Patent Publication Number: US-2022235657-A1

Title: Downhole Hydrogen Sulfide Capture and Measurement

Description:
BACKGROUND 
     Wells may be drilled at various depths to access and produce oil, gas, minerals, and other naturally-occurring deposits from subterranean geological formations. The drilling of a well is typically accomplished with a drill bit that is rotated within the well to advance the well by removing topsoil, sand, clay, limestone, calcites, dolomites, or other materials. The drill bit is typically attached to a drill string that may be rotated to drive the drill bit and within which drilling fluid, referred to as “drilling mud” or “mud”, may be delivered downhole. The drilling mud is used to cool and lubricate the drill bit and downhole equipment and is also used to transport any rock fragments or other cuttings to the surface of the well. 
     It is often desired to collect a representative sample of formation or reservoir fluids (e.g., hydrocarbons) to further evaluate drilling operations and production potential, or to detect the presence of certain gases or other materials in the formation that may affect well performance. For example, hydrogen sulfide (H2S), a poisonous, corrosive, and flammable gas can occur in formation fluids, and its presence in the wellbore in significant concentrations may result in damage to wellbore components or dangerous conditions for well operators at the surface. However, H2S concentration in formation fluids is often underestimated with current measurement techniques, for example, due to losses via absorption/adsorption on tool surfaces and/or during sample transfers. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments. 
         FIG. 1A  illustrates a schematic view of a well in which an example embodiment of a fluid sample system is deployed. 
         FIG. 1B  illustrates a schematic view of another well in which an example embodiment of a fluid sample system is deployed. 
         FIG. 2  illustrates a schematic view of an example embodiment of a fluid sampling tool. 
         FIG. 3  illustrates an enlarged schematic view of an example embodiment the fluid sampling tool of  FIG. 2   
         FIG. 4  illustrates a cross-sectional view an example embodiment of a sample chamber coated with a material that is reversibly sorbent. 
         FIG. 5A  illustrates an enlarged cross-sectional view of a sample chamber showing an example embodiment of a porous coating. 
         FIG. 5B  illustrates an enlarged cross-sectional view of a sample chamber showing an example embodiment of a structured coating, 
         FIG. 6  illustrates an example diagram of an example test system for target component measurement. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure relates to subterranean operations and, more particularly, embodiments disclosed herein provide methods and systems for capture and measurement of a target component. 
     Embodiments may include sampling of formation fluids from a wellbore to determine a concentration of a target component in the formation fluid. Target component may include any of a variety of gases, vapors, or liquids, where quantification in formations fluids may be desired, including, but not limited to, H2S, mercury, and carbon dioxide, among others. By way of example, H2S is a volatile chemical that oxidizes easily, is corrosive to downhole tools, and is poisonous and explosive. The presence of H2S in a formation may increase the cost of extracting and processing formation fluids from a well and also present a safety hazard to well operators, Accurate measurement of H2S (or other target components) in the formation fluids can better enable well operators to make decisions about completing a well so that formation fluids can be economically extracted while maintaining safe conditions for well operators. In addition, it may desirable to know concentration of mercury and carbon dioxide as well, as these components can also be corrosive. 
     The fluid sampling tools described herein may vary in design, but embodiments of the fluid sampling tools typically may include an inlet, an outlet, and a sampling chamber. Embodiments may further include two or more sampling chambers. The inlet and outlet may be fluidly connected to the fluid within the wellbore that is being extracted from a subterranean formation. In operation, a fluid sample may be gathered into the sampling chamber from the wellbore for analysis. Embodiments may include coating inner surfaces of the sampling chamber with a material that can reversibly sorb the target component. In this manner, the target component in the fluid sample should be sorbed by the coating, instead of being lost via sorbtion on tool surfaces. At a desired time, for example, after recovery of the sample tool to the well surface, the target component can be desorbed and measured. Given a known volume of formation fluid sampled and amount of target component, the concentration of the target component in the sample can be determined. Multiple component measurements from multiple sample chambers (e.g., two or more) may be obtained, for example, to extrapolate to reservoir conditions. The component measurements may be obtained at different times in the wellbore. 
