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BACKGROUND 
     Technical Field 
       [0001]    The present disclosure generally relates to apparatuses and methods for evaluating formations traversed by a well borehole and in particular to formation sampling and testing. 
       Background Information 
       [0002]    Formation sampling and testing tools have been used in the oil and gas industry for collecting formation samples, for monitoring formation parameters such as pressure along a well borehole, and for predicting performance of reservoirs around the borehole. Such formation sampling and testing tools typically include an elastomer packer or pad that is pressed against a borehole wall portion to form an isolated zone from which formation samples are collected. Information that helps in determining the viability of the formation for producing hydrocarbons and in determining drilling operation parameters may then be acquired by evaluating the formation samples. 
         [0003]    Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more downhole fluid samples produced from the subterranean formations. Downhole fluids, as used herein include any one or any combination of drilling fluids, return fluids, connate formation fluids, and formation fluids that may be contaminated by materials and fluids such as mud filtrates, drilling fluids and return fluids. Downhole fluid samples are often retrieved from the borehole and tested in a rig-site or remote laboratory to determine properties of the fluid samples, which properties are used to estimate formation properties. Modern fluid sampling also includes various downhole tests to estimate fluid properties while the fluid sample is downhole. 
         [0004]    Some formations produce hazardous fluids, and local governmental regulations may greatly control and restrict the amount of formation fluids that are introduced into the well borehole to reduce the risk of exposing the surface environment and personnel to these hazardous fluids. This is the case even when it is necessary to retrieve connate formation samples from formations that produce hazardous downhole fluids. It is difficult to retrieve connate formation samples from these hazardous fluid producing formations, because borehole fluids and filtrates often contaminate the formation samples. One obstacle is that cleanup processes used to remove borehole contaminants from a fluid sample to obtain a connate fluid sample substantially free of borehole contaminants usually results in ejecting large amounts of formation fluid into the borehole. Thus, the hazardous formation fluids are produced into the return fluid posing environmental threats and hazards to personnel at the surface. 
       SUMMARY 
       [0005]    The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows. 
         [0006]    A method for collecting a downhole fluid includes receiving a downhole fluid into a downhole sub from a first borehole wall portion adjacent a formation of interest and expelling at least a portion of the received downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion. 
         [0007]    Another method aspect for collecting a downhole fluid includes conveying a downhole sub in a borehole, the downhole sub including a fluid sampling tool. A first borehole wall portion adjacent a formation of interest is sealed using a first seal coupled to the fluid sampling tool and a second borehole wall portion is sealed using a second seal coupled to the fluid sampling tool. A first fluid path is established with the first borehole wall portion and the tool. A second fluid path is established with the second borehole wall portion and the tool. The method further includes receiving the downhole fluid into the fluid sampling tool using the first fluid path, flowing the received downhole fluid through the tool during a cleanup process, estimating a fluid contamination level during the cleanup process, and expelling at least a portion of the received downhole fluid from the tool using the second fluid path during the cleanup process to remove some or all borehole contaminants from the received downhole fluid until fluid flowing through the tool is a substantially contamination free connate formation fluid. The substantially contamination free connate formation fluid may be stored in a fluid sample chamber. 
         [0008]    An apparatus includes a downhole sub, a formation sampling member coupled to the downhole sub for collecting the downhole fluid from a first borehole wall portion adjacent a formation of interest, a sample expulsion member coupled to the downhole sub for expelling at least a portion of the collected downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0009]    For detailed understanding of the present disclosure, references should be made to the following detailed description of the several embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein: 
           [0010]      FIG. 1  schematically illustrates a non-limiting example of a well logging system in a wireline arrangement according to several non-limiting embodiments of the disclosure; 
           [0011]      FIG. 2  illustrates a non-limiting example of extendable probes useful in several embodiments of the disclosure; 
           [0012]      FIG. 3  illustrates a non-limiting example of a straddle packer arrangement useful in several embodiments of the disclosure; 
           [0013]      FIG. 4  illustrates a non-limiting example of a fluid sample container suitable for operation as a flush-through sample container; and 
           [0014]      FIG. 5  illustrates an exemplary fluid sample container including one or more devices for controlling pressure within the container during transport. 
