Patent Publication Number: US-11384637-B2

Title: Systems and methods for formation fluid sampling

Description:
BACKGROUND 
     Wellbores (also known as boreholes) are drilled to penetrate subterranean formations for hydrocarbon prospecting and production. During drilling operations, evaluations may be performed of the subterranean formation for various purposes, such as to locate hydrocarbon-bearing formations and to manage the production of hydrocarbons from these formations. To conduct formation evaluations, a drill string may include one or more drilling tools that test and/or sample the surrounding formation, or the drill string may be removed from the wellbore, and a wireline tool may be deployed into the wellbore to test and/or sample the formation. These drilling tools and wireline tools, as well as other wellbore tools conveyed on coiled tubing, drill pipe, casing or other conveyers, can also be referred to as “downhole tools.” 
     Formation evaluation may involve drawing fluid from the formation, also referred to as “formation fluid,” into a downhole tool for testing and/or sampling. Various devices, such as probes and/or packers, may be extended from the downhole tool to isolate a region of the wellbore wall, and thereby establish fluid communication with the subterranean formation surrounding the wellbore. Fluid may then be drawn into the downhole tool using the probe and/or packer. Within the downhole tool, the fluid may be directed to one or more fluid analyzers and sensors that may be employed to detect properties of the fluid. The properties of the fluid may be employed to determine reservoir architecture, connectivity, and compositional gradients, among others. 
     SUMMARY 
     Embodiments of the disclosure can include systems and methods for formation fluid sampling. In one embodiment, a method can include monitoring a relationship between a first characteristic of a formation fluid extracted from a formation and a second characteristic of the formation fluid extracted from the formation, determining, based at least in part on the monitoring; that a linear trend is exhibited by the relationship between the first characteristic of the formation fluid extracted from the formation and the second characteristic of the formation fluid extracted from the formation; and determining a reservoir fluid breakthrough based at least in part on the identification of the linear trend, where the reservoir fluid breakthrough is indicative of virgin reservoir fluid entering a sampling tool. 
     In another embodiment, a non-transitory computer-readable storage medium may be provided that includes computer-executable instructions that are executable by processors to cause: monitoring a relationship between a first characteristic of a formation fluid extracted from a formation and a second characteristic of the formation fluid extracted from the formation; determining, based at least in part on the monitoring, that a linear trend is exhibited by the relationship between the first characteristic of the formation fluid extracted from the formation and the second characteristic of the formation fluid extracted from the formation; and determining a reservoir fluid breakthrough based at least in part on the identification of the linear trend, where the reservoir fluid breakthrough is indicative of virgin reservoir fluid entering a sampling tool. 
     In yet another embodiment, a system may be provided that includes a formation sampling tool having a first flowline, a second flowline, and a controller. The controller may include processors and memories storing computer-executable instructions, that are executable by the processors to cause the following: monitoring a relationship between a first characteristic of a formation fluid extracted from a formation and a second characteristic of the formation fluid extracted from the formation; determining, based at least in part on the monitoring, that a linear trend is exhibited by the relationship between the first characteristic of the formation fluid extracted from the formation and the second characteristic of the formation fluid extracted from the formation; determining a reservoir fluid breakthrough based at least in part on the identification of the linear trend, where the reservoir fluid breakthrough is indicative of virgin reservoir fluid entering a sampling tool; in response to identifying the reservoir fluid breakthrough, splitting the flow of the formation fluid entering the sampling tool such that a portion of the formation fluid is directed into the first flowline and a portion of the formation fluid is directed into the second flowline; monitoring a contamination level of the formation fluid directed into the first flowline; determining that the contamination level of the formation fluid directed into the first flowline falls below a contamination threshold; and in response to determining that the contamination level of the formation fluid directed into the first flowline falls below the contamination threshold, sampling the formation fluid directed into the first flowline. 
     This summary is provided to introduce a selection of concepts in a simplified form that are further described below in the detailed description. This summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a diagram that illustrates an example drilling system in accordance with one or more embodiments. 
         FIG. 2  is a diagram that illustrates an example fluid sampling tool deployed within a well in accordance with one or more embodiments. 
         FIG. 3  is a diagram that illustrates example components of a fluid sampling tool in accordance with one or more embodiments. 
         FIG. 4  is a diagram that illustrates an example controller in accordance with one or more embodiments. 
         FIGS. 5A and 5B  are diagrams that illustrate an example fluid sampling tool in accordance with one or more embodiments. 
         FIG. 6A  is a chart diagram illustrating example multi-channel optical density data in accordance with one or more embodiments. 
         FIG. 6B  is a chart diagram illustrating example fluid density data in accordance with one or more embodiments. 
         FIGS. 7A-7E  are example cross-plot diagrams illustrating relationships between characteristics of formation fluid in accordance with one or more embodiments. 
         FIG. 8  is a flowchart that illustrates an example method for focused fluid sampling in accordance with one or more embodiments. 
     
    
    