     The fluid sampling tools, systems and methods described herein may be used with any of the various techniques employed for evaluating a well, including without limitation wireline formation testing (WFT), measurement while drilling (MWD), and logging while drilling (LWD). The various tools and sampling units described herein may be delivered downhole as part of a wireline-delivered downhole assembly or as a part of a drill string. It should, also be apparent that given the benefit of this disclosure, the apparatuses and methods described herein have applications in downhole operations other than drilling, and may also be used after a well is completed. 
       FIG. 1A  illustrates a fluid sampling and analysis system  100  according to an illustrative embodiment used in a well  102  having a wellbore  104  that extends from a surface  108  of the well  102  to or through a subterranean formation  112 . While the wellbore  104  is shown extending generally vertically into the subterranean formation  112 , the principles described herein are also applicable to wellbores that extend at an angle through the subterranean formations  112 , such as horizontal and slanted wellbores. For example, although  FIG. 1A  shows wellbore  104  that is vertical or low inclination, high inclination angle or horizontal placement of the wellbore  104  and equipment is also possible. In addition, it should be noted that while  FIG. 1A  generally depicts a land-based operation, those skilled in the art should readily recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. 
     The well  102  is illustrated with the fluid sampling and analysis system  100  being deployed in a drilling assembly  114 . In the embodiment illustrated in  FIG. 1A , the well  102  is formed by a drilling process in which a drill bit  116  is turned by a drill string  120  that extends from the drill bit  116  to the surface  108  of the well  102 . The drill string  120  may be made up of one or more connected tubes or pipes, of varying or similar cross-section. The drill string  120  may refer to the collection of pipes or tubes as a single component, or alternatively to the individual pipes or tubes that include the string. The term “drill string” is not meant to be limiting in nature and may refer to any component or components that are capable of transferring rotational energy from the surface of the well to the drill bit. In several embodiments, the drill string  120  may include a central passage disposed longitudinally in the drill string  120  and capable of allowing fluid communication between the surface  108  of the well  102  and downhole locations. 
     At or near the surface  108  of the well  102 , the drill string  120  may include or be coupled to a kelly  128 . The kelly  128  may have a square, hexagonal, octagonal, or other suitable cross-section. The kelly  128  may be connected at one end to the remainder of the drill string  120  and at an opposite end to a rotary swivel  132 . As illustrated, the kelly  120  may pass through a rotary table  136  that is capable of rotating the kelly  128  and thus the remainder of the drill string  120  and drill bit  116 . The rotary swivel  132  should allow the kelly  128  to rotate without rotational motion being imparted to the rotary swivel  132 . A hook  138 , cable  142 , traveling block (not shown), and hoist (not shown) may be provided to lift or lower the drill bit  116 , drill string  120 , kelly  128  and rotary swivel  132 . The kelly  128  and swivel  132  may be raised or lowered as needed to add additional sections of tubing to the drill string  120  as the drill bit  116  advances, or to remove sections of tubing from the drill string  120  if removal of the drill string  120  and drill bit  116  from the well  102  is desired. 
     A reservoir  144  may be positioned at the surface  108  and holds drilling fluid  148  for delivery to the well  102  during drilling operations. A supply line  152  may fluidly couple the reservoir  144  and the inner passage of the drill string  120 . A pump  156  may drive the drilling fluid  148  through the supply line  152  and downhole to lubricate the drill bit  116  during drilling and to carry cuttings from the drilling process back to the surface  108 . After traveling downhole, the drilling fluid  148  returns to the surface  108  by way of an annulus  160  formed between the drill string  120  and the wellbore  104 . At the surface  108 , the drilling mud  148  may returned to the reservoir  144  through a return line  164 . The drilling mud  148  may be filtered or otherwise processed prior to recirculation through the well  102 . 
     FIB.  1 B illustrates a schematic view of another embodiment of well  102  in which an example embodiment of fluid analysis system  100  may be deployed. As illustrated, fluid analysis system  100  may be deployed as part of a wireline assembly  115 , either onshore of offshore. As illustrated, the wireline assembly  115  may include a winch  117 , for example, to raise and lower a downhole portion of the wireline assembly  115  into the well  102 , As illustrated, fluid analysis system  100  may include fluid sampling tool  170  attached to the winch  117 . In examples, it should be noted that fluid sampling tool  170  may not be attached to a winch unit  104 . Fluid sampling tool  170  may be supported by rig  172  at surface  108 . 
