Patent Document

BACKGROUND 
       [0001]    Oil wells may include multiple hydrocarbon zones (e.g., payzones, hydrocarbon zones, formation zones) that are fluidically and/or hydraulically isolated. In production, some oilfield operators prefer to use a single installation of production tubing to produce fluids from all of the zones. During the production process, using a single installation of production tubing mixes the fluids from the different payzones. However, fluids from the different zones may or may not be compatible. 
       SUMMARY 
       [0002]    This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
         [0003]    Embodiments relate to an apparatus and a method including exposing a first fluid to a pre-filter, observing the first fluid, introducing a second fluid to the first fluid, exposing the first and second fluids to a filter, and observing the first and second fluids wherein the observing the first fluid and observing the first and second fluids comprise optical measurements and the first fluid comprises material from a subterranean formation. Some embodiments may compare the optical measurements of the first fluid and the first and second fluids and/or estimate the first fluid&#39;s likelihood of forming precipitants with other fluids and/or the first fluid&#39;s asphaltene content. Embodiments relate to an apparatus and method for characterizing a fluid property including a pre-filter in communication with a fluid from a formation, an optical sensor to observe the fluid from the pre-filter, a fluid combination device in communication with the fluid and a second fluid source, a filter in communication with the combination device, a second optical sensor to observe a third fluid from the filter, and a processor to compare data collected by the sensor and second sensor. 
     
    
     
       FIGURES 
         [0004]    Embodiments of systems and methods of determining parameter values in a downhole environment are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components. 
           [0005]      FIG. 1  illustrates an example system in which embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones can be implemented. 
           [0006]      FIG. 2  illustrates another example system in which embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones can be implemented. 
           [0007]      FIG. 3  illustrates another example system in which embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones can be implemented. 
           [0008]      FIG. 4  illustrates various components of an example apparatus that can implement embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones. 
           [0009]      FIG. 5  illustrates another example apparatus that can implement embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones. 
           [0010]      FIG. 6  illustrates an example apparatus that can implement embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones. 
           [0011]      FIG. 7  illustrates an example method for determining commingling compatibility of fluids from different formation zones. 
           [0012]      FIG. 8  is an example plot obtained using the examples disclosed herein. 
           [0013]      FIG. 9  illustrates an example mixer that can be used to implement the examples described herein. 
           [0014]      FIGS. 10 and 11  illustrate an example filter that can be used to implement the examples described herein. 
           [0015]      FIG. 12  illustrates various components of an example apparatus that can implement embodiments of the systems and methods for determining commingling compatibility of fluids from different formation zones. 
           [0016]      FIG. 13  is a schematic illustration of an example processor platform that may be used and/or programmed to implement any or all of the example systems and methods disclosed herein. 
       
    
    
     DETAILED DESCRIPTION 
       [0017]    In the following detailed description of the preferred embodiments, reference is made to the accompanying drawings, which form a part hereof, and within which are shown by way of illustration specific embodiments by which the examples described herein may be practiced. It is to be understood that other embodiments may be utilized and structural changes may be made without departing from the scope of the disclosure. 
         [0018]    The examples disclosed herein relate to downhole methods and systems that enable the determination of asphaltene content of a fluid sample(s) downhole and/or whether live crude oils from different production zones can be commingled during oil well production. More generally, the examples disclosed herein determine downhole the stability of mixing crude oils in an open hole and/or cased hole sampling operation. The methods and systems disclosed herein may be implemented in downhole tools and/or wireline-conveyed tools such as the MDT Modular Formation Dynamics Tester (which is commercially available from the Schlumberger Technology Corporation of Sugar Land, Tex.). 
         [0019]    The examples disclosed herein may be used to determine a characteristic of a fluid sample (e.g., crude oil) downhole by mixing it with another substance. The characteristic may be an amount of asphaltenes of the fluid sample and the other substance may be heptane, pentane, etc. The fluid sample may be obtained from the adjacent borehole and stored (e.g., temporarily stored) in a sample chamber at a given temperature and/or pressure. The temperature at which the sample is stored may be the temperature of the borehole and/or a temperature that is higher than the borehole temperature due to electronics of the downhole tool. 
