Patent Publication Number: US-11649725-B2

Title: Downhole tool with filtration device

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a national stage entry of PCT/US2016/068984 filed Dec. 28, 2016, said application is expressly incorporated herein in its entirety. 
     FIELD 
     The present disclosure relates generally to filtration devices. In particular, the present disclosure relates to filtration devices for downhole tools. 
     BACKGROUND 
     Wellbores are drilled into the earth for a variety of purposes including tapping into hydrocarbon bearing formations to extract the hydrocarbons for use as fuel, lubricants, chemical production, and other purposes. The oil and gas industry typically conducts comprehensive evaluations of underground hydrocarbon reservoirs prior to wellbore development and production. Formation evaluation procedures may involve the collection of formation fluid samples for hydrocarbon content analysis. Accordingly, a variety of tools can be provided downhole for obtaining samples from a formation or other fluids in the wellbore. Exemplary tools include a Reservoir Description Tool (RDT™) by Halliburton Energy Services. The tool is able to collect, in a single deployment for example, formation pressure, fluid identification, and samples. A sealed probe is provided with the tool for isolating and extracting samples from the formation. Other tools and procedures may be provided for evaluation and collecting downhole samples. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Implementations of the present technology will now be described, by way of example only, with reference to the attached figures, wherein: 
         FIG.  1 A  is a diagram illustrating an exemplary environment for a filtration device according to the present disclosure; 
         FIG.  1 B  is a diagram illustrating another exemplary environment for a filtration device according to the present disclosure; 
         FIG.  2    is a diagram illustrating an exemplary tool incorporating a filtration device; 
         FIG.  3    is a diagram illustrating an embodiment of an exemplary filtration device; 
         FIG.  4    is a diagram illustrating another embodiment of an exemplary filtration device; and 
         FIG.  5    is a flow chart of a method for utilizing an exemplary filtration device. 
     
    
    
     DETAILED DESCRIPTION 
     It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. Also, the description is not to be considered as limiting the scope of the embodiments described herein. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features of the present disclosure. 
     In the above description, reference to up or down is made for purposes of description with “up,” “upper,” “upward,” “uphole,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” “downhole,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. Correspondingly, the transverse, axial, lateral, longitudinal, radial, etc., orientations shall mean orientations relative to the orientation of the wellbore or tool. The term “axially” means substantially along a direction of the axis of the object. If not specified, the term axially is such that it refers to the longer axis of the object. 
     Several definitions that apply throughout the above disclosure will now be presented. The term “coupled” is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to physical connections. The connection can be such that the objects are permanently connected or releasably connected. The term “outside” or “outer” refers to a region that is beyond the outermost confines of a physical object. The term “inside” or “inner” refers to a region that is within the outermost confines of a physical object. The term “substantially” is defined to be essentially conforming to the particular dimension, shape or other word that substantially modifies, such that the component need not be exact. For example, “substantially cylindrical” means that the object resembles a cylinder, but can have one or more deviations from a true cylinder. The terms “comprising,” “including” and “having” are used interchangeably in this disclosure. The terms “comprising,” “including” and “having” mean to include, but not necessarily be limited to the things so described. The term “fines” means particulates, particles, or small formation or reservoir material. The terms fines and particles may be used interchangeably herein. 
     Disclosed herein is a filtration device to be used in a downhole tool in a wellbore. When extracting fluid from a formation or within the wellbore, various fine particulates, or “fines” tend to be present in the fluid. The filtration device disclosed herein may be employed to remove the fines to obtain a cleaner fluid for testing, or to test the fines themselves. The filtration device includes an entry valve, a bypass valve, a purge valve, and an exit valve. The filtration device also includes a series of filters which have inline valves on either side of the filters. The filters can each have gradually smaller pores to catch smaller fines. As a filter becomes clogged, the inline valves can open such that the fluid bypasses the clogged filter and proceeds to the next filter in line. For example, as the pressure differential across the inline valve increases past a predetermined amount due to a clogged filter, the inline valve can open to allow the fluid to bypass that filter and proceed to the next filter in line. 
     Further, as the filters need cleaning, the filters can be reverse purged. During reverse purging, all of the valves are closed. The bypass valve and the purge valve are opened. To reverse purge each filter, the corresponding inline valves are opened such that fluid flows through the bypass valve, across an inline valve, through the filter, across the opposite inline valve, and out the purge valve to the wellbore. The process of reverse purging can occur with each individual filter as desired. 
     The filtration device may also have an entry sensor and an exit sensor. The entry sensor and exit sensor can be, for example, optical sensors or pressure sensors. The entry sensor and exit sensor can determine whether the fluid is clean or filtered to a desired level. Further, the entry sensor and exit sensor can determine whether the filters are plugged and need cleaning or replacement. For example, if the pressure differential between the entry sensor and the exit sensor is equal to or greater than a predetermined amount, the filters can be replaced or reverse purged. Further, if the exit sensor determines that the fluid is not clean or sufficiently filtered, the fluid can be routed back through the filtration device for one or more additional rounds of filtering. 