     While the disclosure is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the disclosure to the particular form disclosed, but to the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present disclosure as defined by the appended claims. 
     DETAILED DESCRIPTION 
     The present disclosure relates to formation fluid sampling operations, including identifying a breakthrough of virgin formation fluid, and conducting post-breakthrough operations. The post-breakthrough operations may include, for example, splitting the flow of formation fluid (in a focused sampling operation), performing contamination monitoring, acquiring a sample of the formation fluid, performing a normalization procedure, performing non-focused sampling operations and/or the like. Although certain embodiments, are described in the context of focused sampling operations (e.g., including splitting the flow of formation fluid) for the purpose of illustration, similar techniques can be employed with other operations, such as non-focused sampling operations (e.g., contamination monitoring and/or sampling operations that do not employ splitting the flow of the formation fluid). In some embodiments, identifying a breakthrough of virgin formation fluid during a sampling operation includes real-time monitoring of relationships between characteristics (or properties) of the formation fluid being extracted from the formation during the sampling operation. In the case of sampling hydrocarbon-based formation fluid (e.g., oil), the characteristics may include, for example, optical density, fluid density, and/or the like. In the case of sampling water-based formation fluid (e.g., connate water), the characteristics may include, for example, resistivity (or conductivity), fluid density, optical density, and/or the like. In some embodiments, the breakthrough of virgin formation fluid can be identified based on a linear trend exhibited by the relationships between the characteristics. Thus, a sampling operation may include extracting formation fluid from a formation, monitoring relationships between characteristics of the extracted formation fluid, identifying a breakthrough of virgin formation fluid based on a linear trend exhibited by the monitored relationships, and conducting post-breakthrough operations (e.g., splitting the flow of formation fluid, performing contamination monitoring, acquiring a sample of the formation fluid, performing a normalization operation, and/or the like). 
     As noted above and discussed more fully below, the formation fluid sampling operations can be used in sampling and scanning/analyzing fluids in hydrocarbon reservoirs or water reservoirs. Such formation fluid sampling operations can be performed with downhole tools of various wellsite systems, such as drilling systems and wireline systems. Embodiments of two such systems are depicted in  FIGS. 1 and 2  by way of example. 
       FIG. 1  is a diagram that illustrates an example drilling system  10  in accordance with one or more embodiments. While certain elements of the drilling system  10  are depicted in this figure and generally discussed below, it will be appreciated that the drilling system  10  may include variations, including other components provided in addition to, or in place of, those presently illustrated and discussed. As depicted, the drilling system  10  can include a drilling rig  12  positioned over a well  14 . Although depicted as an onshore drilling system  10 , it is noted that the drilling system could instead be an offshore drilling system. The drilling rig  12  can support a drill string  16  that includes a bottomhole assembly  18  having a drill bit  20 . The drilling rig  12  can rotate the drill string  16  (and its drill bit  20 ) to drill the well  14 . 
     The drill string  16  may be suspended within the well  14  from a hook  22  of the drilling rig  12  via a swivel  24  and a kelly  26 . Although not depicted in  FIG. 1 , the skilled artisan will appreciate that the hook  22  can be connected to a hoisting system used to raise and lower the drill string  16  within the well  14 . As one example, such a hoisting system could include a crown block and a drawworks that cooperate to raise and lower a traveling block (to which the hook  22  is connected) via a hoisting line. The kelly  26  may be coupled to the drill string  16 , and the swivel  24  may allow the kelly  26  and the drill string  16  to rotate with respect to the hook  22 . A rotary table  28  on a drill floor  30  of the drilling rig  12  can be provided to grip and turn the kelly  26  to drive rotation of the drill string  16  to drill the well  14 . In some embodiments, a top drive system can be used to drive rotation of the drill string  16 . 
     During operation, drill cuttings or other debris may collect near the bottom of the well  14 . Drilling fluid  32 , also referred to as drilling mud, can be circulated through the well  14  to remove this debris. The drilling fluid  32  may also clean and cool the drill bit  20  and provide positive pressure within the well  14  to inhibit formation fluids from entering the wellbore. The drilling fluid  32  may be circulated through the well  14  by a pump  34 . The drilling fluid  32  may be pumped from a mud pit (or some other reservoir, such as a mud tank) into the drill string  16  through a supply conduit  36 , the swivel  24 , and the kelly  26 . The drilling fluid  32  may exit near the bottom of the drill string  16  (e.g., at the drill bit  20 ) and return to the surface through an annulus  38  between the wellbore and the drill string  16 . A return conduit  40  can transmit the returning drilling fluid  32  away from the well  14 . In some embodiments, the returning drilling fluid  32  can be cleansed (e.g., via one or more shale shakers, desanders, or desilters) and reused in the well  14 . 
     In addition to the drill bit  20 , the bottomhole assembly  18  can also include various instruments that measure information of interest within the well  14 . For example, as depicted in  FIG. 1 , the bottomhole assembly  18  may include a logging-while-drilling (LWD) module  44  and a measurement-while-drilling (MWD) module  46 . Both modules may include sensors, e.g., housed in drill collars, that collect data and enable the creation of measurement logs in real-time during a drilling operation. The modules may also include memory devices for storing the measured data. The LWD module  44  may include sensors that measure various characteristics of the rock and formation fluid properties within the well  14 . Data collected by the LWD module  44  can include measurements of gamma rays, resistivity, neutron porosity, formation density, sound waves, optical density, and/or the like. The MWD module  46  may include sensors that measure various characteristics of the bottomhole assembly  18  and the wellbore, such as orientation (azimuth and inclination) of the drill bit  20 , torque, shock and vibration, the weight on the drill bit  20 , downhole temperature and pressure, and/or the like. The data collected by the MWD module  46  can be used to control drilling operations. The bottomhole assembly  18  may also include one or more additional modules  48 , such as LWD modules, MWD modules, or other modules. It is noted that the bottomhole assembly  18  can be modular and, thus, the positions and presence of particular modules of the assembly may be changed as desired. Further, as discussed in greater detail below, one or more of the modules  44 ,  46 , and  48  may be or may include a fluid sampling tool configured to obtain a sample of a fluid from a subterranean formation and perform downhole fluid analysis to measure various properties of the sampled fluid, which can then be used to determine the breakthrough of a formation fluid during a sampling operation and the general characteristics of the formation  49 . 
     The bottomhole assembly  18  can also include other modules, such as a power module  50 , a steering module  52 , and/or a communication module  54 . In one embodiment, the power module  50  may include a generator (such as a turbine) driven by the flow of drilling mud through the drill string  16 . In other embodiments, the power module  50  may include other forms of power storage or generation, such as batteries or fuel cells. The steering module  52  may include a rotary-steerable system that facilitates directional drilling of the well  14 . The communication module  54  may enable communication of data (e.g., data collected by the LWD module  44  and the MWD module  46 ) between the bottomhole assembly  18  and the surface. In one embodiment, the communication module  54  communicates via mud pulse telemetry, in which the communication module  54  uses the drilling fluid  32  in the drill string  16  as a propagation medium for a pressure wave encoding the data to be transmitted. 
     The drilling system  10  may also include a monitoring and control system  56 . The monitoring and control system  56  may include one or more computer systems that enable monitoring and control of various components of the drilling system  10 . The monitoring and control system  56  may also receive data from the bottomhole assembly  18  (e.g., data from the LWD module  44 , the MWD module  46 , and the additional module  48 ) for processing and/or communication to an operator, for example. Although depicted on the drill floor  30  in  FIG. 1 , the monitoring and control system  56  can be positioned elsewhere. Further, the monitoring and control system  56  can be a distributed system with elements provided at different places near or remote from the well  14 . 
     An additional example of using a downhole tool for formation testing is depicted in  FIG. 2 .  FIG. 2  is a diagram that illustrates an example fluid sampling tool  62  deployed within a well  14  in accordance with one or more embodiments. The fluid sampling tool  62  may be suspended in the well  14  on a cable  64 . The cable  64  may be a wireline cable with at least one conductor that enables data transmission between the fluid sampling tool  62  and a monitoring and control system  66 . The cable  64  may be raised and lowered within the well  14  in any suitable manner. For instance, the cable  64  can be reeled from a drum in a service truck, which may be a logging truck having the monitoring and control system  66 . The monitoring and control system  66  may control movement of the fluid sampling tool  62  within the well  14  and/or receive data from the fluid sampling tool  62 . The monitoring and control system  66  may include one or more computer systems or devices and may be a distributed computing system, e.g., similar to that of the monitoring and control system  56  of  FIG. 1 . The received data may be stored, communicated to an operator, processed, and/or the like. Although the fluid sampling tool  62  is depicted as being deployed via a wireline, in some embodiments the fluid sampling tool  62  (or at least its functionality) may be incorporated into one or more modules of the bottomhole assembly  18 , such as the LWD module  44  or the additional module  48 . 
     The fluid sampling tool  62  may take various forms. Although depicted in  FIG. 2  as having a body including a probe module  70 , a fluid analysis module  72 , a pump module  74 , a power module  76 , and a fluid storage module  78 , the fluid sampling tool  62  may include different modules in other embodiments. The probe module  70  may include a probe  82  that can be extended (e.g., hydraulically driven) and pressed into engagement against a wall  84  of the well  14  to draw (or extract) fluid (or formation fluid) from the formation  49  into the fluid sampling tool  62  via an intake  86 . As depicted, the probe module  70  can also include one or more setting pistons  88  that may be extended outwardly to engage the wall  84  and push an end face of the probe  82  against another portion of the wall  84 . In some embodiments, the probe  82  may include a sealing element or packer that isolates the intake  86  from the rest of the wellbore. In other embodiments the fluid sampling tool  62  can include one or more inflatable packers that can be extended from the body of the fluid sampling tool  62  to circumferentially engage the wall  84  and isolate a region of the well  14  near the intake  86  from the rest of the wellbore. In such embodiments, the extendable probe  82  and the setting pistons  88  may be omitted, and the intake  86  may be provided in the body of the fluid sampling tool  62 , such as in the body of a packer module housing an extendable packer. 