         [0020]    To determine a first optical density value(s) of the fluid sample, a portion of the fluid sample is pumped through a flowline and past one or more optical sensors. The optical sensors or detectors may obtain optical density values of the fluid samples at a series of pre-defined wavelengths. The optical path may be relatively short to ensure that the fluid sample does not appear opaque to the optical sensors. The portion of the fluid sample from which the first optical density values(s) is obtained may then be pumped through the example apparatus and out to the borehole. 
         [0021]    To cause asphaltenes to precipitate from the rest of the fluid sample (e.g., maltenes), heptane stored in a chamber of the downhole tool is brought to a substantially identical pressure as the fluid sample and then simultaneously pumped into a flowline into which the fluid sample is also being pumped. The heptane may be pumped into the flowline at a first flowrate and the fluid sample may be pumped into the flowline at a second flowrate such that a mixing ratio of the fluids is obtained and/or achieved (e.g., 40:1 mixing ratio). Prior to its usage, the heptane may be stored in a separate chamber that is filled prior to the downhole tool being deployed downhole. 
         [0022]    To efficiently mix the heptane and the fluid sample, the mixed fluids may be directed through a passive mixer. The passive mixer may include a torturous flowpath that maximizes the mixing efficiency between the heptane and the fluid sample (e.g., the crude oil). To filter any asphaltenes that may have flocculated from the mixture, the mixed fluids are directed through a filter and/or membrane that has sufficiently small pores (e.g., 0.435 microns) to substantially prevent the passage of flocculated asphaltenes, but enables the remainder of the mixed fluids to pass therethrough. 
         [0023]    After passing through the filter, a second optical density value of the mixed fluids may be obtained. To determine an amount of asphaltenes flocculated from the fluid sample, the first optical density value may be compared to the second optical density value. If the first and second optical density values are substantially the same, no significant flocculation of asphaltenes took place. However, if there is a difference between the first and second optical densities values, at least some light-absorbing or light-scattering asphaltenes were filtered out by the filter. To determine an amount of asphaltenes contained in the live fluid sample, a difference between the first and second optical density values may be interpreted using methods described in U.S. patent application Ser. No. 12/790,927, filed May 31, 2010, which is hereby incorporated herein by reference in its entirety. 
         [0024]    In some examples, asphaltenes filtered out by the filter may be removed by flushing the filter, flowline(s) and/or system with toluene or other solvent (e.g., a similar solvent). The toluene may be pumped through the example apparatus and out to the borehole after flushing the filter, flowline(s) and/or system. Prior to its usage, the toluene may be stored in a separate chamber that is filled prior to the downhole tool being deployed downhole. 
         [0025]    To determine whether or not two or more fluid samples (e.g., crude oils) can be commingled without significant asphaltene flocculation, the fluid samples may be mixed and filtered in a manner as described above. The fluid samples may be mixed at any desired mixing ratio such as 1:1; 4:1, etc. In some examples, the mixing ratio selected corresponds to the production rate of first and second production zones from which the corresponding first and second fluid samples are obtained. For example, the fluid samples may be mixed at a ratio of 4:1 if the crude oil from a first production zone is to be produced at an anticipated rate of 4 times higher than crude oil from a second production zone. Flowing the fluid samples at different flow rates may be beneficial when asphaltenes have different extinction coefficients. 
         [0026]    The examples disclosed herein may obtain and store live fluid samples that are from different production zones and which are to be analyzed and/or tested downhole. In some examples, a plurality of first sample chambers (e.g., six chambers) into which fluid samples are to be stored may be selectively coupled to a first pump (e.g., a micropiston) and a plurality of second sample chambers (e.g., six chambers) into which fluid samples are to be stored may be selectively coupled to a second pump (e.g., a micropiston). The fluid sample(s) may flow and/or be pumped through a membrane that substantially removes water and/or particulate from the fluid(s) to be stored in a respective sample chamber (e.g., the piston bore). The examples disclosed herein enable stored fluid samples (e.g., samples having high asphaltene content) to remain stable with respect to temperature variations when moving the tool to different formation zones by enabling the fluid samples to be stored at or above a particular pressure (e.g., above reservoir pressure, an overpressure, a pressure that increases with depth and/or temperature, etc.). 