     The filtration device can be employed in an exemplary wellbore system  364  shown, for example, in  FIG.  1 A .  FIG.  1 A  shows a well during wireline logging operations. A drilling platform  386  is equipped with a derrick  388  that supports a hoist  390 . 
     Drilling oil and gas wells is commonly carried out using a string of drill pipes connected together so as to form a drilling string that is lowered through a rotary table  310  into a wellbore or borehole  312 . Here it is assumed that the drill string has been temporarily removed from the borehole  312  to allow a downhole tool  370 , such as a probe or sonde, to be lowered by conveyance  374  into the borehole  312 . A conveyance  374  can be, for example, tubing-conveyed, wireline, slickline, work string, coiled tubing, or any other suitable means for conveying downhole tools into a wellbore. Typically, the downhole tool  370  is lowered to the bottom of the region of interest and subsequently pulled upward at a substantially constant speed. 
     During, the upward trip, at a series of depths the tool movement can be paused and the tool set to pump fluids into the instruments included in the downhole tool  370  can be used to perform measurements on the subsurface geological formations  314  adjacent the borehole  312  (and the tool body  370 ). The measurement data can be communicated to a surface logging facility  392  for storage, processing, and analysis. The logging facility  392  may be provided with electronic equipment for various types of signal processing, which may be implemented by any one or more of the components of the downhole tool  370 . Similar formation evaluation data may be gathered and analyzed during drilling operations (for example, during logging while drilling (LWD) operations, and by extension, sampling while drilling). 
     The downhole tool  370  includes a filtration device  100  to filter the fluids of obstructions or fines such that accurate measurements of the fluids can be obtained. The downhole tool  370  can also include a formation testing tool for obtaining and analyzing a fluid sample from a subterranean formation through a wellbore. The formation testing tool can be, for example, a HALLIBURTON® RDT™. The formation testing tool is suspended in the wellbore by a conveyance  374  that connects the tool to a surface control unit. The formation testing tool may be deployed in the wellbore on coiled tubing, jointed drill pipe, hard wired drill pipe, or any other suitable deployment technique. 
     The formation testing tool can include a body having a control module, a fluid acquisition module, and fluid storage modules. The body can be any suitable shape, for example cylindrical. The fluid acquisition module can include an extendable fluid admitting probe and extendable tool anchors. Fluid is drawn into the downhole tool  370  through one or more probes by a fluid pumping unit. The acquired fluid then flows through one or more fluid measurement modules so that the fluid can be analyzed using the techniques described herein. Resulting data can be sent to the workstation  354  via the conveyance  374 . The fluid that has been sampled can be stored in the fluid storage modules and retrieved at the surface for further analysis. 
     The filtration device can also be employed in an exemplary wellbore system  364  shown, for example, in  FIG.  1 B . A system  364  can form a portion of a drilling rig  402  located at the surface  404  of a well  406 . The drilling rig  402  provides support for a drill string  408 . The drill string  408  can operate to penetrate a rotary table  310  for drilling a borehole  312  through subsurface formations  314 . The drill string  408  can include a Kelly  416 , drill pipe  418 , and a bottom hole assembly  420 , perhaps located at the lower portion of the drill pipe  418 . 
     The bottom hole assembly  420  includes drill collars  422 , a downhole tool  424 , and a drill bit  426 . The drill bit  426  creates a borehole  312  by penetrating the surface  404  and subsurface formations  314 . The downhole tool  424  includes a filtration device  100 . The filtration device  100  can be used for a variety of purposes including, but not limited to, protecting the pump from being plugged, assisting in the analysis of fluid, or for collection of fines for analysis of the wellbore. The downhole tool  424  can also include any of a number of different types of tools including MWD (measurement while drilling) tools, LWD tools, and others. 
     During drilling operations, the drill string  408  (which can including the Kelly  416 , the drill pipe  418 , and the bottom hole assembly  420 ) can be rotated by the rotary table  310 . In addition to, or alternatively, the bottom hole assembly  420  can also be rotated by a motor (for example, a mud motor) that is located downhole. The drill collars  422  can be used to add weight to the drill bit  426 . The drill collars  422  can also stiffen the bottom hole assembly  420 , allowing the bottom hole assembly  420  to transfer the added weight to the drill bit  426 , and in turn, assist the drill bit  426  in penetrating the surface  404  and subsurface formations  314 . 
