CN+1_Produced is produced concentration of tracer injected in segment N+1, C _N-Injected is injected concentration of tracer in segment N, and C _N+1-Injected is injected concentration of tracer in segment N+1. [00131] Estimating swept volume for each tracer type may include handling the common volume that both segment N and segment N+1 are sweeping to avoid double counting the yellow triangular common volume with the green portion and the red portion. The yellow triangular portions illustrated in FIG.8 show the common volume (referred to as volume series herein) that both segment N and segment N+1 are sweeping. The yellow triangular portions of FIG.8 may be handled with the following Equation (2). The Equation (2) may similarly be utilized to handle the common volume that both proppant segment N and proppant segment N+1 are sweeping. Equation (2) wherein V _series is common volume, V _{slug_N} is swept volume derived using tracer injected in segment N, Vslug,N+1 is swept volume derived using tracer from segment N+1, VDerived_Global is swept volume derived using concentration obtained from the C _{Global_Normalized} equation which is the pseudo global tracer concentration in segments N and N+1. Vslug_N and Vslug,N+1 may be determined using the Jain reference. [00132] Estimating swept volume for each tracer type may include handling segment N and segment N+1 together. For instance, fluid segment1 and fluid segment2 are handled together, then fluid segment2 and fluid segment3 are handled together, then fluid segment3 and fluid segment4 are handled together, then fluid segment4 and fluid segment5 are handled together, then fluid segment5 and fluid segment6 are handled together, and then fluid segment6 and fluid segment7 are handled together. Handling two segments together allows volumes for each segment to be isolated separately. For example, the green portion of FIG.8 may refer to fluid segment N and the red portion of FIG.8 may refer to fluid segment N+1. As illustrated in FIG.8, these green and red portions (without the common triangular yellow volumes) are uncommon volumes referred to as parallel volume herein. The green portion and the red portion of FIG.8 may be handled with the following Equations (3)-(5). The Equations (3)-(5) may similarly be utilized to handle proppant segment N and proppant segment N+1. Equation (3) (4) (5) wherein uncommon swept volume for segment N, Vparallel,N+1 is uncommon swept volume for segment N+1, Vseries is common volume, V _{slug_N} is swept volume derived using tracer injected in segment N, Vslug,N+1 is swept volume derived using tracer from segment N+1, VDerived_Global is swept volume derived using concentration obtained from the C _{Global_Normalized} equation which is the pseudo global tracer concentration in segments N and N+1. [00133] Regarding the running example, FIG.9A illustrates a diagram of swept volume for wellbore_a 120a for the seven fluid segments corresponding to seven liquid tracer types. FIG.9C illustrates a diagram of swept volume for wellbore_b 120b for the seven fluid segments corresponding to seven liquid tracer types. FIG.9E illustrates a diagram of swept volume for wellbore_c 120c for the seven fluid segments corresponding to seven liquid tracer types. FIG.9G illustrates a diagram of swept volume for wellbore_d 120d for the seven fluid segments corresponding to seven liquid tracer types. [00134] Regarding the running example, FIG.10A illustrates a diagram of swept volume for wellbore_a 120a for the seven proppant segments corresponding to seven solid tracer types. FIG.10C illustrates a diagram of swept volume for wellbore_b 120b for the seven proppant segments corresponding to seven solid tracer types. FIG.10E illustrates a diagram of swept volume for wellbore_c 120c for the seven proppant segments corresponding to seven solid tracer types. FIG.10G illustrates a diagram of swept volume for wellbore_d 120d for the seven proppant segments corresponding to seven solid tracer types. [00135] At step 515, the process 500 includes estimating fracture area/volume growth rate for each tracer type. The step 515 may be performed by the fracture area/volume growth rate estimate component 406. For instance, step 515 may estimate the V_parallel or V_uncommon for each segment tracer injected (both liquid water and proppant oil tracer) which is then plotted in cum fashion to show the increase in swept volume from one segment to another showing how the fracture volume grows. [00136] Regarding the running example, FIG.9B illustrates a diagram of fracture area/volume growth rate for wellbore_a 120a for the seven fluid segments corresponding to seven liquid tracer types. FIG.9D illustrates a diagram of fracture area/volume growth rate for wellbore_b 120b for the seven fluid segments corresponding to seven liquid tracer types. FIG.9F illustrates a diagram of fracture area/volume growth rate for wellbore_c 120c for the seven fluid segments corresponding to seven liquid tracer types. FIG.9H illustrates a diagram of fracture area/volume