         [0027]    Prior to mixing the samples, a sensor(s) and/or an optical cell(s) (e.g., a microfluidic optical sensor) may independently determine a first optical density value at a predetermined wavelength for a portion of a first downhole fluid sample and a second optical density value at a predetermined wavelength for a portion of a second downhole fluid sample. The fluid samples may be mixed by independently pumping the fluid samples from the respective sample chambers at a controlled flow rate(s) (e.g., substantially equal volumetric flow rates) toward, for example, a flowline having a mixer and/or a filter. While two fluid samples are described as being mixed, any other number (e.g., 3, 4, etc.) of fluid samples may be mixed instead. The mixer may be an active, static and/or passive mixer that includes a torturous flowpath that accelerates the rate at which the fluid samples mix. The filter may be a dead-end filter that substantially blocks the passage of flocculated asphaltenes. In some examples, the filter is a cross flow filter that is positioned sideways (e.g., at a non-perpendicular position relative to a longitudinal axis of the flowline) within the flowline. 
         [0028]    In some embodiments, the cross-flow filter wicks fluid slowly from the main tool flowline and conveys the filtered fluid to the microfluidic capillary flowlines. The filters that are in the small microfluidic lines need to be dead-end filters, where the fluid flow is perpendicular to the membrane surface and all fluid goes through the membrane (but not particulates). 
         [0029]    In some examples, to simulate the mixed fluids flowing through production tubing to the surface, the pressure of the fluid samples may be decreased from the storage pressure prior to mixing and/or the temperature of the flowline through which the fluid samples are to flow may be decreased prior to mixing the fluid samples using, for example, a Peltier cooler. While the above example describes mixing different fluid samples, in other examples, to determine an amount of asphaltenes present in a fluid sample (e.g., a first fluid sample), the fluid sample may be mixed with a substance (e.g., heptane) and thereafter analyzed. The heptane may be mixed with the crude oil sample at a 40:1 mixing ratio. 
         [0030]    To determine if and/or an amount of asphaltenes that may have flocculated when mixing the fluid samples, a sensor(s) and/or an optical cell(s) (e.g., a microfluidic optical sensor) may determine a third optical density value at a predetermined wavelength for the mixed fluid samples. The first and second optical density values may be averaged to generate an averaged optical density value and the averaged optical density value may be compared to the third optical density value. In some examples, a difference between the third optical density value and the averaged optical density value corresponds to the optical spectrum of the asphaltenes in the mixed fluid samples. The asphaltene content of the fluid samples can be determined using a calibration curve, the optical density difference and/or a coefficient of determination (R 2 ). If the third optical density value is less than the averaged optical density value, asphaltenes have flocculated from the mixed fluid samples and have been filtered out of the mixed fluid samples by the filter. If the third optical density value is substantially similar to the averaged optical density value, substantially no asphaltenes have flocculated from the mixed fluid samples. In some examples, after the commingling analysis is complete, toluene is pumped through the filter to substantially remove any asphaltenes that may be trapped therein. 
         [0031]    To probe and/or determine the kinetics of the asphaltene flocculation process, an amount of time between mixing the fluid samples and the time of measurement (e.g., when the optical density value of the sample(s) is determined) may be varied. The kinetics of the asphaltene flocculation process may be used to determine and/or provide an indicator of the stability of the commingled solution. In some examples, the kinetics of the asphaltene flocculation process can be probed and/or determined by varying the flow rate of the fluid samples. 
         [0032]    For example, to determine the commingling compatibility of two fluid samples at a mixing ratio of 1:1, the volumetric flow rates of the fluid samples may be set to be substantially identical. In a first test, the flow rate of the fluid samples may be 0.1 microliters/second such that 100 seconds pass between when the fluid samples contact one another and when the mixed fluids pass through the filter and/or membrane. In a second test, the flow rate of the fluid samples may be 1.0 microliters/second such that 10 seconds pass between when the fluid samples contact one another and when the mixed fluids pass through the filter and/or membrane. In a third test, the flow rate of the fluid samples may be 10 microliters/second such that 1 second passes between when the fluid samples contact one another and when the mixed fluids pass through the filter and/or membrane. For each of the tests, the optical density of the fluid samples and the mixture after passing through the filter are measured. In some embodiments, the optical measurements may include optical density and/or fluorescence. 
