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CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is claims priority from U.S. Provisional Patent Application Ser. No. 61/485,961, filed on May 13, 2011, the disclosure of which is incorporated herein by reference in its entirety. 
     
    
     FIELD OF THE DISCLOSURE 
       [0002]    This disclosure pertains generally to investigations of underground formations and more particularly to systems and methods for evaluating downhole fluids. 
       BACKGROUND OF THE DISCLOSURE 
       [0003]    Commercial development of hydrocarbon fields requires significant amounts of capital. Before field development begins, operators desire to have as much data as possible in order to evaluate the reservoir for commercial viability. While data acquisition during drilling provides useful information, it is often also desirable to conduct further testing of the hydrocarbon reservoirs in order to obtain additional data. Therefore, after a borehole for a well has been drilled, the hydrocarbon zones are usually tested with tools that acquire fluid samples, e.g., liquids from the formation. These fluids may be multi-phase fluids; i.e., fluids that are a mixture of water, hydrocarbons, and/or solids. The multi-phase nature of these fluids may reduce the accuracy of evaluation of a particular phase. 
         [0004]    In one aspect, the present disclosure addresses the need to separate one or more phases of a downhole fluid. 
       SUMMARY OF THE DISCLOSURE 
       [0005]    In one aspect, the present disclosure provides an apparatus for sampling a fluid in a borehole. The apparatus may include a vessel configured to be disposed in a borehole, the vessel being further configured to separate the fluid into a plurality of phases without substantially affecting a structure of at least one of the separated phases; and at least one sensor in communication with one phase of the plurality of phases in the vessel. 
         [0006]    In another aspect, the present disclosure provides a method for sampling a fluid in a borehole. The method may include separating the fluid into a plurality of phases in a vessel positioned in the borehole without substantially affecting a structure of at least one of the separated phases; and estimating a parameter of interest relating to at least one phase separated from the fluid while the at least one phase is in the vessel. 
         [0007]    Examples of certain features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]    For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein: 
           [0009]      FIG. 1  shows a schematic of a centrifugal-type of separator according to one embodiment of the present disclosure; 
           [0010]      FIG. 2  shows a schematic of a thermal separator according to one embodiment of the present disclosure; and 
           [0011]      FIG. 3  shows a schematic of a separator that uses reactive surfaces according to one embodiment of the present disclosure; 
           [0012]      FIG. 4  shows a schematic of a membrane-based separator according to one embodiment of the present disclosure; 
           [0013]      FIG. 5  illustrates a schematic of a formation evaluation system that includes a separator according to one embodiment of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0014]    In aspects, the present disclosure relates to devices and methods to evaluate downhole fluids. As used herein, the term downhole fluid is generally any fluid found in a drilled wellbore and/or any fluid that resides in the formation. Downhole fluids include but are not limited to, naturally occurring fluids such as oil, gas, and water, as well as engineered fluids such as drilling fluids and surface injected fluids. The teachings may be advantageously applied to a variety of systems in the oil and gas industry, water wells, geothermal wells, surface applications and elsewhere. Merely for clarity, certain non-limiting embodiments will be discussed in the context of hydrocarbon producing wells. 
         [0015]    Referring initially to  FIG. 1 , there is schematically illustrated one embodiment of a test tool  100  that may be used to actively separate a fluid into two or more homogeneous materials or phases (e.g., a polar phase, a nonpolar phase, an aqueous phase, a liquid hydrocarbon, a gas hydrocarbon, water, etc.). As discussed in further detail below, the separation may be performed without substantially affecting a structure of one or more of the substances making up the several phases. That is, after the separation, one or more than one of the separated phases still retains the same molecular structure as prior to the separation (e.g., minimal molecular dissolution or association). Of course, a minimal amount of change may be encountered in the post-separated phase, but not to a degree that affects the ability to use the post-separated phase to acquire information relating to that phase prior to separation. Thus, the pre-separation and post-separation phases are structurally similar. 