growth rate for wellbore_d 120d for the seven fluid segments corresponding to seven liquid tracer types. [00137] Regarding the running example, FIG.10B illustrates a diagram of fracture area/volume growth rate for wellbore_a 120a for the seven proppant segments corresponding to seven solid tracer types. FIG.10D illustrates a diagram of fracture area/volume growth rate for wellbore_b 120b for the seven proppant segments corresponding to seven solid tracer types. FIG.10F illustrates a diagram of fracture area/volume growth rate for wellbore_c 120c for the seven proppant segments corresponding to seven solid tracer types. FIG.10H illustrates a diagram of fracture area/volume growth rate for wellbore_d 120d for the seven proppant segments corresponding to seven solid tracer types. [00138] The tracer analysis of the wellbore_a-wellbore_d shows quantification that was typically not available with traditional techniques. Furthermore, the tracer analysis led to a better understanding of fracture growth and drainage mapping. For instance, liquid water tracer recovery from each segment shows expected behavior. Tracer recovery increases from early segment to later segments. For instance, proppant tracer recovery from each segment also shows expected behavior. Tracer recovery decreases from early to later segments. For instance, tracer swept hydraulic volume shows expected behavior as well. For instance, tracer swept propped drainage volume higher for early segments, but later segments also show significant drained volumes. [00139] Various alternatives may be made to embodiments and examples in the tracer analysis section. For example, the principles of the present disclosure regarding tracer analysis may be applied in various scenarios in which a tracer type was injected via a segment (i.e., segment injection scheme), such as, but not limited to, acidizing process (e.g., fluid segments only), a hydraulic fracturing process (e.g., proppant segments and fluid segments like the running example or different than the running example), a refracturing process (e.g., proppant segments only, proppant segments and fluid segments), and/or a fluid injection process (e.g., fluid segments only) performed on the subsurface formation. Tracer analysis may even be performed for one or more offset wellbores. The tracer analysis may also be performed at a coarse or coarser level consistent with this disclosure. [00140] For instance, the matrix/fracture acidizing is carried out to increase/restore reservoir permeability. In this process a slug of acid is injected to stimulate the reservoir rock below or above the fracture pressure. To assess the conformance and efficacy of the acidizing, the acid slug could be divided into liquid segments and those segments would be tagged with unique liquid tracer types. The tracer flowback data from when the wellbore is put back on production and sampled is analyzed using the same method to determine the common/series and uncommon/parallel volumes to evaluate the efficacy of the entire acid treatment. [00141] For instance, the foam injection / huff and puff (inject and produce in the same well) undergo injection of liquid and gas slugs in an alternating or continuous manner. In either type of injection, the injection may be divided into multiple fluid and gas segments. Each of these segments are tagged with unique liquid and gas tracers to determine how effectively each segment is contacting the reservoir and help determine the conformance effect due to foam injection / huff and puff. [00142] Furthermore, different tracer types may be injected into different segments via vertical wellbores (FIG.3 with wellbore 220 and the other labels 209, 210, 208, and 225 are similar to wellbore 120) or wellbores with other configurations, other subsurface formations, etc. for tracer analysis as discussed herein. A “subsurface volume of interest” 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. The subsurface volume of interest may be divided into one or more zones. The subsurface volume of interest may include resources such as hydrocarbons, a rock matrix, and geological features. The hydrocarbons may be liquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons (e.g., natural gas), solid hydrocarbons (e.g., asphaltenes or waxes), a combination of hydrocarbons (e.g., a combination of liquid hydrocarbons, gas hydrocarbons, and solid hydrocarbons), etc. The hydrocarbons may be discovered by hydrocarbon exploration processes. [00143] 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, conventional, 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 "subsurface volume of interest " is not limited to any description or configuration described herein. [00144] A “well” refers to a single hole, usually cylindrical, that is drilled into a subsurface volume of interest. A well may be drilled in one or more directions. For example, a well may include a vertical well, a horizontal well, a deviated well, and/or other type of well. A well may be drilled in the subsurface volume of interest