       
    
    
     DESCRIPTION OF EXEMPLARY EMBODIMENTS 
       [0015]      FIG. 1  schematically illustrates a non-limiting example of a well logging system  100  in a wireline arrangement according to several non-limiting embodiments of the disclosure. The exemplary logging system  100  includes a downhole sub  102  shown disposed in a borehole  104  and supported by a wireline cable  106 . The exemplary downhole sub  102  may include one or more centralizers  108 ,  110  for centralizing the downhole sub  102  in the borehole  104 . The cable  106  may be supported by a sheave wheel  112  disposed in a drilling rig  114 . The cable  106  may be wound on a drum  116 , shown here mounted on a truck  118 , for lowering or raising the downhole sub  102  in the borehole. The cable  106  may comprise a multi-strand cable having electrical conductors for carrying electrical signals and power from the surface to the downhole sub  102  and for transmitting information to and from the downhole sub  102 . The downhole sub  102  may send information to and receive information from the surface for processing and/or for executing commands. A surface transceiver  120  and a controller  122  may be located on the truck  118  or at any suitable surface location. The exemplary downhole sub  102  communicates with the surface controller  122  via the surface transceiver  120  and a downhole transceiver  124 . 
         [0016]    The exemplary wireline  FIG. 1  operates as a carrier, but any carrier is considered within the scope of the disclosure. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, downhole subs, BHA&#39;s, drill string inserts, modules, internal housings and substrate portions thereof. 
         [0017]    In the non-limiting embodiment of  FIG. 1 , the downhole sub  102  includes a downhole evaluation tool  126 , and the downhole evaluation tool  126  may include an assembly of several tool segments that are joined end-to-end by threaded sleeves or mutual compression unions  128 . An assembly of tool segments suitable for the present disclosure may include an arrangement as shown in  FIG. 1 . The exemplary arrangement includes the transceiver  124  discussed above, and a downhole controller  130  is shown below the transceiver  124 . The downhole controller  130  may further include a processor and memory for processing information and for executing commands used for controlling aspects of the downhole sub  102 . A power unit  132  may be coupled below the controller  130 . The power unit  132  may include one or more of a hydraulic power unit, an electrical power unit and an electromechanical power unit. A formation sampling tool  134  is shown coupled to the downhole evaluation tool  126  below the power unit  132 . 
         [0018]    The exemplary formation sampling tool  134  shown in  FIG. 1  includes a formation sampling member  136  and a sample expulsion member  138 . The formation sampling member  136  may be extendable as shown in this example or the formation sampling member  136  may be a tool portion having a port for receiving a formation sample. Likewise, the sample expulsion member  138  may be extendable as shown in this example or the sample expulsion member  138  may be a tool portion having a port for expelling a formation sample from the tool. The exemplary formation sampling tool  134  may be configured for acquiring and/or extracting a formation core sample, a formation fluid sample, formation images, nuclear information, electromagnetic information, and/or other downhole samples. 
         [0019]    Referring to  FIGS. 1 ,  2  and  3 , several non-limiting embodiments may be configured with the formation sampling tool  134  operable as a fluid sampling tool. In these embodiments, the formation sampling member may include an extendable probe having a sealing pad  200  for isolating a portion of the well borehole. The fluid expulsion member  138  may also include an extendable probe having a sealing pad  200  as depicted in  FIG. 2 . Other exemplary arrangements may use straddle packers  300  as depicted in  FIG. 3  for isolating borehole portions for the respective formation sampling member  136  and fluid expulsion member  138 . Combinations of extendable pad seals and straddle packers are also within the scope of the disclosure. A fluid pump  140  may be placed in fluid communication with the formation sampling member  136  included with the formation sampling tool  134  for collecting fluid samples. The fluid pump  140  may be a single pump or may include one pump for line purging and a smaller displacement pump for collecting samples and for quantitatively monitoring fluid received by the downhole evaluation tool via the formation sampling tool  134 . The fluid pump  140  may be a variable rate pump or a constant rate pump. 