         [0033]    If the optical density values of the mixtures are substantially the same for each of the tests, the asphaltenes flocculated very quickly, which indicates that the commingled fluid is not very stable. However, if substantially more asphaltenes flocculated at the 100 second measurement than at the 1 second measurement, then the commingled fluid is slightly more stable. 
         [0034]    While the above examples describe determining an optical density value of the fluid samples, a fluorescence value may alternatively or additionally be obtained. 
         [0035]      FIG. 1  depicts an example wireline tool  151  that may be an environment in which aspects of the present disclosure may be implemented. The example wireline tool  151  is suspended in a wellbore  152  from the lower end of a multiconductor cable  154  that is spooled on a winch (not shown) at the Earth&#39;s surface. At the surface, the cable  154  is communicatively coupled to an electronics and processing system  156 . The example wireline tool  151  includes an elongated body  158  that includes a formation tester  164  having a selectively extendable probe assembly  166  and a selectively extendable tool anchoring member  168  that are arranged on opposite sides of the elongated body  158 . Additional components (e.g.,  160 ) may also be included in the wireline tool  151 . 
         [0036]    The extendable probe assembly  166  may be configured to selectively seal off or isolate selected portions of the wall of the wellbore  152  to fluidly couple to an adjacent formation F and/or to draw fluid samples from the formation F. Accordingly, the extendable probe assembly  166  may be provided with a probe having an embedded plate. The formation fluid may be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers  176  and  178 . The example wireline tool  151  also includes an example apparatus  180  that may be used to determine the compatibility of fluids (e.g., water), formation fluids obtained from different production zones and/or to determine an asphaltene content of formation fluid downhole, for example. As discussed in more detail below, the apparatus  180  may include one or more pumps, sample storage chambers (e.g.,  176 ,  178 ), flowlines, sensors, mixers, filters, membranes, etc., that are used to determine fluid compatibility and/or if and/or an amount of asphaltenes that have flocculated from the fluid samples, once mixed. The amount of asphaltenes that flocculate from the mixed fluid samples is indicative of the compatibility and/or stability of crude oils from different production zones. The determined amount of asphaltenes that have flocculated from the mixed fluid samples may be none, some or a particular amount (e.g., a weight percent). In the illustrated example, the electronics and processing system  156  and/or a downhole control system are configured to control the extendable probe assembly  166 , the apparatus  180  and/or the drawing of a fluid sample from the formation F. 
         [0037]      FIG. 2  illustrates a wellsite system in which the examples described herein can be employed. The wellsite can be onshore or offshore. In this example system, a borehole  11  is formed in subsurface formations by rotary drilling in a manner that is well known. However, the examples described herein can also use directional drilling, as will be described hereinafter. 
         [0038]    A drill string  12  is suspended within the borehole  11  and has a bottom hole assembly  100  which includes a drill bit  105  at its lower end. The surface system includes a platform and derrick assembly  10  positioned over the borehole  11 . The assembly  10  includes a rotary table  16 , a kelly  17 , a hook  18  and a rotary swivel  19 . The drill string  12  is rotated by the rotary table  16  and energized by means not shown, which engages the kelly  17  at the upper end of the drill string  12 . The drill string  12  is suspended from the hook  18 , attached to a traveling block (also not shown), through the kelly  17  and the rotary swivel  19 , which permits rotation of the drill string  12  relative to the hook  18 . As is well known, a top drive system could alternatively be used. 
         [0039]    In this example, the surface system further includes drilling fluid or mud  26  stored in a pit  27  formed at the well site. A pump  29  delivers the drilling fluid  26  to the interior of the drill string  12  via a port in the swivel  19 , causing the drilling fluid  26  to flow downwardly through the drill string  12  as indicated by the directional arrow  8 . The drilling fluid  26  exits the drill string  12  via ports in the drill bit  105 , and then circulates upwardly through the annulus region between the outside of the drill string  12  and the wall of the borehole  11 , as indicated by the directional arrows  9 . In this manner, the drilling fluid  26  lubricates the drill bit  105  and carries formation cuttings up to the surface as it is returned to the pit  27  for recirculation. 
         [0040]    The bottom hole assembly  100  includes a logging-while-drilling (LWD) module  120 , a measuring-while-drilling (MWD) module  130 , a roto-steerable system and motor  150 , and the drill bit  105 . 