     During drilling operations, a mud pump  432  pumps drilling fluid (sometimes known by those of skill in the art as “drilling mud”) from a mud pit  434  through a hose  436  into the drill pipe  418  and down to the drill bit  426 . The drilling fluid can flow out from the drill bit  426  and be returned to the surface  404  through an annular area  440  between the drill pipe  418  and the sides of the borehole  312 . The drilling fluid can then be returned to the mud pit  434 , where such fluid is filtered. The drilling fluid may be used to cool the drill bit  426 , as well as to provide lubrication for the drill bit  426  during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation  314  cuttings created by operating the drill bit  426 . 
     It should be noted that while  FIGS.  1 A and  1 B  generally depict a land-based operation, those skilled in the art would readily recognize that the principles described herein are equally applicable to operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. Also, even though  FIGS.  1 A and  1 B  depict a vertical wellbore, the present disclosure is equally well-suited for use in wellbores having other orientations, including horizontal wellbores, slanted wellbores, multilateral wellbores or the like. Further, the wellbore system  364  can have a casing already implemented while, in other examples, the wellbore system  364  can be used in open hole applications. 
     An exemplary downhole tool  370  which utilizes the filtration device  100  is shown in  FIG.  2   . While the disclosure is focused on the exemplary downhole tool  370  as shown in  2 , the filtration device  100  and other features of the downhole tool  370  can be implemented in other types of tools. 
     The downhole tool  370  as shown in  FIG.  2    is a modular downhole formation testing tool, which can be a HALLIBURTON® RDT™. The downhole tool  370  is made suitable for testing, retrieval and sampling along sections of the formation by means of contact with the surface of a borehole  312 . The downhole tool  370  includes several modules (sections of the downhole tool  370 ) capable of performing various functions. As shown in  FIG.  2   , the downhole tool  370  has a body  371 . The body  371  can be tubular and elongated, cylindrical, rectangular, or any suitable shape. The downhole tool  370  includes a hydraulic power module  20  that converts electrical into hydraulic power; a probe module  30  to take samples of the formation fluids; a flow control module  40  regulating the flow of various fluids in and out of the tool; a fluid test module  50  for performing different tests on a fluid sample; a multi-chamber sample collection module  60  that may contain various size chambers for storage of the collected fluid samples; a telemetry module  70  that provides electrical and data communication between the modules and a workstation  354  (shown in  FIG.  1 A ), and possibly other sections designated in  FIG.  2    collectively as  80 . The arrangement of the various modules may depend on the specific application. The order or arrangement of the modules is not restricted to the arrangement as illustrated in  FIG.  2   . 
     The power telemetry section  70  conditions power for the remaining tool sections. Each section can have its own process-control system and can function independently. While section  70  provides a common intra-tool power bus, the entire tool string (extensions beyond downhole tool  370  not shown) shares a common communication bus that is compatible with other logging tools. This arrangement enables the tool to be combined with other logging systems, such as a Magnetic Resonance Image Logging (MRIL) or High-Resolution Array Induction (HRAI) logging systems. 
     The downhole tool  370  can be conveyed in the borehole by wireline (shown in  FIG.  1 A ), which contains conductors for carrying power to the various components of the tool and conductors or cables (for example, coaxial or fiber optic cables) for providing two-way data communication between downhole tool  370  and a workstation  354  (shown in  FIG.  1 A ). The downhole tool  370  may be conveyed by tubing-conveyed, slickline, work string, coiled tubing, or any other suitable means for conveying downhole tools  370  into a wellbore  312 . The workstation  354  includes a computer and associated memory for storing programs and data. The workstation  354  generally controls the operation of downhole tool  370  and processes data received from it during operations. The workstation  354  can have a variety of associated peripherals, such as a recorder for recording data, a display for displaying desired information, printers and others. The telemetry module  70  may provide both electrical and data communication between the modules and the uphole control unit. Telemetry module  70  provides high-speed data bus from the workstation  354  to the modules to download sensor readings and upload control instructions initiating or ending various test cycles and adjusting different parameters, such as the rates at which various pumps are operating. 
     Flow control module  40  of the downhole tool  370  includes a pump  42 . The pump  42  can be a double piston pump or any suitable pump to withdraw fluid from external the body  371 . The pump  42  is in fluid communication with probes  32   a ,  32   b  and controls the formation fluid flow from the formation into flow line  15  via probes  32   a ,  32   b . The probes  32   a ,  32   b  include intake ports  33   a ,  33   b  for receiving fluid from external the body  371 . The probes  32   a ,  32   b  also include sealing pads  34   a ,  34   b  for engagement with a formation surface. The pump operation is generally monitored by the uphole workstation  354 . Fluid entering the probes  32   a ,  32   b  flows through the intake ports  33   a ,  33   b  into the flow line  15  and can be discharged into the wellbore  312  via exit port  44 . A fluid control device, such as a control valve, can be connected to flow line  15  for controlling the fluid flow from the flow line  15  into the borehole  312 . Flow line fluids can be pumped either up or down with all of the flow line fluid directed into or though pump  42 . Flow control module  40  can further accommodate strain-gauge pressure transducers that measure an inlet and outlet pump pressures. 
