System And Method For Detecting Hydrogen Sulfide In A Formation Sampling Tool

BACKGROUND

The present disclosure relates generally to drilling systems and more particularly to tools for sampling and analyzing formation fluid.

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

Wells are generally drilled into a surface (land-based) location or ocean bed to recover natural deposits of oil and gas, as well as other natural resources that are trapped in geological formations in the Earth's crust. A well is often drilled using a drill bit attached to the lower end of a “drill string,” which includes drillpipe, a bottom hole assembly, and other components that facilitate turning the drill bit to create a borehole. Drilling fluid, or “mud,” is pumped down through the drill string to the drill bit during a drilling operation. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in an annulus between the drill string and the borehole wall.

Information about the subsurface formations, such as measurements of the formation pressure, formation permeability and the recovery of formation fluid samples may be useful for predicting the economic value, the production capacity, and production lifetime of a subsurface formation. Formation fluid samples may be extracted from the well and evaluated in a laboratory to establish physical and chemical properties of the formation fluid. Such evaluation may include analyses of fluid viscosity, density, composition, gas/oil ratio (GOR), differential vaporization, PVT analysis, multi-stage separation tests, and so forth. Recovery of formation fluid samples, in order to perform such evaluations, may be accomplished using different types of downhole tools, which may be referred to as formation testers. Formation testing tools may use pumps to withdraw fluid from a formation for analysis within the tool or storing the fluid in a sample chamber for later analysis. Pumping the formation fluid through the formation testing tool and sampling the formation fluid in this way may introduce hydrogen sulfide (H2S) from the formation into the formation testing tool. It is now recognized that, under certain conditions, it is desirable for an operator to know whether there is H2S trapped in the formation testing tool, so that procedures can be followed when removing parts of the formation testing tool at the surface of the well.

SUMMARY

In a first embodiment, a drilling system includes a downhole sampling tool that may be placed in a wellbore of a subterranean formation and used to pump formation fluid from the subterranean formation into the downhole sampling tool. The downhole sampling tool includes internal components that route the formation fluid through the downhole sampling tool and drill collars designed to hold the internal components of the downhole sampling tool. The downhole sampling tool also includes a coupon made from a material that is optically reactive to hydrogen sulfide (H2S). The coupon is mounted in a location that is exposed to the formation fluid being pumped into the downhole sampling tool, and the location of the coupon is accessible from outside the downhole sampling tool without removing the internal components from the drill collars.

In another embodiment, a drilling system includes a downhole sampling tool that may be placed in a wellbore of a subterranean formation and used to pump formation fluid from the subterranean formation into the downhole sampling tool. The downhole sampling tool includes a coupon made from a material that is optically reactive to hydrogen sulfide (H2S), and the coupon is positioned in a location of the downhole sampling tool that is exposed to the formation fluid being pumped into the downhole sampling tool. The coupon, when in the location of the downhole sampling tool, is accessible from outside of the downhole sampling tool when the downhole sampling tool is fully assembled.

In a further embodiment, a method includes lowering a downhole sampling tool into a well formed in a subterranean formation at a rig site. The method also includes pumping formation fluid from the subterranean formation into a flowline of the downhole sampling tool. In addition, the method includes exposing a coupon made from a material that is optically reactive to hydrogen sulfide (H2S) to the formation fluid being pumped into the flowline of the downhole sampling tool. Further, the method includes raising the downhole sampling tool out of the well and accessing the coupon at the rig site.

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

BRIEF DESCRIPTION OF THE DRAWINGS

Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:

FIG. 1 is a partial cross sectional view of a drilling system used to drill a well through subsurface formations, in accordance with an embodiment of the present techniques;

FIG. 2 is a schematic diagram of downhole equipment used to sample a subsurface formation and to passively detect hydrogen sulfide (H2S), in accordance with an embodiment of the present techniques;

FIG. 3 is a schematic diagram of downhole equipment used to sample a subsurface formation and to passively detect H2S, in accordance with an embodiment of the present techniques;

FIG. 4 is a cross sectional view of a hydraulic extender used in the downhole equipment of FIG. 2, in accordance with an embodiment of the present techniques.

FIG. 5 is an exploded perspective view of a probe of the drilling equipment of FIG. 2 with H2S sensing coupons configured to be mounted in the probe, in accordance with an embodiment of the present techniques;

FIG. 6 is an exploded perspective view of a holder used to mount the H2S sensing coupons into the probe of FIG. 5, in accordance with an embodiment of the present techniques;

FIG. 7 is a partial cross sectional view of the probe of FIG. 5 having the H2S sensing coupons mounted into a filter piston of the probe, in accordance with an embodiment of the present techniques;

FIG. 8 is a top view of a mounting insert holding H2S sensing coupons, in accordance with an embodiment of the present techniques;

FIG. 9 is a top view of a mounting insert holding H2S sensing coupons, in accordance with an embodiment of the present techniques;