         [0016]    The tool  100  may be used to evaluate one or more characteristics of the separated phase(s) and also estimate one or more parameters relating to the separation process (e.g., pressure, temperature, etc.). The tool  100  may include an inlet  102  through which a fluid  103  enters an active separation chamber  104  and outlets  106   a,b  through which the separated phases  107   a,b  exit the separation chamber  104 . The tool  100  may include a variety of sensors configured to estimate one or more desired parameters. For example, a sensor  108   a  may be used to estimate a characteristic of a first phase component (e.g., oil), and a sensor  108   b  may be used to estimate a characteristic of a second phase component (e.g., water). Other phase components (e.g., condensates) may be evaluated with similar sensors (not shown). Also, sensors  108   c  may be used to estimate one or more environmental parameters (e.g., pressure, temperature, rotational speed, fluid flow rate, fluid velocity, etc.). In embodiments, the test tool  100  may include a separator  110  that uses rotation to separate the fluid into two or more phase components. The separator  110  may include an enclosure  112 , which may be drum-shaped, that is rotated by a suitable motor  114 . 
         [0017]    During operation, the fluid  103  flows via the inlet  102  into the enclosure  112 , which is rotated by the motor  114 . The centrifugal forces generated by the rotating enclosure  112  separates phases based on relative density. In other embodiments, the separation may be performed independent of orientation. As shown, the relatively lighter phase  107   a  (e.g., oil) separates and exits via outlet  106   a  and the relatively denser phase  107   b  (e.g., water) separates and exits via outlet  106   b.    
         [0018]    Further, in some embodiments, the enclosure  112  may be oriented to allow gravity to also separate the phases based on relative density. For example, the tool  100  may include an orientation sensor (not shown) that provides an indication of verticality and an orientation device (not shown) that orients the device such that more dense phases collect at a particular location in the chamber  104 . 
         [0019]    In conjunction with the separation process, the sensors  108   a - c  may generate information relating to one or more parameters of the fluid  103 , the separated phase components  107   a,b  and/or the environmental conditions associated with the tool  100 . ‘Information’ may be data in any form and may be “raw” and/or “processed,” e.g., direct measurements, indirect measurements, analog signal, digital signals, etc. It should be appreciated that the information provided by the sensors  108   a,b  is indicative of a state, condition, or property of the separated phase immediately after separation, but before the separated phase has exited the tool  100 . Also, the sensors  108   c  may provide information relating to the conditions under which the separation occurred. Thus, in aspects, the tool  100  may provide information that includes at least a property of one or more separated components and the conditions that caused the separation. 
         [0020]    The sensors  108   a,b  may be configured to generate information regarding the chemical composition(s) or material properties(s) of the separated phases  107   a,b . This information may relate to properties that include, but are not limited to, one or more of: (i) pH, (ii) H 2 S, (iii) density, (iv) viscosity, (v) thermal conductivity, (vi) electrical resistivity, (vii) chemical composition, (viii) reactivity, (ix) radiofrequency properties, (x) surface tension, (xi) infra-red absorption, (xii) ultraviolet absorption, (xiii) refractive index, and (xiv) rheological properties. 
         [0021]    The separation of the phase components may be performed by a number of different devices and techniques in addition to the centrifugal separator shown in  FIG. 1 . For example, the tool  100  may include a cyclonic separator wherein the fluid  103  is spun in a spiral or helix-like manner in the chamber  104 . Still other non-limiting embodiments of separators are discussed below. 
         [0022]    Referring now to  FIG. 2 , there is shown a thermal separator  120  that includes a distillation column  122 . In some embodiments, cooling devices such as thermoelectric elements  124   a,b  may be used to remove heat from the fluid  123  in the column  122 . A thermoelectric elements  124   a,b  may be formed of a suitable material (e.g., bismuth telluride) that when energized by an electrical circuit  126  transfers heat across a space against a temperature gradient (or Peltier effect). A suitable power source  128  may provide electrical power. In other embodiments, heat may be applied by suitable heating elements to separate phases in the distillation column  122 . In addition to or instead of thermal separation, electrostatic forces may be used to separate phase components based on the electric charge of the components. As discussed previously, sensors  108   a - c  may be used to obtain desired information relating to the fluid and/or environment in the distillation column  122 . 