         [0020]    One or more flush-through fluid sample containers  142  may be included below the fluid pump  140  and above the sample expulsion member  138 . In several examples, the fluid sample containers  142  are individually or collectively detachable from the downhole evaluation tool formation sampling tool  134 . Further details of several exemplary flush-through fluid sample containers will be provided below with reference to  FIGS. 4-5 . 
         [0021]      FIG. 4  illustrates a non-limiting example of fluid sample container  400  suitable for operation as a flush-through sample container according to one or more embodiments described above and shown in  FIG. 1  at reference numeral  142 . The exemplary fluid sample container  400  may be used in a wireline arrangement, in a while-drilling drilling arrangement, a slickline arrangement or by using any suitable carrier for conveying the fluid sample container  400  in a well borehole. The exemplary embodiment of  FIG. 4  is shown detachably mounted in a downhole sub  102 . 
         [0022]    The exemplary fluid sample containe  400  shown in  FIG. 4  includes an elongated body  402  having an internal cavity  404  for receiving fluid samples  406 . The elongated body  402  portion of the exemplary fluid sample container  400  includes a first end  408  and a second end  410  axially displaced from the first end. The elongated body  402  has a first opening  412  in the first end for receiving the fluid  406  into the internal cavity  404 , and a second opening  414  in the second end  410  for expelling at least a portion of the fluid  406  from the internal cavity  404 . The fluid sample container  400  of this non-limiting embodiment includes a fluid flow control device  416  proximate the second end  410  of the body  402  and coupled to the downhole sub for controlling fluid expulsion from the internal cavity  404 . The fluid flow control device  416  shown may be a controlled valve or any suitable fluid flow control device that is controllable to control fluid expulsion from the second opening  414  during fluid sampling and may be operable to cease fluid expulsion when a predetermined parameter is met for the downhole fluid expelled from the fluid container  400 . 
         [0023]    Additional fluid control devices  416  are shown in the exemplary embodiment of  FIG. 4  coupled to the downhole sub input flow line  420  and within the container  400  proximate the body first end  408  to control fluid flow to and within the first end. The first end fluid control devices may be substantially similar to the fluid control devices  416  proximate the second end  410 , but the fluid control devices  416  may be of different types without departing from the scope of the disclosure. 
         [0024]    The exemplary embodiment shown in  FIG. 4  includes a flow line connector  418  connected to an input flow line  420  at the body first end  408  for allowing fluid flow into the internal cavity  404 . A similar flow line connector  418  and flow control device  416  are shown coupled to an output flow line  422  at the body second end  410  for allowing fluid expulsion from the internal cavity  404 . The input flow line  420  and the output flow line  422  in the example shown here are flow line portions of the downhole sub  102  that are in fluid communication with the internal cavity  404  of the formation sample container  400 . 
         [0025]    The fluid sample container  400  may be detachable from the downhole sub  102  using detachable flow line connectors  418  and one or more detachable mounting members  424  that couple the fluid sample container body  402  to the downhole sub  102 . The downhole sub  102  may include a pump  140  for conveying fluid through a fluid flow control device  416 , which may be a valve controllable downhole using command signals. The fluid flow control device  416  is in communication with the internal cavity  404 . 
         [0026]    The exemplary fluid sample container  400  may further include a check value  426  as shown coupled to the input flow line connector  418  and a similar check valve  426  coupled to the output flow line connector  418  to help ensure fluid flows through the fluid sample container  400  in one direction during a downhole sample cleanup process. 