     The power module  76  may provide power to electronic components of the fluid sampling tool  62 . The pump module  74  may be operated to draw formation fluid into the intake  86 , through a flowline  92 . The formation fluid may, then, be expelled into the wellbore through an outlet  94 , or directed into a storage container (e.g., a sample bottle within the fluid storage module  78 ) for transport back to the surface when the fluid sampling tool  62  is removed from the well  14 . The fluid analysis module (or fluid analyzer)  72  may include one or more sensors for measuring properties of the sampled formation fluid, such as the optical density (OD) of the formation fluid. The sensors may include, for example, optical spectrometers, fluid density sensors, resistivity sensors, viscosity sensors, nuclear magnetic resonance (NMR) sensors, dielectric sensors, ultrasonic sensors, and/or the like. In some embodiments, the fluid analysis module  72  may include a multi-channel (e.g., 20 channel) spectrometer that measures the optical density (OD) of a fluid (e.g., the sampled formation fluid) at multiple discrete wavelengths (e.g., 20 discrete wavelengths) in the visible to near-infrared (NIR) portion of the spectrum. 
     The drilling and wireline environments depicted in  FIGS. 1 and 2  are examples of environments in which a fluid sampling tool  62  may be used to facilitate retrieval and/or analysis of a downhole fluid. The presently disclosed techniques, however, can be implemented in other environments as well. For instance, the fluid sampling tool  62  may be deployed in other manners, such as by a slickline, coiled tubing, or a pipe string. Additional details on the construction and operation of the fluid sampling tool  62  may be better understood through reference to  FIG. 3 . 
       FIG. 3  is a diagram that illustrates example components of a fluid sampling tool  62  in accordance with one or more embodiments. In the illustrated embodiment, each of a probe module  70 , a fluid analysis module  72 , a pump module  74 , a power module  76 , and a fluid storage module  78  are communicatively coupled to a controller  100 . In some embodiments, the controller  100  can be employed to control operation of the modules and their respective components. The control module  100  may provide control commands that cause various components of the fluid sampling tool to perform the operations of the fluid sampling techniques described herein. For example, the controller  100  may command the probe module  70  to engage the well with the probe  82 , and the probe module  70  may, in turn, extend the probe  82  and the setting pistons  88  into contact with the wall  84  of the well  14  to facilitate sampling of a formation fluid through the wall  84  of the well  14 . The controller  100  may, for example, command the pump module  74  to generate flow through one or more flowlines of the fluid sampling tool  62 , and the pump module  74  may, in turn, operate one or more pumps to generate the flow through one or more flowlines of the fluid sampling tool  62 . The controller  100  may command the fluid analysis module  72  to acquire various measurements of a fluid flowing through the fluid sampling tool  62 , and the fluid analysis module  72  may, in turn, operate one or more sensors of the fluid analysis module to acquire the various measurements. The sensors may include, for example, optical spectrometers, fluid density sensors (e.g., densitometers), resistivity sensors, viscosity sensors, nuclear magnetic resonance (NMR) sensors, dielectric sensors, ultrasonic sensors, and/or the like. The fluid analysis module  72  may communicate the resulting measurement data to the controller  100  for use in various aspects of a sampling operation. For example, the fluid analysis module  72  may communicate resulting measurements for reservoir pressure (Pres) and temperature (T), optical density (OD), fluid density (ρ), fluid viscosity (μ), electrical resistivity or conductivity, saturation pressure, and fluorescence and/or the like for the formation fluid, to the controller  100 . The controller  100  may, in turn, use the data for determining relationships between various characteristics of the formation fluid, for determining a contamination level of the formation fluid, and/or the like. The controller  100  may also use these determined relationships to identify a reservoir fluid breakthrough (e.g., based on whether a linear relationship indicative of a reservoir fluid breakthrough is exhibited by the relationships). Further, the controller  100  may, for example, command the fluid storage module  78  to acquire one or more samples of the formation fluid, and the fluid storage module  78  may, in turn, operate a sample valve to divert at least a portion of the formation fluid flowing through the fluid sampling tool  62  into a container, such as one or more sample bottles. 
     In some embodiments, the controller  100  can be a processor-based system, such as that illustrated in  FIG. 4 .  FIG. 4  is a diagram that illustrates an example controller  100  in accordance with one or more embodiments. The controller  100  may include at least one processor  120  connected, by a bus  122 , to volatile memory  124  (e.g., random-access memory) and/or non-volatile memory  126  (e.g., flash memory and a read-only memory (ROM)). Coded application instructions  128  (e.g., software that may be executed by the processor  120  to enable the control and analysis functionality described herein) and data  130  (e.g., acquired measurements and/or the results of processing) may be stored in the non-volatile memory  126 . For example, the coded application instructions  128  can be stored in a ROM, and the data can be stored in a flash memory. The coded application instructions  128  and the data  130  may also be loaded into the volatile memory  124  or a local memory  132  of the processor  120 . The memories  124  and  126  may include one or more non-transitory computer-readable storage medium having program instructions (e.g., coded application instructions  128 ) stored thereon that are executable by one or more processors (e.g., processor  120 ) to cause various operations, including those described herein (e.g., including some or all of the operational aspects of the method  800  described in more detail below with regard to  FIG. 8 ). 
     An input/output (I/O) interface  134  of the controller  100  may enable communication between the processor  120 , the input devices  136 , and the output devices  138 . The I/O interface  134  can include any suitable device that enables such communication, such as a modem or a serial port. In some embodiments, the input devices  136  can include one or more sensing components of the fluid sampling tool  62 , such as sensors of the fluid analysis module  72 , and the output devices  138  can include displays, printers, and storage devices that allow output of data received or generated by the controller  100 . Input devices  136  and output devices  138  may be provided as part of the controller  100 , although in other embodiments such devices may be separately provided. 
     The controller  100  can be provided as part of the monitoring and control systems  56  or  66  outside of a well  14  to enable downhole fluid analysis of samples obtained by the fluid sampling tool  62 . In such embodiments, data collected by the fluid sampling tool  62  can be transmitted from the well  14  to the surface for analysis by the controller  100 . In some other embodiments, the controller  100  is provided within a downhole tool in the well  14 , such as within the fluid sampling tool  62 , or in another component of the bottomhole assembly  18 . This can enable downhole fluid analysis (DFA) to be performed within the well  14 . Further, the controller  100  may be a distributed system with some components located in a downhole tool and others provided elsewhere (e.g., at the surface of the wellsite). Whether provided within or outside the well  14 , the controller  100  can receive data collected by the sensors within the fluid sampling tool  62  and process this data to determine one or more characteristics of interest for the sampled fluid. 
       FIGS. 5A and 5B  illustrate aspects of an example fluid sampling tool  62  in accordance with one or more embodiments.  FIG. 5A  illustrates a set of tool modules of the example fluid sampling tool  62 .  FIG. 5B  is a functional diagram that illustrates an example configuration of various elements of the fluid sampling tool  62  in accordance with one or more embodiments. The fluid sampling tool  62  of  FIGS. 5A and 5B  may be, for example, a focused fluid sampling tool that can be used for focused sampling of formation fluids as described herein. 
     Referring to  FIG. 5A , the fluid sampling tool  62  may include a power module  76 , a fluid storage module  78 , a “sample” pump module  74   b , a “sample” fluid analyzer module  72   b , a probe module  70 , a “guard” fluid analysis module  72   a , and a “guard” pump module  74   b . Referring to  FIG. 5B , the fluid sampling tool  62  may include a focused sampling probe  82 , a “guard” flowline  92   a , a “guard” pump  502   a , a “guard” fluid analyzer  504   a , a “sample” flowline  92   b , a sample pump  502   b , a “sample” fluid analyzer  504   b , one or more sample bottles  506 , a sample valve  508 , and a flowline bypass valve (or seal valve)  509 . Referring to both  FIGS. 5A and 5B , the focused sampling probe  82  may be a component of the probe module  70 , the guard pump  502   a  may be a component of the guard pump module  74   b , the guard fluid analyzer  504   a  may be a component of the guard fluid analysis module  72   a , the sample pump  502   b  may be a component of the sample pump module  74   b , the sample fluid analyzer  504   b  may be a component of the sample fluid analyzer module  72   b , and the one or more sample bottles  506  and the sample valve  508  may be components of the fluid storage module  78 . The flowline bypass valve  509  may be a component of the guard or sample pump modules  74   a  and  74   b.    
     During a sampling operation, an intake  86  of the focused sampling probe  82  may be extended into engagement with the wall  84  of the well  14 . The intake  86  may include a primary inlet (or central inlet)  512  and a secondary inlet (or annular inlet)  514 . The primary inlet  512  may include a central region of the intake  86 , and the secondary inlet  514  may include the annular region surrounding the primary inlet  512 . During operation, formation fluid  520  may be drawn from a sampling zone  522  (e.g., at the wall  84  of the well  14 ) into the intake  86 . The formation fluid  520  near the center of the sampling zone  522  may be drawn into the primary inlet  512 , and the formation fluid  520  near the outside edge of the intake  86  and sampling zone  522  may be drawn into the secondary inlet  514 . In an example sampling operation, debris of mud cake  524  on or at the wall  84  may be initially drawn into the intake  86 . As pumping continues, the filtrate fluid  526  adjacent to the wall  84  may be drawn into the intake  86  and, as pumping further continues, the virgin formation fluid  528  adjacent to and behind the filtrate fluid  526  may be drawn into the intake  86 . Each of the transitions from drawing in one fluid to the next may include a period characterized by drawing in a large mixture of the respective fluids. 
     A “breakthrough” or “breakthrough time” may refer to a point in time at which the virgin formation fluid (or reservoir fluid)  528  enters the intake  86 . Thus, for example, a sampling operation may include drawing in the mud cake  524 , followed by drawing in the filtrate fluid  526 , and further followed by drawing in the virgin formation fluid  528 . The start of drawing in the virgin formation fluid  528  may be referred to as the breakthrough of the virgin formation fluid  528 . The illustrated embodiment of  FIG. 5B  depicts a point in time after breakthrough of the virgin formation fluid  528  has occurred. This is represented by the virgin formation fluid  528  already being drawn into the intake  86 . Notably, in the illustrated embodiment, the formation fluid  520  drawn into the secondary inlet  514  includes a high concentration of filtrate fluid  526 , and the formation fluid  520  drawn into the primary inlet  512  includes primarily virgin formation fluid  528  with a low concentration of filtrate. 