         [0023]    Referring now to  FIG. 3 , there is shown a column  140  that includes one or more reactive column surfaces  142  that define a flow conduit  144  where the separator  140  is used for chromatographic purposes, e.g., high performance liquid chromatography, ion exchange chromatography, hydrophobic interaction chromatography, gel filtration chromatography, and combinations thereof. Chromatography is used to separate phases of a liquid. The liquid, i.e., the mobile phase, is poured or dripped through a column surface  142 , i.e., the stationary phase. The column surfaces  142  may interact with a targeted phase of the fluid  146 . As the fluid  146  flows along the column surface  142 , the targeted phase of the fluid  146  interacts with the column surface  142  and is retained by the column surface  142 , which allows the remainder of the fluid  146  to continue flowing through the column  140 . Thus, the targeted phase of the fluid  146  is separated from the remainder of the fluid  146 . Chromatography may be used by designing the column surfaces  142  to interact with the fluid  146  based on dipole-dipole interactions, ionic interactions or molecule sizes. As discussed previously, sensors  108   a - c  may be used to obtain desired information relating to the fluid and/or environment in the flow conduit  144 . 
         [0024]    For example, the column surfaces  142  may attract oil or water (e.g., lipophilic, hydrophobic, hydrophilic), cause a phase component to coalesce, and/or cause a desired flow regime. For instance, the surfaces may be a combination of hydrophilic and superhydrophobic surfaces that allow water to coalesce and then flow along a predefined channel. Similar combination of surface may be designed using oleophilic and oleophobic surfaces. In embodiments, the column surfaces  142  may be configured to operate according to HPLC (high performance liquid chromatography). HPLC is generally an automated system having fluids applied in a precise manner with controlled flow rates at high pressures. The column surfaces  142  may be a matrix of specially fabricated glass or plastic beads coated with a uniform layer of chromatographic material. HPLC allows for high speed, high resolution, and reproducibility of the separation. 
         [0025]    The column  140  may also be configured for ion exchange chromatography where oppositely charged molecules are bound to the column surfaces  142  to allow a targeted phase to be separated from the fluid  146 . For example, if the targeted phase is water to be separated from the fluid  146 , charged or ionic molecules would be bound to the column surfaces  142 . Water would bind to the ionic molecules and the remainder of the fluid  146  would flow through the column  140 . 
         [0026]    The column  140  may also be configured for hydrophobic interaction chromatography where the column surfaces  142  are impregnated with nonpolar groups. The nonpolar groups may interact with the hydrophobic phase of the fluid  146 , which causes the hydrophobic phase to bind to the column surfaces  142  and allows the charged phase to flow through the column  140 . An embodiment of this may include the oil phase being separated from the fluid  146 , so that the remainder of the fluid  146  flows through the column  140 . 
         [0027]    The column  140  may be configured for size exclusion chromatography where molecules are separated according to the size and/or shape of the molecules within the targeted phase of the fluid  146 . In this instance, the column surface  142  may have gel beads with pores of a specified size range. The pores may retain molecules of a particular wettability, size and/or shape of the fluid  146 . For example, as is known, an oil molecule is size-wise larger than a water molecule. Thus, the pores of the column surfaces  146  may be configured to be penetrable by water but relatively impenetrable by oil. Such a column surface  142  then would retain water but allow the oil to flow through the column  140 . 
         [0028]    Referring now to  FIG. 4 , there is shown a separator  160  that includes a permeable material  162  that separates a chamber  164  into a pre-separation section  166  and a post-separation section  168 . In one embodiment, the material may be a membrane  162  that has a permeability selected to allow passage of only a selected phase component (e.g., a hydrocarbon). A piston  170  or other suitable movable member reduces the volume in the pre-separation section  166  to generate a pressure differential that forces the selected phase component through the membrane  162  and into the post-separation section  168 . In other embodiments, a vacuum pump (not shown) may be used to reduce pressure in the post-separation section  168 . In other embodiments, the material  162  may be beads, or a sponge-like material. As discussed previously, sensors  108   a - c  may be used to obtain desired information relating to the fluid and/or environment in the membrane separator  160 . Other embodiments of using membrane separation may use pistons or other pressurizing mechanisms to force the fluid through a membrane which selectively filters molecules. The membrane may be porous, micro-porous, or nano-porous. 