         [0041]    The LWD module  120  is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g., as represented at  120 A. (References, throughout, to a module at the position of  120  can alternatively mean a module at the position of  120 A as well.) The LWD module includes capabilities for measuring, processing and storing information, as well as for communicating with the surface equipment. In this example, the LWD module  120  includes a fluid sampling device. 
         [0042]    The MWD module  130  is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power for the downhole system. This may include a mud turbine generator powered by the flow of the drilling fluid  26 . However, other power and/or battery systems may be employed. In this example, the MWD module  130  includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. 
         [0043]      FIG. 3  is a simplified diagram of a sampling-while-drilling logging device of a type described in U.S. Pat. No. 7,114,562, incorporated herein by reference, utilized as the LWD module  120  or part of a LWD tool suite  120 A. The LWD module  120  is provided with a probe  6  for establishing fluid communication with a formation F and drawing the fluid  21  into the tool, as indicated by the arrows. The probe  6  may be positioned in a stabilizer blade  23  of the LWD module  120  and extended therefrom to engage a borehole wall  24 . The stabilizer blade  23  comprises one or more blades that are in contact with the borehole wall  24 . Fluid drawn into the downhole tool using the probe  6  may be measured to determine, for example, pretest and/or pressure parameters. Additionally, the LWD module  120  may be provided with devices, such as sample chambers, for collecting fluid samples for retrieval at the surface. Backup pistons  81  may also be provided to assist in applying force to push the drilling tool and/or probe against the borehole wall  24 . 
         [0044]      FIG. 4  depicts an example apparatus  400  that may be used to determine the compatibility of formation fluids obtained from different production zones. The apparatus  400  includes first through third flowlines  402 - 406  that are fluidly coupled to a bypass flowline  408 . To urge fluid to flow from the bypass flowline  408  through a membrane  410 , the bypass flowline  408  includes an adjustable back pressure regulator  412  that enables an upstream pressure to be greater (e.g., 20 psi greater) than a downstream pressure. The membrane  410  is positioned adjacent the bypass flowline  408  and wicks particulate-free and/or water-free fluid from the bypass flowline  408  for downhole testing and/or analysis. This membrane  410  is an example of cross-flow filtration in some embodiments. 
         [0045]    The apparatus  400  also includes a first sample storage chamber and pump  414  and a second sample storage chamber and pump  416 . First, second and third fluid control devices (e.g., valves)  417 ,  418  and/or  420  control fluid flow relative to the respective storage chambers and pumps  414  and  416 . In this example, the sample storage chambers and pumps  414  and  416  include pistons (e.g., motorized micropistons)  422 ,  424  and first and second chambers (e.g., piston bores)  426 ,  428 . When the pistons  422 ,  422  retract, fluid can be pumped into and retained in the respective chambers  426 ,  428 . However, any other configuration of pumps and/or storage chambers may be used instead. 
         [0046]    Prior to obtaining and/or storing a first sample, fluid may be pumped through the first flowline  402  and analyzed and/or tested for quality and/or other parameters (e.g., optical density). Once it is determined to obtain the first sample, the apparatus  400  is positioned in the borehole adjacent a first formation zone and fluid is extracted from the first formation zone. The extracted fluid flows through the bypass flowline  408 , the membrane  410  and the flowlines  402  and  404  to the first chamber  426 . When obtaining the first sample, the first and second valves  417  and  418  are in the open position, the third valve  420  is in a closed position and a fourth valve  430  is in a position to direct fluid flow back to the bypass flowline  408 . Once obtained, the first sample may be held in the first chamber  426  at a particular pressure (e.g., an overpressure, etc.). 
         [0047]    Prior to obtaining and/or storing a second sample, fluid may be pumped through the first flowline  402  and analyzed and/or tested for quality and/or other parameters (e.g., optical density). Once it is determined to obtain the second sample, the apparatus  400  is positioned adjacent a second formation zone and fluid is extracted from the second formation zone. The extracted fluid flows through the bypass flowline  408 , the membrane  410  and the flowlines  402  and  406  to the second chamber  428 . When obtaining the second sample, the first and third valves  417 ,  420  are in the open position, the fourth valve  430  is in the position to direct fluid flow back to the bypass flowline  408  and the second valve  418  is in the closed position. Once obtained, the second sample may be held in the second chamber  428  at a particular pressure (e.g., an overpressure, etc.). 