FIG. 10 is a schematic diagram of an H2S sensing coupon being held in a mounting insert, in accordance with an embodiment of the present techniques;

FIG. 11 is a side view of a mounting insert holding H2S sensing coupons, in accordance with an embodiment of the present techniques; and

FIG. 12 is a process flow diagram of a method for detecting the presence of H2S within a downhole sampling tool, in accordance with an embodiment of the present techniques.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will be described below. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

Present embodiments are directed to systems and methods for passively detecting hydrogen sulfide (H2S) present in formation fluid being pumped through a downhole sampling tool. H2S sensing coupons may be mounted into specific sections of the downhole sampling tool that can be accessed by drilling operators at a rig site. The term rig site refers to the location of the drilling rig that is being used to lower or raise the downhole sampling tool. The H2S coupons mounted in these locations may allow operators to determine whether or not H2S gas is present in the downhole sampling tool before disassembling the tool, so that they may follow desired procedures in preparation for the disassembly. In some embodiments, one or more H2S sensing coupons may be mounted into a probe of the downhole sampling tool, this probe being used to direct formation fluid into the downhole sampling tool from the formation. These probe mounted H2S sensing coupons may be visible or removable from the downhole sampling tool without the downhole sampling tool being disassembled. In other embodiments, the H2S sensing coupons may be mounted along a flowline of a battery cap of the downhole sampling tool, a rig-accessible location at an end of a hydraulic extender of the downhole sampling tool, an inlet of a sample bottle of the downhole sampling tool, or a flowline exit location of the downhole sampling tool.

FIG. 1 illustrates a drilling system 10 used to drill a well through subsurface formations 12. A drilling rig 14 at the surface 16 is used to rotate a drill string 18 that includes a drill bit 20 at its lower end. As the drill bit 20 is rotated, a “mud” pump 22 is used to pump drilling fluid, commonly referred to as “mud” or “drilling mud,” downward through the center of the drill string 18 in the direction of the arrow 24 to the drill bit 20. The mud, which is used to cool and lubricate the drill bit 20, exits the drill string 18 through ports (not shown) in the drill bit 20. The mud then carries drill cuttings away from the bottom of a wellbore 26 as it flows back to the surface 16, as shown by the arrows 28 through an annulus 30 between the drill string 18 and the formation 12. At the surface 16, the return mud is filtered and conveyed back to a mud pit 32 for reuse.

While a drill string 18 is illustrated in FIG. 1, it will be understood that the embodiments described herein are applicable to work strings and wireline tools as well. Work strings may include a length of tubing (e.g. coil tubing) lowered into the well for conveying well treatments or well servicing equipment. Wireline tools may include formation testing tools suspended from a multi-wire cable as the cable is lowered into a well so that it can measure formation properties at desired depths. It should be noted that the location and environment of the well may vary widely depending on the formation 12 into which it is drilled. Instead of being a surface operation, for example, the well may be formed under water of varying depths, such as on an ocean bottom surface. Certain components of the drilling system 10 may be specially adapted for underwater wells in such instances.

As illustrated in FIG. 1, the lower end of the drill string 18 includes a bottom-hole assembly (“BHA”) 34 that includes the drill bit 20, as well as a plurality of drill collars 36, 38. The drill collars 36, 38 may include various instruments, such as sample-while-drilling (“SWD”) tools that include sensors, telemetry equipment, and so forth. For example, the drill collars 36, 38 may include logging-while-drilling (“LWD”) modules 40 and/or measurement-while drilling (“MWD”) modules 42. The LWD modules or tools 40 may include tools configured to measure formation parameters or properties, such as resistivity, porosity, permeability, sonic velocity, and so forth. The MWD modules or tools 42 may include tools configured to measure wellbore trajectory, borehole temperature, borehole pressure, and so forth. The LWD modules 40 of FIG. 1 are each housed in one of the drill collars 36, 38, and each contain any number of logging tools and/or fluid sampling devices. The LWD modules 40 include capabilities for measuring, processing and/or storing information, as well as for communicating with the MWD modules 42 and/or directly with the surface equipment such as, for example, a logging and control computer 44.

Present embodiments are directed toward systems and methods for detecting a presence of H2S that may be introduced into downhole sampling tools, such as the LWD modules 40. H2S may be present within the well formation and may enter the LWD modules 40 during sampling or pumping of the formation fluid therethrough. This H2S may become trapped within or between the LWD modules 40 (or other features of the BHA 34) as the formation fluid is pumped, and the H2S may remain trapped as the BHA 34 is brought to the surface. In some embodiments, the LWD modules 40 may be partially disassembled at the rig site. For example, sample bottles containing formation fluid samples collected downhole may be removed from the rest of the LWD module 40, and separate portions of the LWD module 40 may be disconnected to allow for relatively easy transportation of the LWD module 40. During this disassembly of the LWD modules 40 taking place at the surface of the rig site, it may be desirable to vent gases trapped within the LWD module 40. In order to enhance the efficiency of rig operations and minimize environmental impact of this venting process, certain procedures may be used when venting gases that include H2S, as compared to gases that do not include H2S. Thus, it is desirable to know whether the formation fluid pumped through the LWD modules 40 includes H2S, so that these procedures may be followed. In addition, it may be desirable to passively determine whether the formation fluid pumped through the LWD modules 40 includes H2S, in order to provide redundancy for active H2S sensing components, testing of formation fluid collected in sample bottles, and the like.