     The primary inlet  512  may be connected to the sample flowline  92   b . The secondary inlet  514  may be connected to the guard flowline  92   a . During operation, the sample pump  502   b  can be operated to draw formation fluid  520  into the sample flowline  92   b  via the primary inlet  512 , and/or the guard pump  502   a  can be operated to draw formation fluid  520  into the guard flowline  92   a  via the secondary inlet  514 . As discussed herein, in some configurations of the fluid sampling tool  62 , the formation fluid  520  drawn into the sample flowline  92   b  may be passed through the sample fluid analyzer  504   b , and the formation fluid  520  drawn into the guard flowline  92   a  may be passed through the guard fluid analyzer  504   a . As discussed herein, in some instances, the sample valve  508  may be operated to divert at least a portion of the formation fluid  520  into the sample bottle  506  (e.g., from the flow of formation fluid  520  flowing through the sample flowline  92   b ). As discussed herein, in some configurations of the fluid sampling tool  62 , the flowline bypass valve  509  is set in a position to block one of the flowlines (either the guard flowline  92   a  or the sample flowline  92   b ). If the guard flowline  92   a  is blocked, formation fluid  520  from both of the primary inlet  512  and the secondary inlet  514  may be pumped through the sample flowline  92   b  using the sample pump  502   b . If the sample flowline  92   b  is blocked, formation fluid  520  from both of the primary inlet  512  and the secondary inlet  514  may be pumped through the guard flowline  92   a  using the guard pump  502   a . Therefore, there may be only one pump operating in some configurations. In the split-flow configuration, the flowline bypass valve  509  can be set in the position to isolate the two flowlines  92   a  and  92   b , and the two pumps  502   a  and  502   b  are operated independently to draw formation fluid  520  from the formation  49 . For example, the flowline bypass valve  509  can be set in a position to maintain isolation between the formation fluid  520  flowing through the sample flowline  92   b  and the formation fluid  520  flowing through the guard flowline  92   a . In this configuration, the sample pump  502   b  can be operated to draw formation fluid  520  through the primary inlet  512  and the sample flowline  92   b , and the guard pump  502   a  can be operated to draw formation fluid  520  through the secondary inlet  514  and the guard flowline  92   a.    
     The fluid sampling tool  62  can be operated in different configurations. In a “commingled-down” configuration, the flowline bypass valve  509  between the guard and sample flowlines  92   a  and  92   b  may be opened, and the guard pump  502   a  may be operated. In such a configuration, the flow of the formation fluid  520  drawn through the primary inlet  512  may be mixed with the formation fluid  520  drawn through the secondary inlet  514 . Further, the mixed formation fluid  520  may be routed through the guard flowline  92   a  such that it passes through the guard fluid analyzer  504   a  before exiting the fluid sampling tool  62 . The guard fluid analyzer  504   a  may be operated to analyze and monitor the formation fluid  520  flowing through the guard flowline  92   a . The formation fluid  520  may exit the fluid sampling tool  62  (e.g., be pumped down and expelled into the wellbore) as indicated by the downward arrow  530   a  of  FIG. 5A . In this configuration, the sample pump  502   b  may not be operated. In such an instance, the sample flowline  92   b  may be blocked, and the sample fluid analyzer  504   b  may not be operated because there is no flow of formation fluid  520  through the sample flowline  92   b  to be analyzed. This configuration can be used for initial clean-up (e.g., to draw the mud cake  524  and the filtrate fluid  526  through the fluid sampling tool  62  to reach the virgin formation fluid  528 ). 
     In a “commingled-up” configuration, the flowline bypass valve  509  between the guard and sample flowlines  92   a  and  92   b  may be opened, and the sample pump  502   b  may be operated. In such a configuration, the flow of the formation fluid  520  drawn through the primary inlet  512  may be mixed with the formation fluid  520  drawn through the secondary inlet  514 . Further, the mixed formation fluid  520  may be routed through the sample flowline  92   b  such that it passes through the sample fluid analyzer  504   b  before exiting the fluid sampling tool  62 . The sample fluid analyzer  504   b  may be operated to analyze and monitor the formation fluid  520  flowing through the sample flowline  92   b . The formation fluid  520  may exit the fluid sampling tool  62  (e.g., be pumped up the wellbore) as indicated by the upward arrow  530   b  of  FIG. 5A . In this configuration, the guard pump  502   a  may not be operated. Thus, there may be no appreciable flow of formation fluid  520  through the guard flowline  92   a , and the guard fluid analyzer  504   a  may not be operated because there is no appreciable flow of formation fluid  520  through the guard flowline  92   a  to be analyzed. This configuration can also be used for initial clean-up. 
     In a “split-flow” configuration the flowline bypass valve  509  between the guard and sample flowlines  92   a  and  92   b  may be closed (e.g., to maintain isolation between the formation fluid  520  flowing in the two flowlines  92   a  and  92   b ), and both of the guard pump  502   a  and the sample pump  502   b  may be operated. In such a configuration, the flow of the formation fluid  520  drawn through the primary inlet  512  may not be mixed with the formation fluid  520  drawn through the secondary inlet  514 . The formation fluid  520  drawn through the primary inlet  512  (e.g., by operation of the sample pump  502   b ) may be routed through the sample flowline  92   b  such that it passes through the sample fluid analyzer  504   b  before exiting the fluid sampling tool  62 . The formation fluid  520  drawn through the secondary inlet  514  (e.g., by operation of the guard pump  502   a ) may be routed through the guard flowline  92   a  such that it passes through the guard fluid analyzer  504   a  before exiting the fluid sampling tool  62 . The sample fluid analyzer  504   b  may be operated to analyze and monitor the formation fluid  520  flowing through the sample flowline  92   b , and the guard fluid analyzer  504   a  may be operated to analyze and monitor the formation fluid  520  flowing through the guard flowline  92   a . The formation fluid  520  routed through the sample flowline  92   b  may exit the fluid sampling tool  62  (e.g., be pumped up the wellbore) as indicated by the upward arrow  530   b  of  FIG. 5A , and the formation fluid  520  routed through the guard flowline  92   a  may exit the fluid sampling tool  62  (e.g., be pumped down the wellbore) as indicated by the downward arrow  530   a  of  FIG. 5A . This configuration can also be used for downhole fluid analysis (DFA) (e.g., to determine whether formation fluid is sufficiently low in filtrate contamination), sampling the formation fluid (e.g., to fill the sample bottles  506  with formation fluid  520 ) and/or initial clean-up. In some instances, a cleanup process is monitored in real-time, using the fluid analyzers  504   a  and  504   b  on both flowlines  92   a  and  92   b.    
     In some embodiments, focused-sampling of the formation fluid  520  can be achieved by operating the fluid sampling tool  62  in the three configurations, in the following order: (1) a commingled-down configuration; (2) a commingled-up configuration; and (3) a split-flow configuration. Thus, in a first portion of the sampling process (or a “commingled-down” portion of the sampling process), commingled flow of the formation fluid  520  may be pumped through the guard flowline  92   a  using the guard pump  502   a  while the sample pump  502   b  is idle, as described above. In a second portion of the sampling process (or a “commingled-up” portion of the sampling process), the commingled flow of the formation fluid  520  may be altered and pumped through the sample flowline  92   b  using the sample pump  502   b  while the guard pump  502   a  is idle as described above. These two portions of the sampling process may be used for initial clean-up (e.g., to draw in and remove the mud cake  524  and the filtrate fluid  526  through the fluid sampling tool  62 , thereby enabling the virgin formation fluid  528  to be drawn into the fluid sampling tool  62 ). In a third portion of the sampling process (or “split-flow” portion of the sampling process), the flowline bypass valve  509  may be closed to maintain isolation between the two flowlines  92   a  and  92   b , and the flow of formation fluid  520  in the two flowlines  92   a  and  92   b  may be independently controlled by the two pumps  502   a  and  502   b , respectively, as described above. During this third portion of the sampling process, the sample flowline  92   b  may effectively capture the formation fluid  520  concentrated in the central area of the intake  86 , while the guard flowline  92   a  may effectively capture the formation fluid  520  concentrated around the perimeter of the intake  86 . The formation fluid  520  concentrated in the central area of the intake  86  may primarily include the virgin formation fluid  528 , and the formation fluid  520  concentrated around the perimeter of the intake  86  may include the mudcake  524 , the filtrate fluid  526  and/or the virgin formation fluid  528 . Thus, analyzing and sampling formation fluid flowing through the sample flowline  92   b  may enable a focused analysis and sampling of the virgin formation fluid  528 . 
     In some instances, the timing of transitioning from one configuration to another can be based on the characteristics of the formation fluid  520  being extracted. For example, a pre-breakthrough monitoring process may be conducted to identify a breakthrough of the virgin formation fluid  528 , and the split-flow configuration may be initiated in response to detecting, or otherwise identifying, a breakthrough of the virgin formation fluid  528 . In such an embodiment, the formation fluid  520  initially drawn into the primary inlet  512  (and through the sample flowline  92   b ) via the split-flow configuration may include a contaminated flow of virgin formation fluid  528  (e.g., virgin formation fluid  528  mixed with the mudcake  524  and/or the filtrate fluid  526 ). As pumping continues, however, the virgin formation fluid  528  may engulf the primary inlet  512  such that the formation fluid  520  drawn into the primary inlet  512  (and through the sample flowline  92   b ) includes the virgin formation fluid  528  with little to no contamination. In some embodiments, after the split-flow configuration is initiated, a post-breakthrough contamination monitoring process can be conducted on the formation fluid  520  flowing through the sample flowline  92   b  to determine if and when the contamination of the formation fluid  520  has reached a sufficient low level. Once the contamination level is determined to be sufficiently low, additional operations may be conducted, such as a sampling of the formation fluid (e.g., acquiring a sample of the formation fluid  520  in a sample bottle  506 ), a normalization procedure, and/or the like. 
     In some embodiments, a breakthrough of the virgin formation fluid  528  can be identified based on a relationship between two or more characteristics (or properties) of the formation fluid  520  exhibiting a linear trend. For example, a breakthrough of the virgin formation fluid  528  can be identified based on a determination that the relationship between optical densities (ODs) of the formation fluid  520  at two different wavelengths exhibits a linear trend over a given period. Although certain embodiments are discussed with regard to optical densities for the purpose of illustration, embodiments may include consideration of any number of and/or combination of characteristics, such as fluid density, resistivity, conductivity, and/or the like. Further, although certain embodiments are discussed with regard to sampling hydrocarbon-based virgin formation fluids (e.g., oil) for the purpose of illustration, the described embodiments may apply to sampling other formation fluids, such as water. 
     In some instances, contamination monitoring using optical measurements is based on the Beer Lambert law that establishes a linear relationship between the optical absorbance (or “optical density,” OD) and the concentrations of species under investigation. For a binary mixture of formation oil and mud filtrate, the measured OD λ  at the wavelength λ is linearly related to the contamination level by the linear mixing law:
 