     The fluid testing section  50  of the tool contains a fluid testing device  52 , which analyzes the fluid flowing through flow line  15 . The fluid testing device  52  can be a device for optical analysis. For example, the fluid testing device  52  includes optical sensors. In other examples, the fluid sensors  52  can be analyte specific broadband filters, for example HALLIBURTON® ICE CORE sensors. 
     Any suitable device or devices can be utilized to analyze the fluid. Devices may be employed which include a number of sensors or quartz gauges. For example, in such gauge carriers the pressure resonator, temperature compensation, and reference crystal are packaged as a single unit. The assembly is contained in an oil bath that is hydraulically coupled with the pressure being measured. The quartz gauge enables measurement of such parameters as the drawdown pressure of fluid being withdrawn, fluid mobility and fluid temperature. Moreover, if two fluid testing devices  52  are run in tandem, the pressure difference between them can be used to determine fluid viscosity during pumping or density when flow is stopped. 
     A sample collection module  60  of the downhole tool  370  can contain various size chambers for storage of the collected fluid sample. Chamber section  60  contains at least one collection chamber, and can have a piston that divides chamber  62  into a top chamber  62   a  and a bottom chamber  62   b . A conduit is coupled to bottom chamber  62   b  to provide fluid communication between bottom chamber  62   b  and the outside environment such as the wellbore  312 . A fluid flow control device, such as an electrically controlled valve, can be placed in the conduit to selectively open the conduit to allow fluid communication between the bottom chamber  62   b  and the wellbore  312 . Similarly, chamber section  62  can also contain a fluid flow control device, such as an electrically operated control valve, which is selectively opened and closed to direct the formation fluid from the flow line  15  into the upper chamber  62   a.    
     The downhole tool  370  can also include a filtration device  100 . As shown in  FIG.  2   , the filtration device  100  is contained within the body  371  in the fluid testing section  50  and is in fluid communication with the intake ports  32   a ,  32   b . The filtration device  100  includes a particulate removing filter  1000  and filters fines and other particulates from the fluid. As such, the fines do not scatter or interfere with the analysis by the fluid testing device  52 . For example, optical sensors can be affected in quality due to scattering. Solid particles, such as fines, can make optical results difficult to calculate due to both instabilities in the light throughput and low light levels. Further, even when results may be calculated with lower confidence, results can be difficult to interpret. The filtration device  100  filters out fines to an acceptable concentration such that the quality of the results from the optical sensors is desirable. The exit port  44  is in fluid communication with the filtration device  100  and ejects the fluid to external the body  371 . 
     While the disclosure focuses on the filtration device  100  being utilized in conjunction with the fluid testing section  50 , the filtration device  100  can be utilized at any section in the downhole tool  370 . For example, the filtration device  100  can be located at the sample collection module  60 . The filtration device  100  can collect and store the fines and other particulates that are filtered out to bring uphole for analysis. In another example, the filtration device  100  can be located prior to the flow control module  40  to protect the pump  42  from being clogged with fines and potentially malfunction. 
       FIG.  3    illustrates an exemplary filtration device with filter cartridge  110 . Although in the illustrated example they are shown as filter cartridges, other suitable filter devices may be employed such as a belt or a cone screen. Each filter cartridge  110  (the plurality of filter cartridges  110  are designed herein as filter cartridges  111 ,  112 ,  113 ,  114 ,  115 ,  116 ) has at least one particulate removing filter  1000  each with a different particulate filtration size. As shown in  FIG.  3   , the filtration device  100  begins with filter  111  having a particulate removing filter  1000  with the largest pore size. Each filter cartridge having a particulate removing filter  1000  with a progressively smaller pore size until the last filter cartridge  116  having a particulate removing filter  1000  with the smallest pore size. In other words, filter  111  has the particulate removing filter  1000  with the coarsest filtration size and filter  116  has the particulate removing filter  1000  with the finest filtration size. The first filter cartridge  111  captures the largest fines, and subsequent filters captures smaller fines. The last filter cartridge  116  captures the smallest fines. Filter cartridges  112 ,  113 ,  114 , and  115  have different degrees of pore size progressing from largest pore size for filter cartridge  112  and smallest pore size for filter cartridge  115 . Alternatively, or additionally, the filter cartridges each have individual filters with different pore sizes. Filter cartridges  110  can be selected according to a typical size distribution of fines, or particles, for a drilling fluid, for example mud. The filter cartridges  110  are separated by gaps. The size of the gaps can be determined according to the relative volume of fines per size in a total volume of fluid. 