     Fluid sampling tool  170  may be tethered to the winch  117  through wireline  174 . While  FIG. 1B  illustrates wireline  174 , it should be understood that other suitable conveyances may also be used for providing mechanical conveyance to fluid sampling tool in the well  102 , including, but not limited to, slickline, coiled tubing, pipe, drill pipe, drill string, downhole tractor, or the like. In some examples, the conveyance may provide mechanical suspension, as well as electrical connectivity, for fluid sampling tool  170 . Wireline  174  may include, in some instances, a plurality of electrical conductors extending from winch  117 . By way of example, wireline  174  may include an inner core of seven electrical conductors (not shown) covered by an insulating wrap. An inner and outer steel armor sheath may be wrapped in a helix in opposite directions around the conductors. The electrical conductors may be used for communicating power and telemetry downhole to fluid sampling tool  170 . 
     With reference to both  FIGS. 1A and 1B , operation of fluid sampling tool  170  for sample collection will now be described in accordance with example embodiments. Fluid sampling tool  170  may be raised and lowered into well  102  on drill string  120  ( FIG. 1A ) and wireline  174 . ( FIG. 1B ). Fluid sampling tool  170  may be positioned downhole to obtain fluid samples from the subterranean formation  112  for analysis. The formation fluid and, thus the fluid sample may be contaminated with, or otherwise contain, the target component. In some embodiments, the target component may be contained in the fluid sample in small quantities, for example, less than 500 parts per million (“ppm”). For example, the target component mar be present in the fluid sample in an amount from about 1 ppm to about 500 ppm, about 100 ppm to about 200 ppm, about 1 ppm to about 100 ppm, or about 5 to about 10 ppm. The fluid sampling tool  170  may be operable to measure, process, and communicate data regarding the subterranean formation  112 , fluid from the subterranean formation  112 , or other operations occurring downhole. After recovery, the fluid sample may be analyzed, for example, to quantify the concentration of the target component. This information, including information gathered from analysis of the fluid sample, allows well operators to determine, among other things, the concentration the target component within the fluid being extracted from the subterranean formation  112  to make intelligent decisions about ongoing operation of the well  102 . In some embodiments, the data measured and collected by the fluid sampling tool  170  may include, without limitation, pressure, temperature, flow, acceleration (seismic and acoustic), and strain data. As described in more detail below, the fluid sampling tool  170  may include a communications subsystem, including a transceiver for communicating using mud pulse telemetry or another suitable method of wired or wireless communication with a surface controller  184 . The transceiver may transmit data gathered by the fluid sampling tool  170  or receive instructions from a well operator via the surface controller  184  to operate the fluid sampling tool  170 . 
     Referring now to  FIG. 2 , an example embodiment of a fluid sampling tool  170  is illustrated as a tool for gathering fluid samples from a formation for subsequent analysis and testing. It should be understood that the fluid sampling tool.  170  shown on  FIG. 2  is merely illustrative and the example embodiments disclosed herein may be used with other tool configurations. In an embodiment, the fluid sampling tool  170  includes a transceiver  202  through which the fluid sampling tool  170  may communicate with other actuators and sensors in a conveyance drill string  120  on  FIG. 1A  or wireline  174  on FIG. TB), the conveyance&#39;s communications system, and with a surface controller (surface controller  184  on  FIG. 1A ). In an embodiment, the transceiver  202  is also the port through which various actuators (e.g. valves) and sensors (e.g., temperature and pressure sensors) in the fluid sampling tool  170  are controlled and monitored by, for example, a computer in another part of the conveyance or by the surface controller  184 . In an embodiment; the transceiver  202  includes a computer that exercises the control and monitoring function. 
     The fluid sampling tool  170  may include a dual probe section  204 , which extracts fluid from the formation (e.g., formation  112  on  FIGS. 1A and 1B ), as described in more detail below, and delivers it to a channel  206  that extends from one end of the fluid sampling tool  170  to the other. The channel  206  can be connected to other tools or portions of the fluid sampling tool  170  arranged in series. The fluid sampling tool  170  may also include a gauge section  208 , which includes sensors to allow measurement of properties, such as temperature and pressure, of the fluid in the channel  206 . The fluid sampling tool  170  may also include a flow-control pump-out section  210 , which includes a pump  212  for pumping fluid through the channel  206 . The fluid sampling tool  170  also includes one or more chambers, such as multi-chamber sections  214 , which are described in more detail below. 