OD λ =ηOD λ,fil +(1−η)OD λ,oil   (1)
 
where OD λ,fil  and OD λ,oil  are the optical densities of mud filtrate and formation oil at the wavelength λ, respectively, and η is the contamination level in the volume fraction. Assuming that η changes with respect to the pumping time or pumping volume, the values of OD λ  would reflect the changes in the contamination level of the sampled fluid in front of the optical window.
 
     By taking a particular wavelength channel as the reference channel and another channel at a different wavelength (e.g., the two channels including co-located channels of a spectrometer), the measured optical densities as a function of pumping volume (v) at these two channels can be expressed as:
 
OD i ( v )=η( v )OD i,fil +(1−η( v ))OD i,oil   (2)
 
OD ref ( v )=η( v )OD ref,fil +(1−η( v ))OD ref,oil   (3)
 
where ref and i denote the reference channel and the channel at a different wavelength, respectively. By some algebraic manipulation, one can relate these two measurements by
 
OD i ( v )= A   i   +B   i OD ref ( v )  (4)
 
where A i  and B i  are two constants, and they depend on the end points OD i,fil , OD i,oil , OD ref,fil , and OD ref,oil , then:
 
     
       
         
           
             
               
                 
                   
                     
                       A 
                       i 
                     
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                             OD 
                             
                               i 
                               , 
                               fil 
                             
                           
                           ⁢ 
                           
                             OD 
                             
                               ref 
                               , 
                               oil 
                             
                           
                         
                         - 
                         
                           
                             OD 
                             
                               i 
                               , 
                               oil 
                             
                           
                           ⁢ 
                           
                             OD 
                             
                               ref 
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                           OD 
                           
                             ref 
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                             oil 
                           
                         
                         - 
                         
                           OD 
                           
                             ref 
                             , 
                             fil 
                           
                         
                       
                     
                   
                   , 
                 
               
               
                 
                   ( 
                   5 
                   ) 
                 
               
             
             
               
                 
                   
                     B 
                     i 
                   
                   = 
                   
                     
                       
                         
                           OD 
                           
                             i 
                             , 
                             oil 
                           
                         
                         ⁢ 
                         
                           OD 
                           
                             i 
                             , 
                             fil 
                           
                         
                       
                       
                         
                           OD 
                           
                             ref 
                             , 
                             oil 
                           
                         
                         - 
                         
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                             ref 
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                             fil 
                           
                         
                       
                     
                     . 
                   
                 
               
               
                 
                   ( 
                   6 
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     Equation (4) indicates that the cross-plots of optical density data of the reference channel with the optical density data of other channels should exhibit linear trends with offset A i  and slope B i . 
     Similarly, a densimeter (e.g., a sensor for measuring fluid density) co-located with the optical spectrometer along the flowline measures the fluid density of the same binary mixture of formation oil and mud filtrate. The measured fluid density of the fluid mixture is also linearly related to the fluid density of uncontaminated formation oil (ρ oil ) and the fluid density of filtrate (ρ fil ) by:
 
ρ( v )=η( v )ρ fil +(1−η)( v ))ρ oil ,  (7)
 
where ρ(v) is the measured fluid density and η(v) is the contamination level in the volume fraction. Based on Equations (1) and (7), the following relationship between the density (p) and optical measurements (OD λ ) can be derived:
 
OD λ ( v )= A+B ρ( v )  (8)
 
where A and B are two constants defined as:
 
     
       
         
           
             
               
                 
                   A 
                   = 
                   
                     
                       
                         
                           OD 
                           
                             λ 
                             , 
                             fil 
                           
                         
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                           ρ 
                           oil 
                         
                       
                       - 
                       
                         
                           OD 
                           
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                           ρ 
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                         ρ 
                         oil 
                       
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                         fil 
                       
                     
                   
                 
               
               
                 
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                   9 
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                           OD 
                           
                             λ 
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                         - 
                         
                           OD 
                           
                             λ 
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                             fil 
                           
                         
                       
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                         ρ 
                         oil 
                       
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     Equation (4) or Equation (8), or a combination of both, can be used to identify the breakthrough of formation fluid. The breakthrough may be characterized by the apex as the mixture of formation fluid and mud filtrate reaches and enters the probe and flowline. Filtrate contamination may be further reduced with continued pumping. Equation (4) and Equation (8) represent that the cross-plots of OD channels (OD-vs-OD) or the cross-plot of OD and fluid density (OD-vs-density) will exhibit linear trends as pumping continues and filtrate contamination progressively reduces. Therefore, the breakthrough can be detected by identifying the earliest time when the linear trends are established while pumping. That is, the breakthrough can be identified to be the start of the linear trends exhibited while pumping. 
     Similar relationships can also be extended for identifying breakthrough in water sampling operations. In water sampling, the resistivity cell can be used to measure fluid resistivity along a flowline. The inverse of resistivity (conductivity) can also follow a mixing law similar to that of Equations (1) and (7): 
                       1   R     =         η   ⁡     (   v   )       ⁢     1     R   fil         +       (     1   -     η   ⁡     (   v   )         )     ⁢     1     R   wtr             ,           (   11   )               
where R is the measured resistivity by the resistivity cell, R fil  is the resistivity of invaded fluid from WBM, and R wtr  is the formation water resistivity. With the co-located resistivity cell and densimeter, the cross-plot of measured fluid conductivity and fluid density may exhibit a linear trend similar to that for hydrocarbons, and this linear trend can be used in a similar manner to identify the miscible formation water breakthrough in water sampling.
 