FIG. 2 is a schematic diagram of an embodiment of downhole equipment (equipment configured for operation downhole) used to sample a well formation. Specifically, the illustrated downhole equipment includes an embodiment of a downhole fluid formation sampling tool 50, hereinafter referred to as a downhole sampling tool 50. The downhole sampling tool 50 is illustrated as being disposed within the wellbore 26 of the subsurface formation 12 in order to sample formation fluid from the formation 12. In some embodiments, the downhole sampling tool 50 is disposed in the wellbore 26 via a wireline. That is, the downhole sampling tool 50 may be suspended in the wellbore 26 from a lower end of the wireline, which may be a multi-conductor cable spooled from a winch. The wireline may be electrically coupled to surface equipment, in order to communicate various control signals and logging information between the downhole sampling tool 50 and the surface equipment. It should be noted that in other embodiments, such as shown in FIG. 1, the downhole sampling tool 50 may include one or more of the SWD tools (e.g., LWD modules 40), which are disposed in the wellbore 26 via the drill string 18. In still other embodiments, the downhole sampling tool 50 may include drill stem testing tools, which are testing tools that form the BHA 34 (without a drill bit 20) of a string of tubular lowered from the drilling rig 14 into the borehole 26.

The illustrated downhole sampling tool 50 includes a probe module 52, a hydraulics module 54, a pump-out module 56, and two multi-sample modules 58. It should be noted that other arrangements of the modules that make up the downhole sampling tool 50 may be possible. For example, in some embodiments, there may be a single multi-sample module 58, or certain components of the pump-out module 56 and the hydraulics module 54 may be combined. Moreover, the different components shown within each of the illustrated modules may be arranged differently in other embodiments of the downhole sampling tool 50.

The illustrated probe module 52 includes an extendable fluid communication line (probe 60) designed to engage the formation 12 and to communicate formation fluid from the formation 12 into the downhole sampling tool 50. In the illustrated embodiment, the probe 60 includes a rubber “donut” configured to extend from the probe module 52 and to engage the wall of the borehole 26. In the illustrated embodiment, this donut defines a fluid inlet 62 into the probe 60, and the formation fluid is pumped into the downhole sampling tool 50 through this fluid inlet 62. Thus, the probe 60 functions as an inlet for the formation fluid pumped into the downhole sampling tool 50.

In addition to the probe 60, the probe module 52 may include two or more setting mechanisms (not shown). Setting mechanisms are configured to extend outward from the probe module 52 and to engage the wellbore 26 in an opposite direction from the extendable probe 60. The setting mechanisms may include pistons in some embodiments, although other types of probe modules 58 may utilize a different type of probe 60 and/or setting mechanism.

In some embodiments, the probe module 52 may include or be disposed within a centralizer or stabilizer 64. In certain embodiments, the centralizer/stabilizer 64 features blades that are in contact with a wall of the borehole 26 to limit “wobble” of the drill bit 20. “Wobble” is the tendency of the drill string 18, as it rotates, to deviate from the vertical axis of the borehole 26 and cause the drill bit 20 to change direction. The centralizer/stabilizer 64 is already in contact with the borehole wall 46, thus requiring less extension of the probe 60 to establish fluid communication with the formation 12. It should be understood that the probe 60 may be disposed in locations other than in the centralizer/stabilizer 64 without departing from the scope of the presently disclosed embodiments.

The hydraulics module 54 may include, among other things, electronics, batteries, sensors, and/or hydraulic components used to operate the probe 60 and any corresponding setting mechanisms within the probe module 52. In the illustrated embodiment, the hydraulics module 54 includes a battery cap 66 at one end for holding batteries 68 of the hydraulics module 54.

The pump-out module 56 may include a pump 70 used to create a pressure differential that draws the formation fluid in through the probe 60 and pushes the fluid through a flowline 72 of the downhole sampling tool 50. The pump 70 may include an electromechanical pump used for pumping formation fluid from the probe module 52 to the multi-sample modules 58 and/or out of the downhole sampling tool 50. In an embodiment, the pump 70 operates as a piston displacement unit (DU) driven by a ball screw coupled to a gearbox and an electric motor, although other types of pumps 70 may be possible as well. Power may be supplied to the pump 70 via other components located in the pump-out module 56, via components located in the hydraulics module 54, or via a separate power generation module (not shown). During a sampling process, the pump 70 moves the formation fluid through the flowline 72, toward the one or more multi-sample modules 58.