     The filtration device  100  has an entry valve  101  which permits flow of fluid from the tool to the filtration device  100  for filtration. The filtration device  100  also has an exit valve  104  which permits flow of fluid out of the filtration device  100 . Each filter cartridge  110  is inserted in a flow line  130  between two inline valves  120 . The inline valves  120  (the plurality of inline valves  120  designated here as  122   a ,  123   a ,  124   a ,  125   a ,  126   a ) can be check valves such that if the pressure drop across the inline valves  120  exceeds a predetermined amount, for example 20 psi, the inline valve  120  is opened such that the filter cartridge  110  is bypassed. As shown in  FIG.  3   , filter cartridge  111  has an inline valve  121   a  coupled to the flow line  130  on a first side of the filter cartridge  111  and an inline  121   b  coupled to a second side of the filter cartridge  111  opposite the first side. Filter cartridge  112  is inserted between inline valve  122   a  and inline valve  122   b ; filter cartridge  113  is inserted between inline valve  123   a  and inline valve  123   b ; filter cartridge  114  is inserted between inline valve  124   a  and inline valve  124   b ; filter cartridge  115  is inserted between inline valve  125   a  and inline valve  125   b ; and filter cartridge  116  is inserted between inline valve  126   a  and inline valve  126   b . The filter cartridges  110  are also connected by fluid lines  132 . Further, the filtration device  100  includes a purge valve  103  which opens up the flow line  130  to the borehole  312 . 
     When the filtration device  100  is filtering, all of the inline valves  120  and the purge valve  103  are closed. Entry valve  101 , inline valve  121   a , and inline valve  126   b  are opened. The fluid flows through the entry valve  101  and inline valve  121   a  to the filters  120 . The fluid first flows across filter  111 , passes through fluid line  132 , flows across filter cartridge  112 , and continues through the remaining filter cartridges  110 . After passing across filter cartridge  116 , the fluid flows through valve  126   b  and, if the fluid is adequately filtered, out of the filtration device  100  through exit valve  104 . If the fluid is not adequately filtered, the bypass valve  102  closes, and the fluid can pass through the bypass line  131  and re-enter the filtration device  100  through entry valve  101  for another round of filtering. 
     Further, the filtration device  100  can have a bypass line  131  which includes a bypass valve  102 . If one of the filter cartridges  110  becomes backed up or clogged, the pressure differential across the corresponding inline valve  120  increases. The inline valve  120  then opens such that the filter cartridge  110  is bypassed, and the fluid flows to the next filter cartridge  110 . For example, if filter cartridge  112  is clogged, the pressure differential across inline valve  122   a  would increase. When the pressure differential becomes greater than a predetermined value, for example 20 psi, the inline valve  122   a  would open. The fluid then does not pass across filter cartridge  112 ; instead, inline valve  123   a  opens, and the fluid passes through the flow line  130 , to the subsequent filter cartridge  113 . If filter cartridge  113  is also clogged, then the next available filter cartridge  110  will be used. As such, the filtration device  100  does not plug. 
     The filters  110  can be cleaned or regenerated such that the fines that are trapped by the filter cartridges  110  are cleared out. A method of cleaning out the filter cartridges  110  is by reverse purging. As shown in  FIG.  3   , the bypass line  131  is utilized in reverse purging. The bypass line  131  can be concentric with the filter cartridges  110 , and can be used to reverse direction of the flow through the filter mechanism in part or in whole. The bypass line  131  can be opened to reverse the direction of fluid around the entire assembly and through the last filter cartridge  110 ,  116 . Further, the bypass line  131  can be opened, along with exit valve  104 , to allow fluid to flow across the tool  100  without flowing through filter cartridges  110 . 
     The bypass line  131  can be operated electrically. Additionally, or alternatively, the bypass line  131  can be manually opened to reverse flow, or automatically as a function of the last filter cartridge  110 ,  116  moving to a bypass direction. When the bypass line  131  is opened to reverse the flow through the back side of the filter cartridges  110 , the fluid cleans the particles out of the filter cartridge  110  and directs the particles to the wellbore  312  through the purge valve  103 . When the filter cartridges  110  are sufficiently cleaned, the pressure drops across the inline valves  120 , activating the next filter cartridge  110  in series to receive the reverse fluid flow until the entire assembly is cleaned, sequentially. The last filter cartridge  110  being cleaned resets the flow back to the normal direction. 
     The sensing action to determine the opening of the inline valves  120  can be mechanical, electrical, or optical using a reverse purge sensor  163  that measures optical density at the purge valve  103 . Rather than sensing the pressure drop across the inline valves  120  when reverse purging, the cleaning sequence may be timed or manually controlled. Each of the filter cartridges  110  may be individually connected to a valve that purges fluid or particles to the wellbore  312 . 