         [0027]    The non-limiting embodiment of  FIG. 4  may further include a fluid evaluation module  428 . In one or more embodiments, the fluid evaluation module  428  may be in fluid communication with the output flow line  422  for estimating fluid content of fluid expelled from the internal cavity  404 . In one or more embodiments, the fluid evaluation module  428  may be in fluid communication with the input flow line  420  for estimating fluid content of fluid entering the internal cavity  404 . In one or more embodiments, a fluid evaluation module  428  may be in fluid communication with both the input flow line  420  and the output flow line  422  for estimating fluid content of fluid entering and exiting the internal cavity  404 . The fluid evaluation module may be a single module as shown or may be implemented using two or more modules. 
         [0028]    The fluid evaluation module  428  may include any number of fluid measurement devices for estimating fluid characteristics of the fluid  406  entering or leaving the internal cavity  404 . The fluid evaluation module  428  may be arranged to estimate optical characteristics, electrical characteristics, physical characteristics and any combination of characteristics of the fluid  406 . For example, some test devices may be in fluid contact with fluid flowing in the fluid evaluation module, some devices may be in optical communication, some devices may be in acoustic communication, some devices may be in physical contact with the fluid, and still others may be in pressure and/or thermal communication with the fluid. 
         [0029]    Optical characteristics may be estimated using a downhole fluorescence test device, a reflectometer, a spectrometer, or any combination thereof. Physical characteristics of the fluid may be estimated using a viscometer, a pressure sensor, a temperature sensor, fluid density transducer, or any combination thereof. Electrical characteristics of the fluid  406  may be estimated using resistivity measurement devices, capacitance and dielectric constant measurement devices, or combinations thereof. Other devices may be included with the fluid evaluation module  428  for estimating fluid chemical properties and compositional properties. Exemplary devices include, but are not limited to, a gas chromatograph, a pH test device, a salinity test device, a CO2 test device, an H2S test device, a device for determining wax and asphaltene components, a device for determining metal content, (mercury or other metal), a device for determining acidity of the fluid, or any combination thereof. 
         [0030]    In one or more embodiments, the internal cavity  404  is defined by a smooth curvilinear surface  430  within the body  402 . The surface  430  may be selected based on the desired cavity volume, overall size of the body and on fluid flow characteristics. In the exemplary embodiment of  FIG. 4 , the internal cavity  404  has a substantially oval cross section along a longitudinal axis. In one or more embodiments, the internal cavity  404  may be spherical with a substantially circular cross section. In one or more embodiments, the internal cavity  404  may have a cylindrical center portion with flat end portions, hemispherical end portions, conical end portions, or any other end portion shape that provides relatively free fluid flow within the internal cavity  404 . A surface treatment that reduces fluid adhesion may be used to further reduce sticking and resistance in the fluid flow within the internal cavity  404 . Exemplary surface treatments include, but are not limited to, polishing, coatings, laminates, inserts and combinations thereof. 
         [0031]    Turning now to  FIG. 5 , and exemplary fluid sample container  500  may further include one or more devices for controlling pressure within the container  500  during transport. The non-limiting embodiment shown in  FIG. 5  is coupled to a downhole sub  102  and includes a substantially cylindrical internal cavity  504 . Many of the items in  FIG. 5  may be substantially lo similar to the like-numbered items describe above and shown in  FIG. 4 . For brevity, the following description will focus more on the additional features shown in  FIG. 5 . 