The multi-sample modules 58 each include one or more sample bottles 74 for collecting samples of the formation fluid being pumped into the downhole sampling tool 50. Based on characteristics of the formation fluid detected via sensors (e.g., spectrometer, pressure sensors, temperature sensors, etc.) along the flowline 72, the downhole sampling tool 50 may be operated in a sample collection mode or a continuous pumping mode. When operated in the sample collection mode, valves disposed at or near entrances of the sample bottles 74 may be positioned to allow the formation fluid to flow into the sample bottles 74. The sample bottles 74 may be filled one at a time, and once a sample bottle 74 is filled, its corresponding valve may be moved to another position to seal the sample bottle 74. When the valves are closed, the downhole sampling tool 50 may operate in a continuous pumping mode.

In a continuous pumping mode, the pump 70 moves the formation fluid into the downhole sampling tool 50 through the probe 60, through the flowline 72, and out of the downhole sampling tool 50 through a flowline exit port 76. The flowline exit port 76 may be a check valve that releases the formation fluid into the annulus 30 of the wellbore 26, or it may be a valve which performs a similar function but is operated by commands sent from equipment at the surface. The downhole sampling tool 50 may operate in the continuous pumping mode until the formation fluid flowing through the flowline 72 is determined to be clean enough for sampling. This is because when the formation fluid is first sampled, residual drilling mud filtrate may enter the downhole sampling tool 50 along with the sampled formation fluid. After pumping the formation fluid for an amount of time, the formation fluid flowing through the downhole sampling tool 50 may provide a more pure sample of the uncontaminated formation fluid than would otherwise be available when first drawing fluid in through the probe 60.

As noted above, present embodiments may include a downhole sampling tool 50 that includes components for passively detecting H2S present within the formation fluid. This passive detection may be possible through the use of coupons made from H2S sensitive material. The term “H2S sensitive material” may refer to a material that is optically reactive to H2S, so that the material changes color in the presence of certain levels of H2S. The term “optically reactive” refers to the material being configured to react chemically with H2S, thereby causing a visible or otherwise distinguishable change in the material. Some examples of appropriate materials for sensing H2S in the downhole sampling tool 50 may include CDA® 706 copper-nickel alloy (relatively high sensitivity to H2S), HASTELLOY® B-3® nickel-molybdenum alloy (relatively medium sensitivity to H2S), and INCONEL® 600 nickel-chlorium alloy (relatively low sensitivity to H2S). It should be noted that the different materials listed above have different levels of sensitivity to H2S. For example, the most sensitive material (CDA® 706) may be up to approximately 10 times more sensitive to H2S than the least sensitive material (INCONEL® 600). The change in color may be more noticeable or relatively easy to distinguish on the more sensitive materials. An operator at the rig site may access the coupons after pumping formation fluid into the downhole sampling tool 50 (in continuous pumping mode or in sampling mode) and, based on visual inspection of the coupons, determine whether H2S is present in the formation fluid. The downhole sampling tool 50 may be equipped with one or more of a single type of coupon in some embodiments. In other embodiments, the downhole sampling tool 50 may include multiple different types of coupons to detect H2S across a range of sensitivities.

The detected presence and/or levels of H2S in the formation fluid, as determined passively by the coupons located in the downhole sampling tool 50, may provide a variety of technical effects. Passive H2S detection may provide redundancy for any active H2S detection methods used in the downhole sampling tool 50. The passive H2S detection may also enable an operator to determine just by visual inspection that H2S is present in the downhole sampling tool 50 and/or the formation fluid samples, so that an operator who is unaware of actively measured sensor data may be able to make the determination. In addition, passive H2S detection may be used to verify samples of formation fluid that are brought to the surface in the sample bottles 74 and later tested in a laboratory. More specifically, the levels of H2S detected at the rig site via the passive H2S detection coupons may be compared to the H2S levels of the formation fluid samples determined at the laboratory. This comparison may help to confirm accurate operation of the downhole sampling tool 50 and to check the quality of the sample (e.g., comparing H2S levels when the sample was taken into the sample bottle 74 versus when the sample in the sample bottle 74 was tested at the surface). In some instances, drilling operators may change a drilling profile of the well based on the levels of H2S passively detected by the coupons in the downhole sampling tool 50.

The coupons may be located in one or more locations throughout the downhole sampling tool 50. Examples of possible locations for these coupons are provided in the illustrated embodiment, and indicated by reference numeral 78. Each of these locations 78 may be exposed to the formation fluid that is pumped into the downhole sampling tool 50. In addition, each of these locations 78 may be accessible to a rig operator at the rig site. That is, the locations 78 may be accessible from outside the downhole sampling tool 50 while the downhole sample tool 50 is fully assembled, or without removing internal components of the downhole sample tool 50 from one or more drill collars that are holding the internal components. These locations 78 may include, among others, locations within the fluid inlet 62 of the probe 60 (e.g., 78A), the battery cap 66 of the hydraulics module 54 (e.g., 78B), a hydraulic extender used to couple drill collar of two separate modules (e.g., 78C), inlets to the sample bottles 74 (e.g., 78D), and the flowline exit 76 (e.g., 78E).