     As illustrated in  FIG.  3   , to begin reverse purging, all of the valves may begin in a closed state. Bypass valve  102  and purge valve  103  are then opened. Reverse purging each filter cartridge  110  is accomplished by opening the respective inline valves  120  for that filter cartridge  110 . For example, to reverse purge filter cartridge  111 , inline valves  121   a ,  121   b  are opened. Fluid flows through the bypass line  131 , across the bypass valve  102 , and across inline valve  121   b  to the backside of filter cartridge  111 . The fluid, with the fines inside the filter cartridge  111 , across inline valve  121   a , through fluid line  130 , and across purge valve  103  to the wellbore  312 . As such, the filter cartridge  111  is cleaned and cleared out. Then, inline valves  121   a ,  121   b  can be closed, and inline valves  122   a ,  122   b  are opened to reverse purge filter cartridge  112 . The process can continue until the desired filter cartridges  110  are reverse purged. 
     Alternatively, or additionally, the inline valves  120  have three states. The inline valve  120  can pass the fluid through the filter cartridge  110  to the flow line  130  as a bypass for downstream filters  110 ; the inline valve  120  can bypass the filter cartridge  110  directly to the flow line  130 ; or the inline valve  120  can bypass the filter cartridge  110  and pass the fluid to the next filter cartridge  110 . As discussed above, the filter cartridges  110  can be regenerated by reversing flow through the entire series and out through a purge valve  103  to the wellbore  312 . Switching from a filter cartridge  110  to the next in line filter cartridge  110  can be an automatic process such that when the pressure drop across the filter cartridge  110  is greater than a predetermined value, for example 20 psi, a loaded spring opens as a check valve to the next filter cartridge  110 . The process can also be a manual process. 
     Further, between each inline valve  120 , and in front of the first inline valve  120 , a toggle valve may be provided to direct flow to either a bypass or the next filter cartridge  110 . The toggle valve can be controlled electrically, automatically, or manually. In automatic mode, if a sensor were to detect the absence of particles, then the toggle valve would bypass all of the filter cartridges  110 , for example by passing the fluid through the bypass line  131 . The toggle valve can be, for example, a 6 port valve, an electronic three way filter valve, or any suitable valve. 
     To determine whether the fluid is sufficiently filtered, the filtration device  100  may include an entry sensor  160  at the beginning of the filtration device  100  and an exit sensor  162  at the end of the filtration device  100 . The entry sensor  160  and the exit sensor  162  can be any suitable sensor to analyze the fluid. For example, the entry sensor  160  and the exit sensor  162  can be at least one of optical sensors, pressure sensors, vibrating tube densitometers, or capacitance sensors. The entry sensor  160  and the exit sensor  162  can communicate with the valves, for example the entry valve  101 , the bypass valve  102 , the purge valve  103 , and the exit valve  104 . For example, if the entry sensor  160  senses that the fluid coming into the filtration device  100  is sufficiently clean, the bypass valve  102  and the exit valve  104  can open and the fluid bypasses the filter cartridges  110 . If the exit sensor  162  senses that the fluid is not yet sufficiently filtered, the exit valve  104  can remain closed, and the bypass valve  102  can be opened such that the fluid flows back through the filter cartridges  110 . Further, if a large pressure differential pressure is sensed between entry valve  160  and exit valve  162 , the filter cartridges  110  may be clogged; and the filter cartridges  110  can be reverse purged or replaced. 
     If desired, the fines can be saved and provide analysis of the wellbore. The filter cartridges  110 , as filter cartridges shown in  FIG.  3   , can be replaced and saved. As shown in  FIG.  4   , the filter particulate removing filter  1000  can be laminated with film  231  into a laminated sample  240  to be analyzed at the surface. 
       FIG.  4    illustrates a roll assembly  202  where particulate removing filter  1000  that can be stored for analysis. The particulate removing filter  1000  is a belt, such that the particulate removing filter  1000  can be driven to reveal and utilize a new section of the particulate removing filter  1000 . The roll assembly  202 , as shown in  FIG.  4   , can be utilized in any suitable filtration device  100 . If multiple filters are desired, the roll assembly  202  can have multiple filters  221  aligned in a series. 
     In the roll assembly  202  of  FIG.  4   , the fluid  210  flows in the direction A. The fluid  210  flows across particulate removing filter  1000 . The particulate removing filter  1000  can be, for example, a screen or a mesh. The particulate removing filter  1000  can be a metallic screen, such as a Dutch Weave Twill screen. The particulate removing filter  1000  is contained in filter roll  220 . The filter roll  220  contains the particulate removing filter  1000  which is released or drawn out of the filter roll  220  when the fines have plugged the current section of particulate removing filter  1000 . The filter roll  220  can be a roll or spool of particulate removing filter  1000 . 