       FIGS. 6A, 6B and 7A-7E  may help to illustrate the cross-plotting of data and the detection of breakthrough based on the linear trends established while pumping.  FIG. 6A  is a chart diagram  600   a  illustrating example multi-channel optical density data in accordance with one or more embodiments.  FIG. 6B  is a chart diagram  600   b  illustrating example fluid density data in accordance with one or more embodiments.  FIGS. 7A-7E  are example cross-plot diagrams  700   a - 700   e  illustrating relationships between characteristics (or properties) of formation fluid in accordance with one or more embodiments. 
     Referring first to  FIGS. 6A and 6B , the charts  600   a  and  600   b  may be generated based on a set of in-situ data. These charts  600   a  and  600   b  may be displayed in a graphical user interface (GUI), for example, for viewing by an operator. The optical density chart  600   a  of  FIG. 6A  may represent a multi-channel optical density (y-axis) acquired by in-situ fluid analyzer (IFA) versus a pumped volume of formation fluid (x-axis). The optical density chart  600   a  may include a plot  602  of a determined optical density for each of a plurality of channels being monitored. Each of the plots  602  for the respective channels may represent an optical density measurement (at a different wavelength) of the formation fluid  520  being pumped through the fluid sampling tool  62  at a given time. That is, each channel, and thus each plot, may be based on an optical density measurement at a different wavelength taken by a spectrometer. Each of the channels may measure optical density at different wavelengths in the range of about 400-2000 nanometers (nm). The fluid density chart  600   b  of  FIG. 6B  may be generated based on a set of in-situ fluid density data. The fluid density chart  600   b  of  FIG. 6B  may include a fluid density plot  604  that represents the fluid density data (y-axis) versus the pumped volume of formation fluid (x-axis). The fluid density data may be acquired via a densimeter that is co-located or located nearby the spectrometer. As will be discussed in further detail below, the vertical line  606  at a volume of approximately 4000 cc may represent the point at which breakthrough occurs, and the vertical line  608  at a volume of approximately 2000 cc may represent a point shortly before breakthrough occurs. These lines may be time/volume aligned with corresponding points on the cross-plots  702   a - 702   e  of  FIGS. 7A-7E . 
     Referring now to  FIGS. 7A-7D , each of the cross-plot diagrams  700   a - 700   d  illustrate a cross-plot  702   a - 702   d  of optical density measured by a first channel versus optical density measured by a second channel across a given duration (e.g., a time or pumped volume of about 18000 cubic centimeters (cc) as indicated by the x-axis of  FIGS. 6A and 6B ). These cross-plot (e.g., cross-plots  702   a - 702   d ) may be displayed in a graphical user interface (GUI), for example, for viewing by an operator. Each point of the cross-plots  702   a - 702   d  may include an x-axis value representing an optical density (OD) at a first wavelength (e.g., measured by a first channel) at a given time (e.g., at a given pumped volume), and a y-axis value representing an optical density (OD) at a second wavelength (e.g., measured by a second channel) at the same time (e.g., at the same pumped volume). The optical density measurements may be acquired via a spectrometer with multiple wavelength channels. 
     Each of the cross-plots  702   a - 702   d  includes a first portion that does not exhibit a linear trend of any regularity (e.g., a non-linear portion  704 ) and a second portion that exhibits a linear trend (e.g., a linear portion  706 ). Notably, the linear portion  706  begins at or near a breakthrough point  708  that corresponds to a pumped volume of approximately 4000 cc (e.g., the location of the vertical line  606  in the charts  600   a  and  600   b  of  FIGS. 6A and 6B ). The linear trends exhibited by the cross-plots  702   a - 702   d  may be consistent with the linear trend predicted by Equation (4). The cross-plots  702   a - 702   d  illustrate a deviation from a linear trend at the beginning of pumping operation, which may be caused by the presence of mud cake debris, sand particles, gas bubbles, etc., in the flowline, followed by the establishment of a linear trend once the breakthrough occurs and pumping progresses. Notably, the linear trend may include a build-up trend (e.g., as illustrated by the positive sloping linear trend portion  706  of the cross-plots  702   a - 702   c  of  FIGS. 7A-7C ), or a build-down trend (e.g., as illustrated by the negative sloping linear trend portion  706  of the cross-plot  702   d  of  FIG. 7D ). 
     Referring to  FIG. 7E , the cross-plot diagram  700   e  may illustrate a cross-plot  702   e  of fluid density versus the optical density measured across a given duration (e.g., time or pumped volume of about 18000 cubic centimeters (cc)). Each point of the plot  702   e  may include an x-axis value representing an optical density (OD) at a given wavelength (e.g., measured by a channel of a spectrometer) at a given time (e.g., at a given pumped volume), and a y-axis value representing the fluid density (ρ) of the formation fluid at the same time (e.g., at the same pumped volume). Similar to the cross-plots  702   a - 702   d  of  FIGS. 7A-7D , the cross-plot  702   e  of  FIG. 7E  includes a first portion that does not exhibit a linear trend of any regularity (e.g., a non-linear portion  704 ) and a second portion that exhibits a linear trend (e.g., a linear portion  706 ). Notably, the linear portion  706  begins at or near a point that corresponds to a pumped volume of approximately 4000 (e.g., the location of the vertical line  606  in the charts  600   a  and  600   b  of  FIGS. 6A and 6B ). The linear trend exhibited by the cross-plot  702   e  is consistent with the linear trend predicted by Equation (8). Furthermore, the breakthrough detected using the cross-plot  702   e  is consistent with the breakthrough detected using the cross-plots  702   a - 702   d  shown previously. The cross-plot  702   e  illustrates a deviation from a linear trend at the beginning of the pumping operation, which may be caused by the presence of mud cake debris, sand particles, gas bubbles, etc., in the flowline, followed by the establishment of a linear trend once the breakthrough occurs and pumping progresses. Notably, the linear trend may include a build-up trend (e.g., as illustrated by a positive sloping linear trend portion  706 ), or a build-down trend (e.g., as illustrated by the negative sloping linear trend portion  706  of the cross-plot  702   e  of  FIG. 7E ). 
     In accordance with the present disclosure, the systems described can be used to perform focused sampling of formation fluid shortly after breakthrough of the formation fluid. For example, the systems described may be used to: (1) extract formation fluid through a focused sampling tool having a guard and a sample flowline; (2) conduct pre-breakthrough monitoring of the extracted formation fluid to identify if and when a breakthrough of the reservoir fluid occurs (e.g., including identifying the breakthrough based at least in part on the identification of a linear trend exhibited by a relationship between monitored characteristics (or properties) of the extracted formation fluid, such as optical density, fluid density, resistivity, conductivity, and/or the like); (3) split the flow of the extracted fluid into sample and guard flowlines at, near, or shortly after the identified breakthrough; (4) conduct post-breakthrough contamination monitoring of the extracted formation fluid flowing through the sample line to determine if and when its contamination level is sufficiently low; and/or (5) acquire a sample of the formation fluid while the contamination level is sufficiently low. 
       FIG. 8  is a flowchart that illustrates a method  800  for focused fluid sampling in accordance with one or more embodiments. The method  800  may generally include extracting formation fluid from a formation (block  802 ), conducting pre-breakthrough monitoring of the extracted formation fluid (e.g., monitoring one or more relationships between the characteristics of the extracted formation fluid) (block  804 ), determining whether one or more of the monitored relationships between characteristics (or properties) of the extracted formation fluid exhibit a linear trend (block  806 ) (e.g., based on the pre-breakthrough monitoring of the extracted formation fluid). In response to determining that the monitored relationships do not exhibit a linear trend (block  806 ), the pre-breakthrough monitoring of the extracted formation fluid (block  804 ) may continue to be performed. In response to determining that the one or more monitored relationships do exhibit a linear trend (block  806 ), however, the method  800  may proceed to identifying a formation fluid breakthrough (block  808 ) (e.g., based on the linear trend exhibited), and performing operations (or actions) consistent with a reservoir fluid breakthrough. These “post-breakthrough” operations may include, for example, splitting the flow of the extracted formation fluid in the fluid sampling tool (block  810 ) (e.g., such that portions of the flow of the extracted formation fluid are simultaneously directed through the sample flowline  92   b  and the guard flowline  92   a ), conducting post-breakthrough monitoring of the extracted formation fluid (e.g., conducting contamination monitoring of the extracted formation fluid in the sample flowline  92   b ) (block  812 ), and/or determining whether the extracted formation fluid is of a satisfactory contamination level (block  814 ) (e.g., based on the post-breakthrough monitoring of the extracted formation fluid). In response to determining that the extracted formation fluid is not of a satisfactory contamination level (block  814 ), the post-breakthrough monitoring of the extracted formation fluid (block  812 ) may continue to be performed. In response to determining that the extracted formation fluid is of a satisfactory contamination level (block  814 ) (e.g., determining that the contamination level of the extracted formation fluid flowing through the sample flow line  92   b  is at or below a threshold contamination level), the method  800  may proceed to performing additional operations (or actions) consistent with a satisfactory contamination level, such as sampling the extracted formation fluid (block  816 ). In some embodiments, some or all of the aspects of the method  800  can be performed, or otherwise controlled by, controller  100  and/or monitoring and control  66 . 
     In some embodiments, extracting formation fluid from a formation (block  802 ) can include employing a fluid sampling tool  62  to extract formation fluid from a formation. For example, referring to the fluid sampling tool of  FIGS. 5A and 5B , extracting formation fluid  520  from the formation  49  may include the probe module  70  extending the focused sampling probe  82  of the focused fluid sampling tool  62  into engagement with the wall  84  of the formation  49 , as depicted, and operating at least one of the guard and sample pumps  502   a  and  502   b  to draw the formation fluid  520  from the formation  49  and into at least one of the guard and sample flowlines  92   a  and  92   b  via the intake  86 . Extracting formation fluid  520  from the formation  49  may include continued pumping to generate a continued flow of formation fluid  520  through at least one of the guard and sample flowlines  92   a  and  92   b . Thus, extracting formation fluid  520  from the formation  49  may include generating a flow of formation fluid  520  through one or both of the guard and sample fluid analyzers  504   a  and  504   b . In some embodiments, this initial stage of formation fluid extraction includes operating the fluid sampling tool  62  in a commingled-down and/or commingled-up configuration. For example, extracting formation fluid  520  from the formation  49  may include, first, operating the fluid sampling tool  62  in a commingled-down configuration and then operating the fluid sampling tool  62  in a commingled-up configuration. In some embodiments, the fluid sampling tool  62  can be operated in the commingled-up configuration until the fluid sampling tool  62  is shifted into a split-flow configuration as a result of identifying a breakthrough of a reservoir fluid, as described below. 