         [0032]    The exemplary fluid sample container  500  includes and elongated body  502  having an internal cavity  504  for receiving fluid samples  506 . The elongated body  502  portion of the exemplary fluid sample container  500  includes a first end  508  and a second end  510  axially displaced from the first end. The elongated body  502  has a first opening  512  in the first end  508  for receiving the fluid into the internal cavity  504  from the formation sampling member  136 . A second opening  514  in the second end  510  may be used for expelling at least a portion of the fluid  506  from the internal cavity  504  through the fluid expulsion member  138 . The fluid sample container  500  of this non-limiting embodiment includes a pressure control device  516  for controlling pressure of the fluid sample  506 . The pressure control device  516  provides a flow path via a check valve  522  for fluid  506  flowing through the internal cavity  504  and allows for substantially unrestricted flow during the cleanup process and expulsion of fluid from the internal cavity  504  via the expulsion member  138 . The pressure control device  516  in one or more non-limiting embodiments includes a piston  526  that is movably disposed within the cavity  504 . One or more O-rings  518  provide a fluid and pressure seal between the piston  526  and cavity wall  530 . The check valve  522  is positioned within the piston  526  to provide a flow path through the piston  526  to the opening  514  in the second end  510 . 
         [0033]    The piston  526  is shown positioned toward the second end  510  with the sample  506  shown with an arrow to indicate the direction of flow through the container  500 . The check valve  522  prevents flow in the opposite direction. In this manner, the fluid flow through the internal cavity is substantially free flowing during sample cleanup. 
         [0034]    The pressure control device  516  may be actuated using a device controller  520 . In one or more embodiments, the device controller  520  may be a pump substantially similar to the pump  140  described above and shown in  FIG. 1 . In one or more embodiments, the pump  140  may be used as the controller for the pressure control device  516 . A gas supply  524  is shown in communication with one end of the piston  526  and with the device controller  520 . In one or more embodiments, the gas supply may include a pressurized inert gas such as nitrogen. When actuated, the device controller may be used to add pressure to the gas supply and/or to urge gas toward the piston  526 . When pressurized, the piston tends to move toward the first end  508 , thereby decreasing the volume in the cavity  504  and/or increasing the pressure within the cavity  504  when one or more of the inflow and outflow fluid control devices  416  are actuated to cease fluid flow. In this manner, the fluid  506  may be maintained at a predetermined pressure once a fluid sample is collected in the internal cavity  504 . For example, the fluid  506  may be maintained above its bubble point pressure for transport to the surface. 
         [0035]    Several non-limiting operational embodiments for formation sampling will now be described with reference to  FIGS. 1 through 5 . In one or more embodiments a downhole sub  102  may be conveyed in a well borehole to a formation of interest. A portion of the borehole is isolated using straddle packers, a pad seal disposed on the end of an extendable probe or by using a combination of packers and extendable probe to create an isolated zone. Fluid communication is established between the formation of interest and the downhole sub by exposing a tool port to the isolated zone. In some embodiments, formation pressure may be sufficient to flow fluid from the formation into the tool. In one or more embodiments, a pump  140  or other flow controller may be used to urge fluid into the downhole sub. 
         [0036]    Fluid flow into the downhole sub may be maintained in a substantially continuous manner to perform a cleanup process for removing borehole contaminants from the downhole fluid entering the downhole sub. The sample cleanup process may include initially expelling fluid from the downhole sub while the pump or formation pressure urges fluid through the downhole sub. In one or more embodiments, the fluid is monitored for content properties during the cleanup process to estimate a cleanliness level of the fluid flowing within the tool. In one or more embodiments, fluid expulsion is accomplished by reinjecting the expelled fluid into the formation proximate the downhole sub to limit or prevent the fluid from entering the borehole annulus. In one or more embodiments, the fluid is injected into the formation using an extendable expulsion member that is extended to establish fluid communication with the formation. The fluid expulsion may be halted when the fluid within the tool is estimated to be substantially free of contaminants. 
         [0037]    In one or more embodiments, fluid samples may be contained within the tool using an internal fluid sample container  400 ,  500 . In one or more embodiments, the fluid cleanup process may include urging the fluid received in the tool through a first end of the fluid sample container and expelling the fluid from a second end of the fluid sample container. Once the estimations show that the fluid within the fluid sample container are substantially free of contaminants, the second container end flow path may be closed using a sub-carried valve  416  that is in fluid communication with the output flow line  422 . 