     In some embodiments, the dual probe section  204  includes two probes  218 ,  220  which extend from the fluid sampling tool  170  and press against the borehole wall to receive fluid for sampling. Probe channels  222 ,  224  connect the probes  218 ,  220  to the channel  206 . The pump  212  can be used to pump fluids from the reservoir, through the probe channels  222 ,  224  and to the channel  206 . Alternatively, a low volume pump  226  can be used for this purpose. Two standoffs or stabilizers  228 ,  230  hold the fluid sampling tool  170  in place as the probes  218 ,  220  press against the borehole wall to receive fluid. In an embodiment, die probes  218 ,  220  and stabilizers  228 ,  230  are retracted when the tool is in motion and are extended to gather samples of fluid from the formation. 
     With additional reference to  FIG. 3 , the multi-chamber sections  214  include multiple sample chambers  230 , While  FIGS. 2 and 3  show the multi-chamber sections  214  having three sample chambers  230 , it will be understood that the multi-chamber sections  214  can have any number of sample chambers  230  and may in fact be single chamber sections. In some embodiments, the sample chambers  230  may be coupled to the channel  206  through respective chamber valves  320 ,  325 ,  330 . Formation fluid can be directed from the channel  206  to a selected one of the sample chambers  230  by opening the appropriate one of the chamber valves  320 ,  325 ,  330 . The valves  320 ,  325 ,  330  may be configured such that when one of the chamber valves  320 ,  325 ,  330  is open the others are closed. 
     In some embodiments, the multi-chamber sections  214  may include a path  335  from the channel  206  to the annulus  160  through a valve  340 . Valve  340  may be open during the draw-down period when the fluid sampling tool  170  is clearing mud cake, drilling mud, and other contaminants into the annulus before clean formation fluid is directed to one of the sample chambers  230 . A check valve  345  may prevent fluids from the annulus  160  from flowing hack into the channel  206  through the path  335 . As such, the mufti-chamber sections  214  may include a path  350  from the sample chambers  230  to the annulus  160 . 
       FIG. 4  illustrates a cross-sectional view an example embodiment of a sample chamber  230  lined with a coating  400  of a material that can reversibly sorb a target component. As illustrated, the coating  400  may be disposed on inner surfaces  402  of chamber walls  404 . Sample chamber  230  may be any suitable chamber for use in a fluid sampling tool (e.g., fluid sampling tool  170  on  FIGS. 1A, 11B, and 2 ). In some embodiments, sample chamber  230  may have a fixed volume. For example, the sample chamber  230  may have a fixed volume of from about 0.1 milliliters to about 1 liter. Alternatively, the sample chamber  230  may have a fixed volume of from about 1 milliliters to about 1 liter. In some embodiments, the sample chamber  230  may be configured for obtaining micro-samples, i.e., volumes of less than 1 milliliter. For example, the sample chamber  230  may have a fixed volume of from about 10 milliliters to about 1 milliliters. One of ordinary skill in the art, with the benefit of this disclosure, should be able to select an appropriate sample chamber  230  and size thereof for a particular application. 
     As illustrated, the coating  400  may line the sample chamber  230 . The coating  400  may include any of a variety of suitable materials capable of reversibly sorbing a target component, such as H2S, mercury, or carbon dioxide, whether by absorption or adsorption. Non-limiting examples of suitable materials may include, but are not limited to, gold, silver, nickel, platinum, and combinations thereof. In some embodiments, gold may be suitable for reversible absorption of target component, such as H2S and mercury. In some embodiments, nickel and/or platinum may be suitable for reversible absorption of H2S and/or mercury. One of ordinary skill in the art, with the benefit of this disclosure, should be able to select an appropriate material for the coating  400  based on a number of factors, including the particular target component of interest. 
     The coating  400  on the chamber walls  404  may have any suitable thickness. For example, the coating  400  may have a thickness of about 10 nm to about 100 microns. In some embodiments, the coating  400  may have a thickness of about 0.1 micron to about 1 micron or about 10 microns to about 100 microns. One of ordinary skill in the art, with the benefit of this disclosure, should be able to select an appropriate thickness for the coating  400  based on a number of factors, including the particular target component of interest and surface area. 