     In some embodiments, conducting pre-breakthrough monitoring of the extracted formation fluid (block  804 ) includes monitoring one or more relationships between the characteristics (or properties) of the extracted formation fluid to determine whether one or more of the relationships exhibit a linear trend (block  806 ). In some embodiments, the monitored characteristics may include optical density fluid density, resistivity, conductivity and/or the like. For example, with regard to hydrocarbon sampling and, thus, monitoring the formation fluid  520  for a hydrocarbon-based reservoir fluid (e.g., oil), conducting pre-breakthrough monitoring of the extracted formation fluid  520  may include monitoring one or more relationships between an optical density of the formation fluid  520  at a first wavelength and the optical density of the formation fluid  520  at a second wavelength. Such a relationship may be established and monitored for a variety of combinations of optical density measurements at different wavelengths (e.g., as illustrated by the cross-plot diagrams  700   a - 700   d  of  FIGS. 7A-7D ). As a further example, with regard to hydrocarbon sampling (e.g., oil sampling) and, thus, monitoring the formation fluid for  520  a hydrocarbon-based reservoir fluid (e.g., oil), conducting pre-breakthrough monitoring of the extracted formation fluid  520  may include monitoring one or more relationships between the optical density of the formation fluid  520  at a given wavelength and the fluid density of the formation fluid  520  (e.g., as illustrated by the cross-plot diagram  700   e  of  FIG. 7E ). Such a relationship may be established and monitored for a variety of combinations of optical density measurements at different wavelengths and a corresponding fluid density measurement of the formation fluid  520 . 
     In some embodiments, conducting pre-breakthrough monitoring of the extracted formation fluid includes monitoring one or more relationships between the characteristics (or properties) of the extracted formation fluid in real-time to determine whether one or more of the relationships exhibit a linear trend. For example, the monitoring may include acquiring real-time downhole data from the logging tool  62 , identifying, in real-time and using the downhole data, the relationships between characteristics of the formation fluid  520  extracted from the formation  49 , and displaying or otherwise presenting, in real-time and in a graphical user interface, one or more cross-plots of the relationships between the monitored characteristics of the formation fluid  520 . Such real-time data acquisition may include sending or otherwise providing the data to a processing unit shortly after it is acquired (e.g., transmitting the data to a monitoring and control  66 , e.g., via wireline, mud-pulse telemetry and/or the like, within second or minutes after it is acquired). Such real-time presentation of the cross-plots may include displaying the cross-plots (or otherwise providing data indicative of the relationships between the characteristics) shortly after the data used to generate the cross-plots (or the relationships) is acquired (e.g., generating and displaying the cross-plots within second or minutes of the corresponding data being acquired downhole). Such real-time monitoring can enable a system or operator to make operational decisions in real-time. For example, monitoring and control  66  and/or an operator may be able to initiate a split-flow configuration of the tool  62  within seconds or minutes of a breakthrough condition based on the relationships between the characteristics being provided within seconds or minutes of acquiring downhole data that is indicative of a breakthrough condition. 
     With regard to water sampling and, thus, monitoring the formation fluid  520  for a water-based reservoir fluid (e.g., formation connate water), conducting pre-breakthrough monitoring of the extracted formation fluid  520  may include monitoring a relationship between the conductivity and the fluid density of the formation fluid  520 . As a further example, with regard to water sampling and, thus, monitoring the formation fluid  520  for a water-based reservoir fluid (e.g., formation connate water), if dye is added to the drilling mud such that dyed water from the drilling mud is mixed into the formation fluid  520 , then conducting pre-breakthrough monitoring of the extracted formation fluid  520  may include monitoring one or more relationships between an optical density of the formation fluid  520  at a first wavelength and the optical density of the formation fluid  520  at a second wavelength, and/or monitoring one or more relationships between the optical density of the formation fluid  520  at a given wavelength, the fluid density of the formation fluid  520  and/or conductivity of formation fluid  520 . 
     In some embodiments, the characteristics (or properties) of the formation fluid  520  are determined based on measurements acquired by at least one of the guard and sample fluid analyzers  504   a  and  504   b . For example, during operation of the fluid sampling tool  62  in a commingled-down configuration, the optical densities, the fluid density, and/or the resistivity (or conductivity) of the formation fluid  520  may be determined based on measurements acquired via corresponding co-located sensors of the guard fluid analyzer  504   a . During operation of the fluid sampling tool  62  in a commingled-up configuration, the optical densities, the fluid density, and/or the resistivity (or conductivity) of the formation fluid  520  may be determined based on measurements acquired via corresponding co-located sensors of the sample fluid analyzer  504   b . In some embodiments, the measurements may include optical densities for each of the wavelengths for which a relationship is established. For example, if the relationships include relationships between optical densities measured at 20 different wavelengths, then each of the guard and sample fluid analyzers  504   a  and  504   b  may have 20 channels, with each of the channels capable of acquiring a live optical density measurement at a respective one of the 20 different wavelengths. Thus, for example, each of the guard and sample fluid analyzers  504   a  and  504   b  may include 20 different spectrometer sensors, each acquiring measurements at one of the 20 different wavelengths. Further, the fluid analyzers  504   a  and  504   b  may each include a densimeter that is capable of acquiring a live fluid density measurement of the formation fluid  520 . The sensors of the fluid analyzers  504   a  and  504   b  may be co-located. For example, the spectrometer(s) and the densimeter of the sample fluid analyzer  504   b  may be co-located with one another, and the spectrometer(s) and the densimeter of the guard fluid analyzer  504   a  may be co-located with one another. Optical density channels of a sample spectrometer which examines fluid through an optical window of the sample spectrometer may be considered co-located. Other sensors, such as the density or resistivity sensors, may be co-located if they are proximate or nearby one another (e.g., within about 0-7 cm on the flowline). For example, a densimeter may be co-located with channels of a spectrometer if the densimeter is within about 7 cm of the spectrometer (e.g., they are located within about 7 cm of one another on a flowline for which they are used to measure formation fluid  520  flowing there through). Such co-location may include any relative positioning such that the measurements taken at or about the same time are taken across substantially the same formation fluid  520 . 
     In some embodiments, conducting pre-breakthrough monitoring of the extracted formation fluid  520  can include determining whether one or more of the monitored relationships exhibit a linear trend indicative of a reservoir fluid breakthrough (e.g., a breakthrough of virgin formation fluid  528  from the formation  49 ). For example, with regard to monitoring the relationships between optical densities at different wavelengths as depicted in the cross-plot diagrams  700   a - 700   d  of  FIGS. 7A-7D , and/or monitoring the relationship between optical density and fluid density of the formation fluid  520  depicted in the cross-plot diagram  700   e  of  FIG. 7E , it can be determined that each of the relationships exhibits a linear trend with regard to the plotted points following the respective breakthrough points  708   a - 708   e  of  FIGS. 7A-7E  (e.g., that correspond to the location of the vertical line  606  in the charts  600   a  and  600   b  of  FIGS. 6A and 6B  and pumped volume of approximately 4000 cubic centimeters (cc)). In some embodiments, it may be determined that the formation fluid  520  exhibits a linear trend indicative of a reservoir fluid breakthrough if at least a threshold amount (e.g., a threshold number or percentage) of the relationships being monitored are determined to exhibit a linear trend. The threshold may include, for example, at least one of the monitored relationships exhibiting a linear trend, multiple but less than all of the monitored relationships exhibiting a linear trend (e.g., 25%, 50%, or 75% of the monitored relationships exhibiting a linear trend), or all of the relationships exhibiting a linear trend (e.g., 100% of the monitored relationships). 
     In some embodiments, determining whether one or more of the monitored relationships exhibit a linear trend indicative of reservoir fluid breakthrough can include determining whether one or more of the monitored relationships exhibit a linear trend over a given duration. For example, determining whether one or more of the monitored relationships exhibit a linear trend indicative of a reservoir fluid breakthrough can include determining whether one or more of the monitored relationships exhibit a linear trend over a given length of time (e.g., over the last 2 minutes) or over a given volume of pumping (e.g., over the last 2000 cubic centimeters for formation fluid flow). In some embodiments, a linear trend can be established by performing a cure fitting or a line fitting over the specified duration. For example, a linear trend may be identified when a least-squares line fitting over the specified duration has a total error (or deviation) below a specified threshold. Such a technique may help to eliminate prematurely identifying a linear trend in the monitored relationship. The line fitting for each of the cross-plot diagrams  700   a - 700   e  of  FIGS. 7A-7E  may be represented by fit-lines  710   a - 710   e  of the respective diagrams. In some embodiments, if it is determined that the monitored relationships do not exhibit a linear trend indicative of reservoir fluid breakthrough (block  806 ), the method  800  may include continuing to conduct pre-breakthrough monitoring of the extracted formation fluid (block  804 ). In some embodiments, a linear trend may be identified, for example, by visual inspection. For example, an operator may identify a linear trend via inspection of one or more of the cross-plot diagrams  700   a - 700   e  of  FIGS. 7A-7E  (e.g., displayed in a GUI). 