In some embodiments, the downhole sampling tool 50 includes internal components (e.g., pump 70, battery 68, hydraulics, electronics, sensors, and portions of the flowline 72) housed within one or more drill collars. The internal components are configured to route the formation fluid through the downhole sampling tool 50, among other things. In some embodiments, the internal components may be arranged in the form of one or more mandrels, and these mandrels may be inserted into the drill collars at a location distant from the rig site (e.g., in a shop). In the illustrated embodiment, the multi-sample modules 58 may include internal components that are housed in a first drill collar 80, the pump-out module 56 may include internal components that are housed in a second drill collar 82, and the hydraulics module 54 and the probe module 52 may include internal components that are housed in a third drill collar 84. The drill collars 80, 82, and 84 may be coupled to one another and disassembled at the rig site, although the internal components of the different modules remain inside their respective drill collars 80, 82, and 84. While the coupons disposed in some of the locations 78 (e.g., 78A, 78D, and 78E) may be accessible from the outside of the downhole sampling tool 50 when the tool is fully assembled, other locations (e.g., 78B and 78C) may be accessible from the outside of the downhole sampling tool 50 after disassembling the drill collars 80, 82, and/or 84 from one another. Therefore, each of the illustrated locations 78 of the H2S sensitive coupons are accessible to drilling operators at the rig site, without requiring disassembly of the internal components from their corresponding drill collars.

Some embodiments of the downhole sampling tool 50 (e.g., wireline tools) may not include drill collars surrounding the internal components of the downhole sampling tool 50. In such embodiments, the coupons disposed in the locations 78A, 78C, 78D, and 78E may be accessible from outside when the downhole sampling tool 50 is fully assembled. The location 78B may not be utilized in wireline sampling tools, since such tools generally do not include batteries 68 or the battery cap 66.

As discussed above, the H2S sensitive coupons may be disposed in one or more of the illustrated locations 78, which are accessible at the rig site. Thus, field engineers may remove and inspect the coupons to determine H2S exposure. If exposure to H2S is noted during this inspection, the engineers may follow certain protocol when venting pressurized gases from the downhole sampling tool 50, when disassembling the downhole sampling tool 50, or when handling samples taken via the downhole sampling tool 50.

Some of the locations 78 illustrated in FIG. 2 may be particularly positioned for allowing an operator access to the coupons and, thus, to determine whether H2S is present prior to venting pressure from the downhole sampling tool 50. These locations 78 include the probe 60 (78A), the flowline 72 at the rig site removable battery cap 66 (78B), and a rig-accessible location at the end of a hydraulic extender (78C).

The location 78A within the probe 60 may enable the passive detection of H2S within the formation fluid at the first place the formation fluid passes into the downhole sampling tool 50. This may provide a relatively accurate indication of whether any H2S was present within the formation fluid flowing into the downhole sampling tool 50. More specifically, this location 78A of the H2S sensitive coupons may be less susceptible to any H2S scavenging (e.g., H2S becoming trapped in parts of the downhole sampling tool 50) within the downhole sampling tool 50, as compared to other coupon locations further downstream in the flowline 72. In addition, the location 78A may be relatively accessible from outside the downhole sampling tool 50 when the tool is completely assembled. The probe 60 is generally disposed outside of the drill collar 84 that contains the rest of the probe module 52. The coupons may be inserted into the flowline 72 of the probe 60 via the fluid inlet 62, and subsequently removed from the fluid inlet 62, without taking apart the downhole sampling tool 50. After use, the coupons may be removed and replaced by unmarked coupons that have not changed color due to the presence of H2S. In some embodiments, the H2S detecting coupons may be visible from outside the probe 60 even without removing the coupons from the probe 60, thus enabling an operator to determine whether H2S is present in the downhole sampling tool 50 without removing the coupons from the probe 60.

FIG. 3 illustrates the location 78A of H2S sensitive coupons that may be placed within the probe 60 of a different type of downhole sampling tool 50. The probe module 52 in the illustrated embodiment includes two packer elements 90 configured to be inflated into contact with an inner wall of the wellbore 26. In this manner, the packer elements 90 may function as setting mechanisms for keeping the downhole sampling tool 50 in place and for isolating a section of the wellbore 26 around the probe 60. In this embodiment, the coupons may also be placed in the location 78A within the fluid inlet 62 of the probe 60, although this probe 60 does not include the donut-shaped pad that engages with the formation 12. It should be noted that the presently disclosed techniques of placing the coupons within the fluid inlet 62 of the probe 60 may be extended to any number of probes 60 and/or packers 90. Additionally, the arrangement, configuration, size, or shape of these probes 60 and/or packers 90 may vary across different embodiments that utilize the location 78A for holding H2S sensitive coupons.