     The coating  400  may be applied to the chambers walls  404  using any suitable technique. Suitable techniques may include any of a variety of different techniques for depositing a coating onto a substrate, including, but not limited to thin-film deposition techniques, such as atomic layer deposition, physical vapor deposition, and chemical vapor deposition. One or ordinary skill in the art, with the benefit of this disclosure, should be able to select an appropriate technique for application of the coating  400 . 
     It should be understood that the surface area of the coating  400  available for the target component may provide an upper limit on the amount of the target component that can be quantified. In other words, the fluid sample may, in some embodiments, contain more of the target component than can be sorbed by the coating  400 . Accordingly, the surface of the coating  400  may be selected so that a sufficient quantity of target component can be measured to provide desirable information. 
     In some embodiments, the surface-to-volume ratio of the coating  400  and or the chamber walls  404  may be maximized, for example, to provide additional surface area for sorption of the target component. In this manner, the coating  400  and/or the chamber walls  404  may be configured to effective sorption of different concentrations of the target component. In some embodiments, the surface-to-volume ratio of the coating  400  may be maximized. In some embodiments, the surface-to-volume ratio of the chamber walls  404  may be maximized. In some embodiments, the surface-to-volume ratio of the coating  400  and the chamber walls  404  may be maximized. Any of a variety of techniques may be applied to the coating  400  and/or chamber walls  404  for maximization of the surface-to-volume ratio. Suitable examples of the coating  400  and/or chamber walls  404  with increased surface-to-volume ratio may include creation of a porous or structure coating that maximizes surface-to-volume ratio. Examples of suitable techniques for maximization of the surface-to-volume ratio may include, but are not limited to, lithograph techniques, such as etching, anodizing, or patterning. Specific examples of suitable lithograph techniques may include, but are not limited to, electro-chemical anodization, semiconductor lithography, and electron-beam lithography. In addition to lithographic techniques applied to the chamber walls  404  and/or the coating  400  after deposition, techniques may also be used to maximize the surface-to-volume ratio during of the coating  400  application, including nanotube deposition and nanoparticle deposition. In addition to the above mentioned techniques, the coating material may be deposited in such a way as to create a highly porous material coating. 
       FIG. 5A  illustrates an enlarged cross-sectional view of a sample chamber  230  showing an example embodiment of a porous coating  500 . The porous coating  500  may provide, for example, an increased surface-to-volume ratio as compared to non-porous coatings. As illustrated, the porous coating  500  may be deposed on the inner surfaces  402  of the chamber walls  404 . While the porous coating  500  is shown with a random distribution of pores  502 , it should be understood that the structure and arrangement of the pores  502  should depend on the particular application technique. For example, a porous coating  500  be provided with the pores  502  in a regular distribution (not shown). 
       FIG. 5B  illustrates an enlarged cross-sectional view of a sample chamber  230  showing an example embodiment of a structured coating  504 . The structured coating  504  may provide, for example, an increased surface-to-volume ratio as compared to non-patterned coating. As illustrated, the structured coating  504  may be deposed on the inner surfaces  402  of the chamber walls  404 . 
     In some embodiments, a protective coating (not shown) may be applied to sample chamber  230  and/or to other components of the fluid sampling tool  170 . For example, the protective coating may be applied on the chamber walls  404  underneath the coating  400  such that the coating  400  may be backed by the protective coating. In addition, the protective coating may be applied to other components of the fluid sampling tool  170 , such as o-rings, seals, inlet lines (e.g., channel  206  on  FIG. 2 ), inlet valves (e.g., chamber valves  320 ,  325 ,  330  on  FIG. 3 ). The protective coating may include any suitable material that is resistant to target component, for example, does not readily adsorb, absorb, or otherwise react to the target component. Suitable materials may include, but are not limited to, aluminum oxide and beryllium oxide, which are both resistant to H2S. One or ordinary skill in the art, with the benefit of this disclosure, should recognize that the specific material for the protective coating should depend on a number of factors, including the particular target component. 