         [0038]    The pump  140  may be used to increase the pressure in the container internal cavity  404 ,  504  to a desired pressure. Once the pressure within the internal cavity reaches the desired pressure, then the pump may be halted and a second sub-carried valve  416  that is in fluid communication with the input flow line  420  may be actuated to close the flow path into the internal cavity  404 ,  504 . In this manner, the fluid sample  406 ,  506  is sealed within a volume defined between the two sub-carried valves  416 . 
         [0039]    Pressure within the internal cavity may be controlled after sample collection and during transport using a pressure control device. Fluid may flow through the pressure control device during the cleanup process and a check valve may be used to allow fluid flow in only one direction through the pressure control device. An inert gas may be used to move a piston within the internal cavity to control pressure. 
         [0040]    In one or more embodiments, the fluid sample container  400 ,  500  may be transported to a surface location and removed from the downhole sub without losing fluid containment within the internal cavity  404 ,  504 . Surface operations may include actuating the first end and second end fluid control devices  416  within the container body  402 ,  502  to seal the respective first end and second end portions of the internal cavity  404 ,  504 . The fluid sample  20  container  400 ,  500  may then be disconnected from the downhole sub  102  by disconnecting the detachable couplings  424  and the flow line connectors  418 . 
         [0041]    The sample container internal cavity  404 ,  504  may be flushed of contaminants and/or connate fluids without leaving substantial residue within the internal cavity. The pump  140  may generate a fluid flow through the cavity. In some embodiments, the cavity  404 ,  504  includes a curvilinear wall  430 ,  530  that reduces fluid sticking within the cavity. The wall  430 ,  530  may further include a surface treatment that further reduces fluid resistance and may be used to reduce sample sticking along the wall  430 ,  530 . 
         [0042]    Fluid initially urged into the downhole sub  102  may include one or more contaminants such as borehole fluid and filtrates. Undesirable fluid sample components such as the above-noted contaminants may be cleaned from the fluid entering the downhole evaluation tool  126  by pumping the fluid into the tool and then expelling the fluid through the sample expulsion member  138  until the fluid entering the tool is substantially free of the undesirable contaminants. 
         [0043]    In one or more embodiments, pumping and expulsion is performed for a period of time without separate content monitoring with the period of time selected to establish substantially contaminant-free connate fluid flow in the tool. The fluid sample expulsion may be halted on or after completion of the time-based pumping. In one or more embodiments, fluid flowing in the tool is monitored using a downhole tester to estimate fluid content in substantially real-time. The fluid sample expulsion may be halted on or after the content estimate establishes that the fluid flowing in the tool is substantially contaminant-free connate fluid. 
         [0044]    One or more operational embodiments address fluid expulsion where environmental regulations, safety concerns or other factors make it desirable to reduce or avoid introducing produced formation fluid to the well borehole. Fluid communication may be established between the sample expulsion member  138  and the formation proximate the sample expulsion member. In this manner, fluid expelled from the tool may be directly injected into the formation with leakage into the well borehole being reduced to levels in compliance with the applicable regulations or to levels that mitigate the safety hazards or that otherwise meet the selected leakage standards set for the particular sampling operation. Formation fluid samples that are substantially free of contaminants may be brought to the surface for testing on-site or in a laboratory environment using the flush through sample container  142 . 
         [0045]    The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below.

Summary:
A method and apparatus for collecting a downhole fluid are disclosed. A method includes receiving a downhole fluid into a downhole sub from a first borehole wall portion adjacent a formation of interest and expelling at least a portion of the received downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion. An apparatus includes a downhole sub, a formation sampling member coupled to the downhole sub for collecting the downhole fluid from a first borehole wall portion adjacent a formation of interest, a sample expulsion member coupled to the downhole sub for expelling at least a portion of the collected downhole fluid from the downhole sub to a second borehole wall portion, wherein substantially all of the expelled downhole fluid enters the second borehole wall portion.