for exploration and/or recovery of resources. For example, a well may be drilled in the subsurface volume of interest to aid in extraction and/or production of resources such as hydrocarbons. As another example, a well may be drilled in the subsurface volume of interest for fluid injection. A plurality of wells (e.g., tens to hundreds of wells) are often used in a field depending on the desired outcome. [00145] A well 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 (SWD) 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 subsurface volume of interest, the hydrocarbons, and/or other factors. [00146] 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. [00147] A well may be utilized to recover hydrocarbons (sometimes referred to as produced) from a subsurface volume of interest using natural reservoir energy, water injection (also referred to as waterflooding), gas injection, enhanced oil recovery (EOR), fracturing, etc. Enhanced oil recovery refers to techniques for increasing the amount of hydrocarbons that may be extracted from the subsurface volume of interest, such as, but not limited to, chemical injection (sometimes referred to as chemical enhanced oil recovery (CEOR). Other hydrocarbon recovery processes may also be utilized to recover the hydrocarbons. A well may be utilized for other purposes. [00148] While particular embodiments are described above, it will be understood it is not intended to limit the invention to these particular embodiments. On the contrary, the invention includes alternatives, modifications and equivalents that are within the spirit and scope of the appended claims. Numerous specific details are set forth in order to provide a thorough understanding of the subject matter presented herein. But it will be apparent to one of ordinary skill in the art that the subject matter may be practiced without these specific details. In other instances, well-known methods, procedures, components, and circuits have not been described in detail so as not to unnecessarily obscure aspects of the embodiments. [00149] The terminology used in the description of the invention herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used in the description of the invention and the appended claims, the singular forms "a," "an," and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term "and/or" as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms "includes," "including," "comprises," and/or "comprising," when used in this specification, specify the presence of stated features, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, operations, elements, components, and/or groups thereof. [00150] As used herein, the term "if" may be construed to mean "when" or "upon" or "in response to determining" or "in accordance with a determination" or "in response to detecting," that a stated condition precedent is true, depending on the context. Similarly, the phrase "if it is determined [that a stated condition precedent is true]" or "if [a stated condition precedent is true]" or "when [a stated condition precedent is true]" may be construed to mean "upon determining" or "in response to determining" or "in accordance with a determination" or "upon detecting" or "in response to detecting" that the stated condition precedent is true, depending on the context. [00151] Although some of the various drawings illustrate a number of items in a particular order, items that are not order dependent may be reordered and other items may be combined or broken out. While some reordering or other groupings are specifically mentioned, others will be obvious to those of ordinary skill in the art and so do not present an exhaustive list of alternatives. Moreover, it should be recognized that the items could be implemented in hardware, firmware, software or any combination thereof. [00152] The use of the term "about" applies to all numeric values, whether or not explicitly indicated. This term generally refers 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 can 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% can 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. [00153] 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). [00154] Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. All citations referred herein are expressly incorporated by reference. [00155] Although some of the various drawings illustrate a number of logical stages in a particular order, stages that are not order dependent may be reordered and other stages may be combined or broken out. While some reordering or other groupings are specifically mentioned, others will be obvious to those of ordinary skill in the art and so do not present an exhaustive list of alternatives. Moreover, it should be recognized that the stages could be implemented in hardware, firmware, software, or any combination thereof. [00156] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. The embodiments were chosen and described in order to best explain the principles of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.