     The roll assembly  202  can also have an entry sensor  160  and an exit sensor  162 . The entry sensor  160  and the exit sensor  162  are on opposite sides of the particulate removing filter  1000  along the flow line of fluid  210 . The entry sensor  160  and the exit sensor  162  can be any suitable sensor to analyze the fluid. For example, the entry sensor  160  and the exit sensor  162  can be at least one of optical sensors, pressure sensors, vibrating tube densitometers, or capacitance sensors. If the pressure differential between the entry sensor  160  and the exit  162  sensor is equal to or greater than a predetermined amount, the particulate removing filter  1000  may be plugged. If so, the used section of the particulate removing filter  1000  is moved out of the fluid  210 , and the filter roll  220  provides new particulate removing filter  1000 . 
     The section of the particulate removing filter  1000  with fines is shifted to be laminated. On either side of the particulate removing filter  1000  are spools  230  of laminate  231  (which may be a plastic or composite). The laminate  231  seal the particulate removing filter  1000  as the particulate removing filter  1000  is shifted towards the laminated sample  240 . The laminated sample  240  then stores the particulate removing filter  1000  with the fines for later analysis. The particulate removing filter  1000  with the fines can be preserved to allow the later determination of features and properties, such as origin, mud, wear products, formation minerals, and clay. The time and length of the particulate removing filter  1000  being exposed to the fluid and fines provides a history of particulate production which can be a pre-production test to determine sanding of the formation. The information can aid in the design and deployment of production stings as well as to inform of the suitability of the kit that is needed, for example barefoot liners, slotted liners, screens, or gravel packed screens. 
     Referring to  FIG.  5   , a flowchart is presented in accordance with an example embodiment. The method  500  is provided by way of example, as there are a variety of ways to carry out the method. The method  500  described below can be carried out using the configurations illustrated in  FIGS.  1 A- 4   , for example, and various elements of these figures are referenced in explaining example method  500 . Each block shown in  FIG.  5    represents one or more processes, methods or subroutines, carried out in the example method  500 . Furthermore, the illustrated order of blocks is illustrative only and the order of the blocks can change according to the present disclosure. Additional blocks may be added or fewer blocks may be utilized, without departing from this disclosure. The example method  500  can begin at block  502 . 
     At block  502 , a downhole tool is disposed into a wellbore. The downhole tool includes a body, an intake port provided along the body, a filtration device, and an exit port. The body can be cylindrical or any other suitable shape. The intake port receives fluid from external the body and is in fluid communication with the filtration device. The filtration device is contained within the body and has a particulate removing filter. The filtration device may include multiple filter cartridges, each with different particulate removing filters having different particulate filtration sizes. Also, the filter cartridges can be arranged in series. For example, a first filter cartridge can have a particulate removing filter with the coarsest particulate filtration size and the final filter cartridge can have the finest filtration size. Each filter cartridge can have an inline valve at each end of the filter cartridge. The inline valves can be, for example, check valves such that when a pressure differential across the inline valve is equal to or greater than a predetermined amount, the inline valves open. The inline valves can also be manually or electronically opened. 
     The filtration device also includes a bypass line with a bypass valve. When the bypass valve is open, the fluid bypasses the filter cartridges. Further, the filtration device can include a purge valve which is arranged to expel fluid external the tool. The exit port is also in fluid communication with the filtration device and ejects the fluid to external the body. 
     The fluid, at block  504 , is passed through the filtration device. The fluid can be extracted from a wellbore or a formation. One or more characteristics of the fluid passing to, within, or subsequent the filtration device can be detected with a sensor. The sensor can be selected from the group consisting of optical sensors, pressure sensors, vibrating tube densitometers, capacitance sensors, or a combination thereof. The concentration of the particulate can be detected after passing the fluid through the filtration device. After the concentration of the particulate is equal to or less than a predetermined amount, the fluid, at block  506 , is ejected from the exit port. 
     If the filters are plugging or need cleaning, the filter cartridges in the filtration device can be regenerated via a reverse purge. During the reverse purge, all of the valves are closed. The bypass valve is opened such that the fluid flows through the bypass line. The inline valves for the filter cartridge to be reverse purged are open such that the fluid flows through the filter cartridge in a reverse direction, removing the fines that are plugging the filter cartridge. The purge valve is also opened such that the fluid with the purged fines is ejected external the tool through the exit port. After adequate purging, the inline valves are closed, and another set of inline valves can be opened to reverse purge another filter. Characteristics of the fluid can be detected with a sensor to determine whether the filter cartridge is adequately cleaned. 
     Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of statements are provided as follows. 