In addition to the probe location 78A, the H2S sensitive coupons may be disposed in the location 78C within a hydraulic extender between two modules. As an example of this, FIG. 4 illustrates an embodiment of an intersection point between two modules of the downhole sampling tool 50. More specifically, the illustrated embodiment includes the multi-sample module 58 coupled to the pump-out module 56 via a hydraulic extender 110. The hydraulic extender 110 is configured to engage with the drill collar 80 of the multi-sample module 58 at one end and to engage with the drill collar 82 of the pump-out module 56 at the opposite end. The hydraulic extender 110 may enable operators to adjust the relative distance between the drill collars 80 and 82, in order to accommodate variances in the distance between internal components within the drill collars 80 and 82 due to manufacturing tolerances. Thus, the hydraulic extender 110 may be used primarily in embodiments of the downhole sampling tool 50 that have drill collars 80 and 82.

One or more coupons made of H2S sensitive material may be located in the hydraulic extender 110, as noted above. This position exposes the coupons to the flow of formation fluid being pumped through and between the pump-out module 56 and the multi-sample module 58. In addition, this location 78C is accessible at the rig site, as the different drill collars 80 and 82 are being disconnected. It should be noted that accessing the hydraulic extender 110 and, thus, the coupons disposed therein, can be accomplished without removing any internal components from either of the respective drill collars 80 and 82.

Similar to the hydraulic extender 110, the battery cap 66 disposed at the end of the hydraulics module 54 may be accessible at the rig site. The battery cap 66 may be disposed between the two drill collars 82 and 84, as shown in FIG. 2. When the drill collars 80, 82, and 84 are separated, the location 78B in the battery cap 66 may be exposed for the retrieval and examination of the H2S sensitive coupons disposed therein. This may be accomplished without the removal of any internal components from their respective drill collars 80, 82, and 84. As mentioned above, some embodiments of the downhole sampling tool 50 (e.g., wireline tools) do not include batteries 68 for powering the probe 60, and these embodiments do not include the location 78B as a place to position the H2S sensitive coupons.

In some embodiments, it may be desirable to detect levels of H2S present in a specific sample bottle 74 of the downhole sampling tool 50. As illustrated in FIG. 2, coupons made from H2S sensitive material may be disposed in the location 78D to accommodate this specific detection. The location 78D may be at an inlet to an individual sample bottle 74 and, more specifically, at a flowline stabber location going into the drill collar 80. This is a place where the sample bottle 74 is connected to the flowline 72, which is internal to the downhole sampling tool 50 and housed within the drill collar 80. It should be noted that the sample bottles 74 may be accessible from outside the drill collar 80, and the sample bottles 74 may be removable from the drill collar 80 and from the internal components held therein. The sample bottles 74 may later be stabbed back into position through the drill collar 80. Thus, the sample bottle 74 and the H2S sensitive coupons disposed therein may be accessible from outside the downhole sampling tool 50, even while the downhole sampling tool 50 remains fully assembled (e.g., the drill collars 80, 82, and 84 each contain their respective internal components). Although one such location 78D is indicated in the illustrated embodiment, it should be recognized that any number or all of the sample bottles 74 present in the downhole sampling tool 50 may be equipped with H2S sensitive coupons. The H2S sensitive coupons in the location 78D of one or more sample bottles 74 may be used to indicate which sample bottles 74 may have H2S inside, so that operators may take care in handling and testing the formation fluid stored therein.

In some embodiments, it may be desirable to detect H2S levels in order to ensure that appropriate procedures are taken when servicing the downhole sampling tool 50 at a field base location (e.g., not at the rig site). This is where the drill collars 80, 82, and 84 may be removed from the internal components stored therein. For these situations, the H2S sensitive coupons may be disposed in the location 78E, or other suitable locations, which may be accessible at the rig site but are also accessible at the field base. Such locations (e.g., 78E) may be internal parts of the tool that are relatively easy to access after the drill collar (e.g., 80) is removed from the downhole sampling tool 50. Additional H2S sensitive components may be located at other positions inside the downhole sampling tool 50 to alert maintenance technicians to the presence of H2S before they perform maintenance on the downhole sampling tool 50.

In the illustrated embodiment, the location 78E is in the flowline exit 76 of the downhole sampling tool 50. Formation fluid is pumped out of the downhole sampling tool 50 through this flowline exit 76 and back into the annulus of the wellbore 26 when the downhole sampling tool 50 is operated in the continuous pumping mode. The flowline exit 76 is disposed adjacent the drill collar 80 and includes a valve (e.g., check valve) configured to release the formation fluid pumped through the downhole sampling tool 50 into the wellbore 26. In some embodiments, the flowline exit 76 may be disposed in a field joint 112 that is separate from the drill collar 80. In other embodiments, the flowline exit 76 may be disposed within and extend out through the drill collar 80.