     In some embodiments, identifying a reservoir fluid breakthrough can include identifying a breakthrough point that corresponds to a point at or near the start of the linear trend or trends identified. For example, with regard to the cross-plots  702   a - 702   e  of  FIGS. 7A-7E , identifying a reservoir fluid breakthrough may include identifying a breakthrough point at the pumped volume of approximately 4000 cubic centimeters (cc)—this point may correspond to the respective breakthrough points  708   a - 708   e  of the cross-plots  702   a - 702   e  (e.g., that correspond to the location of the vertical line  608  in the charts  600   a  and  600   b  of  FIGS. 6A and 6B  and pumped volume of approximately 4000 cubic centimeters (cc)). In some embodiments, if multiple linear trends are identified, the breakthrough point may be a point corresponding to an average starting point for some or all of the identified linear trends. Thus, for example, if each of the respective breakthrough points  708   a - 708   e  of  FIGS. 7A-7E  is slightly different, the breakthrough point may correspond to an average of the time and/or pumped volume corresponding to the breakthrough points  708   a - 708   e . In some embodiments, the breakthrough point may correspond to the latest or most recent breakthrough time identified for all of the cross-plots  702   a - 702   e . Thus, multiple relationships derived from measurements across multiple channels and sensors may be employed to identify a reservoir fluid breakthrough. 
     In some embodiments, splitting the flow of the extracted formation fluid in the fluid sampling tool (block  810 ) includes operating the fluid sampling tool  62  in a “split-flow” configuration. Thus, splitting the flow of the extracted formation fluid may include operating both of the guard and sample pumps  502   a  and  502   b  to generate a flow of the formation fluid  520  through both of the guard and sample flowlines  92   a  and  92   b  and, thus, through both of the guard and sample fluid analyzers  504   a  and  504   b.    
     In some embodiments, conducting post-breakthrough monitoring of the extracted formation fluid (block  812 ) includes conducting contamination monitoring of the extracted formation fluid  520  flowing through the sample flowline  92   b  to determine whether the extracted formation fluid  520  flowing through the sample flowline  92   b  is of a satisfactory contamination level (block  814 ). For example, conducting post-breakthrough monitoring of the extracted formation fluid may include determining a contamination level of the extracted formation fluid  520  flowing through the sample flowline  92   b  and comparing the contamination level to a specified threshold contamination level. In some embodiments, it may be determined that the formation fluid  520  is of a satisfactory contamination level if the contamination level is at or below the specified threshold contamination level. It may be determined that the formation fluid  520  is not of a satisfactory contamination level if the contamination level is above the specified threshold contamination level. Thus, conducting post-breakthrough monitoring of the extracted formation fluid  520  may include determining whether the contamination level of the extracted formation fluid  520  flowing through the sample flowline  92   b  is sufficiently low. In some embodiments, the contamination level may be determined based on a measured optical density of the formation fluid  520 . The contamination level of the extracted formation fluid  520  flowing through the sample flowline  92   b  may be determined to be sufficiently low if, for example, the optical density of the extracted formation fluid  520  is below a threshold level and/or has reached a stable value (or a steady state value). Although certain embodiments, are described in the context of focused sampling operations (e.g., including splitting the flow of formation fluid) for the purpose of illustration, similar techniques can be employed with other operations, such as non-focused sampling operations (e.g., contamination monitoring and/or sampling operation that do not employ a splitting the flow of formation fluid). For example, conducting post-breakthrough monitoring of the extracted formation fluid may include conducting non-focused sampling operations (e.g., including conducting contamination monitoring and/or sampling operations without splitting the flow of formation fluid). 
     In some embodiments, conducting post-breakthrough monitoring of the extracted formation fluid includes performing normalization for the extracted formation fluid. The normalization may include selecting an interval that occurs after the point of the determined formation fluid breakthrough, and conducting a normalization procedure using data or measurements corresponding to the selected interval. Such a normalization process may ensure that normalization is performed using measurements of the formation fluid  520  that are acquired post-breakthrough. The detection of breakthrough may enable identifying the time or volume interval of data (e.g., optical density data) over which the normalization procedure is applied. The normalization procedure can be part of multi-channel contamination algorithm which produces the contamination level estimate. 
     Because continued pumping in the split-flow configuration should eventually result in virgin formation fluid  528  engulfing the primary inlet  512  of the fluid sampling tool  62  as discussed above, and the post-breakthrough monitoring of the extracted formation fluid  520  may ensure that the formation fluid  520  is sufficiently free of contaminants before taking a sample, it is expected that a sample of the formation fluid  520  acquired when the contamination level is sufficiently low should include virgin formation fluid  528  that is sufficiently free of contaminants. In some embodiments, if it is determined that the formation fluid  520  is not of a satisfactory contamination level (block  814 ), the method  800  may include continuing to conduct post-breakthrough monitoring of the extracted formation fluid (block  812 ). As discussed herein, the method  800  may include, in response to determining that the contamination level is of a satisfactory level, performing additional actions consistent with a satisfactory contamination level, such as sampling the extracted formation fluid (block  816 ). 
     In some embodiments, sampling the extracted formation fluid (block  816 ) can include acquiring a physical sample of the formation fluid. For example, referring to  FIG. 5B , sampling the extracted formation fluid  520  may include opening the sample valve  508  to divert, into one or more sample bottles  506 , at least a portion of the formation fluid  520  flowing through the sample flowline  92   b . As described herein, the acquired sample of the formation fluid  520  can be returned to the surface and further analyzed to determine characteristics of the formation fluid  520 , characteristics of the virgin formation fluid  528 , characteristics of the formation  49 , characteristics of the well  14 , and/or the like. 
     It will be appreciated that the method  800  is an embodiment of a method that may be employed in accordance with the techniques described herein. The method  800  may be modified to facilitate variations of its implementation and use. The order of the method  800  and the operations provided therein may be changed, and various elements may be added, reordered, combined, omitted, modified, etc. Portions of the method  800  may be implemented in software, hardware, or a combination thereof. Some or all of the portions of the method  800  may be implemented by one or more of the processors/modules/applications. 
     Although certain embodiments relate to use of certain fluid characteristics such as optical density, fluid density, and resistivity (or conductivity) for the purpose of illustration, the techniques can be extended to any variety of fluid characteristics. For example, the sensors may include optical spectrometers, fluid density sensors, resistivity sensors, viscosity sensors, nuclear magnetic resonance (NMR) sensors, dielectric sensors, ultrasonic sensors, and/or the like. The derived fluid characteristics (or properties) may include gas-to-oil ratio (GOR), compressibility, fluid composition, saturation pressure (e.g., bubble point, dew point, asphaltene onset pressure), refractivity, thermal conductivity, heat capacity, and/or the like. The relationships may include relationships between these fluid characteristics (or properties). 
     Further modifications and alternative embodiments of various aspects of the disclosure will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative and is for the purpose of teaching those skilled in the art the general manner of carrying out the disclosure. It is to be understood that the forms of the disclosure shown and described herein are to be taken as examples of embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed or omitted, and certain features of the disclosure may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the disclosure. Changes may be made in the elements described herein without departing from the spirit and scope of the disclosure as described in the following claims. Headings used herein are for organizational purposes and are not meant to be used to limit the scope of the description. 
     As used throughout this application, the word “may” is used in a permissive sense (i.e., meaning having the potential to), rather than the mandatory sense (i.e., meaning must). The words “include,” “including,” and “includes” mean including, but not limited to. As used throughout this application, the singular forms “a”, “an,” and “the” include plural referents unless the content clearly indicates otherwise. Thus, for example, reference to “an element” may include a combination of two or more elements. As used throughout this application, the phrase “based on” does not limit the associated operation to being solely based on a particular item. Thus, for example, processing “based on” data A may include processing based at least in part on data A and based at least in part on data B unless the content clearly indicates otherwise. As used throughout this application, the term “from” does not limit the associated operation to being directly from. Thus, for example, receiving an item “from” an entity may include receiving an item directly from the entity or indirectly from the entity (e.g., via an intermediary entity). Unless specifically stated otherwise, as apparent from the discussion, it is appreciated that throughout this specification discussions utilizing terms such as “processing,” “computing,” “calculating,” “determining,” or the like refer to actions or processes of a specific apparatus, such as a special purpose computer or a similar special purpose electronic processing/computing device. In the context of this specification, a special purpose computer or a similar special purpose electronic processing/computing device is capable of manipulating or transforming signals, typically represented as physical electronic or magnetic quantities within memories, registers, or other information storage devices, transmission devices, or display devices of the special purpose computer or similar special purpose electronic processing/computing device.