     Statement 1: A downhole tool comprising: a body; an intake port for receiving fluid from external the body; a pump in fluid communication with the intake port for withdrawing fluid through the intake port; a filtration device having a particulate removing filter, a flow line extending from the intake port to the filtration device, the filtration device being contained within the body and in fluid communication with the intake port; and an exit port in fluid communication with the filtration device for ejecting fluid to external the body. 
     Statement 2: A downhole tool is disclosed according to Statement 1, further comprising a probe which comprises the intake port, the probe having a sealing pad for engagement with a formation surface. 
     Statement 3: A downhole tool is disclosed according to Statements 1-2, the filtration device comprising: a plurality of filter cartridges, each of the plurality of filter cartridges having different particulate filtration sizes; a fluid flow path extending across the plurality of filter cartridges from a first filter cartridge to a final filter cartridge; wherein the particulate filtration sizes of the plurality of filter cartridges progress from the first filter cartridge having the coarsest particulate filtration size to the final filter cartridge having the finest particulate filtration size. 
     Statement 4: A downhole tool is disclosed according to Statement 3, wherein the plurality of filter cartridges are arranged in series. 
     Statement 5: A downhole tool is disclosed according to Statement 4, wherein there is an inline valve for each filter cartridge in the series. 
     Statement 6: A downhole tool is disclosed according to Statements 3-5, wherein the filtration device comprises a bypass line to bypass the plurality of filter cartridges. 
     Statement 7: A downhole tool is disclosed according to Statements 1-6, further comprising a sensor positioned to detect a characteristic of a fluid passing to, within or after the filtration device. 
     Statement 8: A downhole tool is disclosed according to Statement 7, wherein the sensor is selected from the group consisting of optical sensors, pressure sensors, vibrating tube densitometers, capacitance sensors, or a combination thereof. 
     Statement 9: A downhole tool is disclosed according to Statements 7 or 8, wherein the sensor is an optical sensor, and wherein the filtration device is configured to remove fines to a predetermined concentration as detected by the optical sensor. 
     Statement 10: A downhole tool is disclosed according to Statements 1-8, wherein the filtration device is configured to bypass at least one of the plurality of filter cartridge to a secondary filter cartridge of the plurality of filter cartridges when a pressure differential across the first filter cartridge reaches a predetermined level. 
     Statement 11: A downhole tool is disclosed according to Statements 1-10, wherein the filtration device comprises a purge valve arranged to expel fluid from a reverse purge flow through the filtration device to a wellbore. 
     Statement 12: A downhole tool is disclosed according to Statements 1-11, wherein the filtration device comprises a roll assembly having a filter roll, wherein fluid from the intake port is passed through a particulate removing filter drawn from the filter roll. 
     Statement 13: A method comprising: disposing a downhole tool into a wellbore, the downhole tool comprising: a body, an intake port provided along the body, a filtration device having a particulate removing filter, the filtration device being contained within the body and in fluid communication with the intake port, an exit port in fluid communication with the filtration device for ejecting fluid to external the body; passing the fluid through the filtration device; and ejecting the fluid from the exit port. 
     Statement 14: A method is disclosed according to Statement 13, further comprising: detecting a characteristic of a fluid passing to, within or subsequent the filtration device with a sensor. 
     Statement 15: A method is disclosed according to Statement 14, wherein the sensor is selected from the group consisting of optical sensors, pressure sensors, vibrating tube densitometers, capacitance sensors, or a combination thereof. 
     Statement 16: A method is disclosed according to Statements 13-15, further comprising: detecting the concentration of the particulate after passing through the filtration device. 
     Statement 17: A method is disclosed according to Statements 13-16, further comprising: regenerating the filtration device via a reverse purge. 
     Statement 18: A method is disclosed according to Statements 13-17, wherein the filtration device comprises a plurality of filter cartridges. 
     Statement 19: A method is disclosed according to Statement 18, wherein the plurality of filter cartridges are arranged in series. 
     Statement 20: A system comprising: a downhole tool disposed in a wellbore, the downhole tool comprising: a body; an intake port for receiving fluid from external the body; a pump in fluid communication with the intake port for withdrawing fluid through the intake port; a filtration device having a particulate removing filter, a flow line extending from the intake port to the filtration device, the filtration device being contained within the body and in fluid communication with the intake port; and an exit port in fluid communication with the filtration device for ejecting fluid to external the body. 
     The embodiments shown and described above are only examples. Even though numerous characteristics and advantages of the present technology have been set forth in the foregoing description, together with details of the structure and function of the present disclosure, the disclosure is illustrative only, and changes may be made in the detail, especially in matters of shape, size and arrangement of the parts within the principles of the present disclosure to the full extent indicated by the broad general meaning of the terms used in the attached claims. It will therefore be appreciated that the embodiments described above may be modified within the scope of the appended claims.