       FIG. 6  illustrates an example of a test system  600  for target component measurement. As illustrated, the test system  600  may include a chamber housing  602 , a fluid analyzer  604 , a vacuum pump  606 , and a processor  608 . Chamber housing  602  may include a chamber receptacle  610  for receiving the sample chamber  230 . Sample chamber  230  may contain, for example, a fluid sample of a formation fluid. In some embodiments, the fluid sample may be evacuated from the sample chamber  230  prior to use of test system  600 . As previously described, the fluid sample may contain a target component. It may be desired to quantity the concentration of the target component in the fluid sample. In some embodiments, test system  600  may be used for measurement and quantification of the target component in the fluid sample. 
     In some embodiments, the chamber housing  602  may receive the sample chamber  230  in the chamber receptacle  610 . As previously described, the target component may have been sorbed by the coating (e.g., coating  400  on  FIG. 4 ) lining the sample chamber  230 . The chamber housing  602  may be operable to desorb the target component from the coating. By way of example, the chamber housing  602  may include a heating element  612 . In some embodiments, the heating element  612  may confirm electrical energy into heat. The heat from the heating element  612  may heat the chamber housing  602  such that the target component may be desorbed from the chamber housing  602 . While the heating element  612  is shown, it should be understood that the present techniques are intended to encompass other techniques for desorption of the target component from the chamber housing  602 . For example, the target component may be chemically stripped from the chamber housing  602 . 
     Test system  600  may further include a fluid analyzer  604  for analyzing the target component after desorption from the chamber housing  602 . In the illustrated embodiment, a channel  614  provides fluid communication between the fluid analyzer  604  and the sample chamber  230 . Chamber housing  602  may be opened (or otherwise) accessed so that the desorbed target component in the chamber housing  602  can be provided into the fluid analyzer  604  for analysis. As illustrated, a vacuum pump  606  may be used, for example, to create a suction that drives the fluid sample with the desorbed target component from the chamber housing  602  to the fluid analyzer  604 . Fluid analyzer  604  may use any of a variety of suitable analysis techniques for analyzing the fluid sample to quantify concentration of the target component. Suitable analysis techniques may include, but are not limited to, gas chromatography, mass spectrometry, and optical sensors. 
     Test system  600  may further include processor  608 . The processor  608  may include any suitable device for processing instructions, including, but not limited to, a microprocessor, microcontroller, embedded microcontroller, programmable digital signal processor, or other programmable device. The processor  608  may also, or instead, be embodied in an application specific integrated circuit, a programmable gate array, programmable array logic, or any other device or combinations of devices operable to process electric signals. The processor  608  may be communicatively coupled to the fluid analyzer  604 . The connection between the fluid analyzer  604  and the processor  608  may be a wired connection or a wireless connection, as desired for a particular application. 
     In some embodiments, the processor  200  can be configured to receive inputs from the fluid analyzer  604 , for example, to determine a concentration of the target component in the fluid sample. The fluid analyzer  604 , for example, may measure a total quantity (e.g., volume, moles, etc.) of the target component. Since of a total volume of the fluid sample in the sample chamber is known, the concentration of the target component in the fluid sample can then be readily determined with the total quantify of the target component. 
     In some embodiments, target component measurements may be extrapolated to reservoir conditions. Extrapolation may be performed, for example, using measurements of the target component from more than one sample chamber  230 . The fluid sample may be acquired in each of the more than one sample chamber  230  downhole at during the same pump out or at different times. Any suitable technique may be used for extrapolating the target component measurement to reservoir conditions, including, but not limited to, equations of state and geodynamic modeling, among others. 
     Accordingly, this disclosure describes methods and systems for capture and measurement of a target component. Without limitation, the systems and methods may further be characterized by one or more of the following statements: 
     Statement 1. A fluid sampling tool for sampling fluid from a subterranean formation may be provided. The fluid sampling tool may include a sample chamber having a fluid inlet, wherein the sample chamber is lined with a coating of a material that can reversibly hold a target component. 
     Statement 2. The fluid sampling tool of statement 1, wherein the fluid sampling tool further includes a probe that is extendable to engage the subterranean formation from a wellbore, a pump coupled to the probe for pumping fluid from the subterranean formation, wherein the sample chamber is coupled to the pump for receiving a fluid sample pumped from the subterranean formation through the probe. 