As discussed above, the H2S sensitive coupons may be disposed in the fluid inlet 62 of the probe 60 (e.g., location 78A). One embodiment illustrating this arrangement is shown in FIG. 5. Specifically, the illustrated embodiment includes the probe 60, which in this case is a donut-shaped probe that extends to engage a wall of the wellbore 26. The probe 60 has a rounded (e.g., circular) opening formed therein, and this opening functions as the fluid inlet 62. In the illustrated embodiment, three H2S sensitive coupons 130 are mounted on a holder 132, and the holder 132 is configured to be inserted into and removed from the probe 60 through the fluid inlet 62. Since the probe 60 extends to a position outside the drill collar 84, the holder 132 and the H2S sensitive coupons 130 may be accessible from the downhole sampling tool 50 without any disassembling of the downhole sampling tool 50. In some embodiments, the H2S sensitive coupons 130 may be mounted (e.g., on the holder 132) in such a way that the H2S sensitive coupons 130 are visible from outside of the probe 60 when disposed in the location 78A. The multiple H2S sensitive coupons 130 mounted on the holder 132 may each be made from different H2S sensitive materials, to provide detection of a range of H2S levels.

FIG. 6 is a detailed and exploded view of the holder 132 and the H2S sensitive coupons 130 mounted on the holder 132. In the illustrated embodiment, the holder 132 includes three slots 134, each configured to receive one of the coupons 130. The slots 134 may be arranged symmetrically about the holder 132, as illustrated. Other embodiments may include other numbers of slots 134 and/or slots 134 arranged in other configurations along the holder 132. In order to maintain the coupons 130 in their respective slots 134 within the holder 132, the holder 132 may include pins 136, and the coupons 130 may have apertures 138 formed therein and configured to receive the pins 136. In addition, walls of the holder 132 that define the slots 134 may include apertures 140 as well to receive the pins 136. In the illustrated embodiment, the pins 136 are oriented approximately perpendicular to planar surfaces of the corresponding coupons 130 and slots 134. It should be noted that, in other embodiments, more than one pin 136 may be used to secure each individual coupon 130 within its respective slot 134. In addition, it should be noted that other types of securement mechanisms may be used to maintain the coupons 130 in the holder 132, as described below.

FIG. 7 illustrates one implementation of the coupons 130 into the location 78A of the probe 60. The illustrated embodiment includes a partial cutaway view of the internal components of the probe 60. Among other components, the probe 60 may include a filter piston 150, which is a type of valve that can be actuated to allow the flow of formation fluid into the downhole sampling tool 50. The filter piston 150 may be concentrically aligned with the fluid inlet 62 of the probe 60. In the illustrated embodiment, the holder 132 with the mounted coupons 130 may be inserted onto an end of the filter piston 150. The holder 132 may be a threaded insert into the filter piston 150, so that the entire holder 132 with the mounted coupons 130 may be removed from the probe 60. In other embodiments, the holder 132 may be an integral piece formed with the filter piston 150, such that the coupons 130 may be removed directly from the probe 60.

In the location 78A, the coupons 130 may be held in place in a flow path of the formation fluid being pumped into the downhole sampling tool 50. In the illustrated embodiment, arrows 152 indicate a flow of formation fluid through the probe 60. Specifically, the formation fluid flows into the probe 60 through the fluid inlet 62, and the formation fluid flows directly across and around the holder 132 and the coupons 130 mounted thereon. Thus, the coupons 130 may be exposed to the formation fluid being pumped into the downhole sampling tool 50, and the coupons 130 may change colors in response to a presence and/or level of H2S in the formation fluid.

FIGS. 8-11 illustrate various embodiments of the holder 132 and the associated coupons 130 that may be mounted on the holder 132 in specific ways. Each of these holders 132 may be applied within the probe 60 illustrated in FIG. 7. Similar holders 132 and mounted H2S sensitive coupons 130 may be disposed in other locations (e.g., 78B, 78C, 78D, 78E, etc.) of the downhole sampling tool 50. It should be noted that the embodiments illustrated in FIGS. 8-11 are demonstrative and that other arrangements of the coupons 130 mounted on the holders 132 may be used in other embodiments. In some embodiments, combinations of the techniques described with reference to the individual figures may be used. Furthermore, although FIGS. 8, 9, and 11 include holders 132 that are configured to mount four coupons 130 each, other numbers of coupons 130 (e.g., 1, 2, 3, 5, 6, 7, 8, and so forth) may be mounted onto a single holder 132 that employs one of the disclosed techniques for holding the H2S sensitive coupons 130 in a formation fluid flow path.