         [0029]    It should be appreciated that the above illustrative separation techniques separate the phases without substantially affecting a structure of one or more of the substances making up the several phases. Separation processes involving pressure reduction below bubble point or cooling can cause condensate to in a liquid. However, the liquid and/or the condensate in those processes may undergo a chemical structural change that may make it difficult or impossible to acquire information relating to the fluid prior to such a separation process. The separation techniques of the present disclosure, however, retain the pre-separation structure of phase substance(s) even after separation. 
         [0030]    The teachings of the present disclosure may be used in a variety of surface and sub-surface applications. Merely for convenience, there is shown in  FIG. 5 , a tool configured to characterize a fluid that is configured for sub-surface applications.  FIG. 5  schematically illustrates a wellbore system  10  deployed from a rig  12  into a borehole  14 . While a land-based rig  12  is shown, it should be understood that the present disclosure may be applicable to offshore rigs and subsea formations. The wellbore system  10  may include a carrier  16  and a wellbore tool  20 . Merely for ease of discussion, the wellbore tool  20  is shown as a fluid analysis tool. The fluid analysis tool  20  may include a probe  22  that contacts a borehole wall  24  for extracting formation fluid from a formation  26 . Extendable pads or ribs  28  may be used to laterally thrust the probe  22  against the borehole wall  24 . The fluid analysis tool  20  may include a pump  30  that pumps formation fluid from formation  26  via the probe  22 . Formation fluid travels along a flow line to one or more sample containers  32  or to line  34  from which the formation fluid exits to the borehole  14 . The fluid may have one or more pre-existing phase components (i.e., that exist prior to separation). The tool  20  may include a separator  100  as described previously to separate one or more phase components from the fluid extracted from the formation  26 . A programmable controller may be used to control one or more aspects of the operation of the tool  20 . For example, the wellbore system  10  may include a surface controller  40  and/or a downhole controller  42 . 
         [0031]    In one mode of operation, the tool  20  is positioned downhole and operated to extract fluid from the formation  26 . The fluid from the formation (or formation fluid) may be a multi-phase fluid. Thus, the extracted fluid is conveyed to the separator tool  100 . The separator tool  100  separates at least one phase from the extracted fluid. Referring now to  FIGS. 1 and 5 , during the separation phase, the sensors  108   a,b  estimate one or more phase properties of the separated phases before the separated fluids have exited the separator tool  100 . The sensors  108   a,b  provide information about the post-separated phase(s) that may be used to characterize the properties of the phases prior to separation. 
         [0032]    At the same time, the sensors  108   c  acquire information that can be used to evaluate the environmental conditions under which the phase separation occurred. 
         [0033]    In some embodiments, the wellbore system  10  may be a drilling system that configured to form the borehole  14  using tools such as a drill bit (not shown). In such embodiments, the carrier  16  may be a coiled tube, casing, liners, drill pipe, etc. In other embodiments, the wellbore system  10  may use a non-rigid carrier. In such arrangements, the carrier  16  may be wirelines, wireline sondes, slickline sondes, e-lines, etc. 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. 
         [0034]    The controller  40 ,  42  may include an information processor that is in data communication with a data storage medium and a processor memory. The data storage medium may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical disks, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. The data storage medium may store one or more programs that when executed causes information processor to execute the disclosed method(s). Signals indicative of the parameter may be transmitted to a surface controller  40 . These signals may also, or in the alternative, be stored downhole in a data storage device and may also be processed. In one example, wired pipe may be used for transmitting information. 
         [0035]    The term “carrier” as used in this disclosure 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. As used herein, the term “fluid” and “fluids” refers to one or gasses, one or more liquids, and mixtures thereof. 
         [0036]    While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.

Summary:
An apparatus for sampling a fluid in a borehole may include a vessel configured to be disposed in a borehole and at least one sensor in communication with one phase of the plurality of phases in the vessel. The vessel separates the fluid into a plurality of phases.