     Statement 3. The fluid sampling tool of statement 1 or 2, further including more than one of the sample chamber. 
     Statement 4. The fluid sampling tool of any preceding statement, wherein the sample chamber includes a sample fluid including the target component. 
     Statement 5, The fluid sampling tool of any preceding statement, wherein the target component includes at least one component selected from the group consisting of hydrogen sulfide, mercury, carbon dioxide, and combinations thereof, and wherein the material includes at least one material selected from the group consisting of gold, aluminum oxide, nickel, platinum, and combinations thereof. 
     Statement 6. The fluid sampling tool of any preceding statement, wherein the coating and/or one or more walls of the sample chamber were treated to increase a surface-to-volume ratio of the coating. 
     Statement 7. The fluid sampling tool of statement 6, wherein coating and/or the one or more walls were treated with a treatment including at least one lithographic technique selected from the group consisting of etching, anodizing, patterning, and combinations thereof. 
     Statement 8. The fluid sampling tool of any preceding statement, wherein at least one surface of the fluid sampling tool is coated with a protective coating that is resistant to the target component. 
     Statement 9. The fluid sampling tool of any preceding statement, wherein the coating is a porous or structured coating. 
     Statement 10. The fluid sampling tool of any preceding statement, wherein the coating includes gold, wherein the target component includes hydrogen sulfide, and wherein at least one surface of the fluid sampling tool is coated with a protective coating of aluminum oxide that is resistant to the target component. 
     Statement 11. The fluid sampling tool of any preceding statement, wherein the material is backed with an inert material to the target component. 
     Statement 12. The fluid sampling tool of statement 11, wherein the inert material includes aluminum oxide, beryllium oxide, or a combination thereof. 
     Statement 13. A method for sampling formation fluids may be provided. The method may include inserting a sample chamber into a wellbore, wherein the sample chamber is lined with a material that can reversibly hold a target component. The method may further include collecting a fluid sample in the sample chamber while disposed in the wellbore such that the target component in the fluid sample is at least partially sorbed by the material. 
     Statement 14. The method of statement 13, wherein at least 99% by volume of the target component in the fluid sample is sorbed by the material. 
     Statement 15. The method of statement 13 or 14, further including retrieving the sample chamber from the wellbore, desorbing the target component from the material, and measuring a quantity of the desorbed target component. 
     Statement 16. The method of statement 15, wherein the desorbing includes heating the sample chamber. 
     Statement 17. The method statement 15 may further include collecting one or more additional fluid samples in one or more additional sample chambers while disposed in the wellbore, wherein the one or more additional sample chambers are lined with the material such that at least a portion of the target component present in the one or more additional fluid samples is at least partially sorbed by the material in the one or more additional sample chambers. The method may further include retrieving the one or more additional sample chambers from the wellbore. The method may further include desorbing the target component from the material in the one or more additional samples chambers. The method may further include measuring a quantity of the desorbed component from the one or more additional sample chambers. The method may further include extrapolating the quantity of the desorbed component from the one or more additional sample chambers and the desorbed component from the sample chamber to a reservoir concentration. 
     Statement 18, The method of any one of statements 13 to 17, wherein the target component includes hydrogen sulfide and the material includes gold, and wherein at least one surface of a fluid sampling tool including the sample chamber is partially coated with a protective coating that is resistant to the target component. 
     Statement 19. A test system for component measurement may be provided. The test system may include a chamber housing including a chamber receptacle for receiving a sample chamber. The test system may further include a heating element disposed in the chamber housing arranged to heat the sample chamber. The test system may further include a fluid analyzer for measuring a desorbed component from the sample chamber. The test system may further include a vacuum pump in fluid communication with the chamber housing for creating a suction to transfer the desorbed component from the sample chamber to the fluid analyzer. The test system may further include a processor operable to receive inputs from the fluid analyzer to determine a concentration of the desorbed component. 
     Statement 20. The system of statement 19, wherein the fluid analyzer is selected from a mass spectrometer, a gas chromatograph, an optical sensor, and combinations thereof. 
     The preceding description provides various embodiments of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual embodiments may be discussed herein, the present disclosure covers all combinations of the disclosed embodiments, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “including,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. 
     For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. 
     Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, the disclosure covers all combinations of all of the embodiments. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those embodiments. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.