In some embodiments, the coupons 130 may be mounted integrally with the holder 132 so that, in order to remove the coupons 130 from the downhole sampling tool 50, an operator may remove the entire holder 132. FIG. 8 shows one such embodiment, where the coupons 130 are brazed to the holder 132. Any desired techniques may be used to fuse the coupons 130 with the holder 132, thereby ensuring that the holder 132 remains an integral piece with the coupons 130. In the embodiment of FIG. 9, the coupons 130 are separate pieces that may be mounted to the sides of the holder 132. That is, the holder 132 includes the slots 134 configured to receive the coupons 130, as discussed above with reference to FIG. 6. In other embodiments, the coupons 130 may be separate pieces that are mounted to an end of the holder 132, instead of the sides as shown. In either case, the holder 132 may receive the at least one coupon 130 as press fit inserts, inserts that are screwed into the holder 132, or inserts that are removably held in place by pins. As shown in the partial cutaway view of FIG. 10, the individual coupons 130 may be held in place within the slot 134 via the pin 136, as described in detail above with reference to FIG. 7. The pin 136 may be removable from the holder 132 to allow access to the coupon 130. This arrangement may be useful for allowing replaceable coupons 130 to be inserted and subsequently removed from the holder 132.

It should be noted that the shape of the coupons 130 may vary across different embodiments. For example, the coupons 130 may include H2S sensitive material formed in a domed or cylindrical shape that is inserted into the holder 132. As one example of this, FIG. 11 illustrates an embodiment showing domed coupons 130 that may be flush mounted to openings in the holder 132 or brazed into pockets of the holder 132. In some embodiments, the domed coupons 130 may be spring loaded so that they may be pressed together, inserted through an opening in an upper surface 160 of the holder 132, and pressed into the holder 132 until the domed coupons 130 reach rounded openings 162 in the sides of the holder 132. At this point, the spring-loaded domed coupons 130 may extend outward to fill the openings 162 so that the coupons 130 are flush mounted to the openings 162 in the holder 132. This may allow the coupons 130 to be removable and replaceable from the holder 132. In other embodiments, the domed coupons 130 may be brazed into pockets formed in the holder 132, thereby making the coupons 130 integral with the holder 132. Again, it should be noted that any desired arrangement of coupons 130 may be mounted to any desirable type of holder 132, in order to maintain the coupons 130 in one of the disclosed locations 78. Again, mounting the coupons 130 in these locations 78 may allow the coupons 130 to be exposed to the formation fluid pumped into the downhole sampling tool 50, while leaving the coupons 130 accessible to operators (visually and/or physically) at the rig site.

FIG. 12 is a process flow diagram of a method 170 for detecting the presence of H2S within the downhole sampling tool 50 using the presently disclosed techniques. Every part of the method 170 may be performed at the rig site. The method 170 includes, at the rig site, disposing (block 172) the downhole sampling tool 50 into the wellbore 26. This may be performed while drilling by using the LWD 40 of FIG. 1 or a similar arrangement of the downhole sampling tool 50. In other embodiments, a multi-conductor wireline may be used to lower the downhole sampling tool 50. The method 170 also includes pumping (block 174) formation fluid from the formation 12 into the flowline 72 of the downhole sampling tool 50. To accomplish this, the downhole sampling tool 50 may extend the probe 60 to engage the formation 12, and the pump 70 may create a pressure differential that draws the formation fluid out of the formation 12, through the probe 60, and into the flowline 72. In addition, the method 170 includes exposing (block 176) the one or more H2S sensitive coupons 130 to the formation fluid flowing into or through the downhole sampling tool 50. The location 78 of the coupons 130 in the downhole sampling tool 50 may be such that the coupons 130 are exposed to the formation fluid during certain operations of the downhole sampling tool 50. Further, the method 170 includes raising (block 178) the downhole sampling tool 50 out of the wellbore 26. This may be performed after the desired samples of formation fluid have been taken into the sample bottles 74.

The method 170 also includes accessing (block 180) the coupons 130 at the rig site. In some embodiments, this may involve removing the coupons 130 from the downhole sampling tool 50 at the rig site. For example, accessing (block 180) the coupons 130 may involve disassembling a series of the drill collars 80, 82, and/or 84 from one another to expose the coupon 130. This may be the case when the coupon 130 is located in relatively internal locations (e.g., 78B, 78C, or 78E). In embodiments where the coupon 130 is located in the probe 60, accessing (block 180) the coupon 130 may involve accessing the coupon 130 at the location 78A in the probe 60 when the downhole sampling tool 50 is fully assembled. In still further embodiments, accessing (block 180) the coupons 130 may involve visually accessing and inspecting the color of the coupons 130, without removing the coupons 130 from the downhole sampling tool 50.

The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover any modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.

System And Method For Detecting Hydrogen Sulfide In A Formation Sampling Tool

Information

Publication Number

Date Filed

Date Published

Inventors

Original Assignees

CPC

International Classifications

Abstract

Description

Claims