         [0048]    To determine a first value of a parameter for the first sample, with the first and third valves  417 ,  420  in the closed position and the fourth valve  430  directing fluid flow back to the bypass flowline  408 , the second valve  418  is opened and the piston  422  pumps and/or urges a portion of the first sample from the first chamber  426  through the second flowline  404  and through and/or adjacent to a sensor  432 . The sensor  432  then determines a first value of a parameter and/or optical density value for the first sample. 
         [0049]    To determine a second value of the parameter for the second sample, with the first and second valves  417 ,  418  in the closed position and the fourth valve  430  directing fluid flow back to the bypass flowline  408 , the third valve  420  is opened and the pump  424  pumps and/or urges a portion of the second sample from the second chamber  428  through the third flowline  406  and toward the sensor  432 . The sensor  432  may be an optical density sensor that determines a second value of a parameter and/or optical density value for the second sample. 
         [0050]    With the optical densities of the first and second samples obtained, the first valve  417  in the closed position and the fourth valve  430  directing fluid flow toward a mixer  435 , the respective pistons  422  and  424  pump and/or urge a portion of the first and second samples from the chambers  426 ,  428  through the flowlines  404 ,  406  and/or  402  and toward the mixer  435 . The pistons  422  and  424  may selectively and simultaneously pump the first and second samples at the same, similar or different flowrates. The mixer  435  may be an active and/or passive mixer including a torturous flowpath that accelerates the rate at which the samples mix. Mixing the samples may cause asphaltenes to flocculate from the mixture. 
         [0051]    In this example, a filter  436  is positioned within the flowpath of the mixer  435 . The filter  436  is configured to substantially prevent flocculated asphaltenes from flowing therethrough. After the mixed fluids have passed through the filter  436 , the mixed fluid samples are directed through and/or adjacent to a second sensor  438 , through a check valve  440  and back to the bypass flowline  408 . The second sensor  438  may be an optical density sensor that determines a third value of a parameter and/or optical density value of the mixed samples. 
         [0052]    To determine if and/or an amount of asphaltenes that may have flocculated when mixing the fluid samples, a processor  442  may average the first and second optical density values to generate an average optical density value. The processor  442  may then compare the average optical density value to the third optical density value. If the third optical density value is less and/or different than the average optical density value, asphaltenes have flocculated from the mixed fluid samples and, thus, the fluid samples may not be compatible. If the third optical density value is substantially similar to the average optical density value, substantially no asphaltenes have flocculated from the mixed fluid samples and, thus, the fluid samples may be compatible. 
         [0053]    In other examples, the example apparatus  400  can be used to measure asphaltene content of one or more fluids. In such examples, the apparatus  400  may be deployed downhole with one of the chambers  426  or  428  empty and the other of the chambers  426  or  428  filled with, for example, heptane. The initially empty chamber  426  or  428  is used to store (e.g., temporarily store) a fluid sample, once obtained, from a formation zone. 
         [0054]    The asphaltene content of the obtained fluid sample may be determined by measuring a first optical density value of the fluid sample using the sensor  432 , mixing the fluid sample and the heptane (e.g., 40 parts heptane to 1 part fluid sample) using the mixer  435  and filtering the mixture using the filter  436 . As discussed above, the filter  436  may remove any asphaltenes that may precipitate from the fluid sample. The sensor  438  may be used to measure a second optical density value of the mixture, which is compared to the first optical density by the processor  442 . If the first and second optical density values are substantially the same, then substantially no asphaltenes precipitated from the fluid sample. However, if the second optical density value is less than the first optical density value, asphaltenes have precipitated from the fluid sample. To determine an amount of asphaltenes contained in the fluid sample, a difference between the first and second optical density values may be interpreted using methods described in U.S. patent application Ser. No. 12/790,927, filed May 31, 2010. Fluid samples from multiple formation zones may be tested until all of the heptane is used. Once the chamber  426  or  428  storing the heptane is empty (i.e., all of the heptane has been used), the chamber  426  or  428  may store fluid samples to be used in a commingling analysis as disclosed herein. 
         [0055]      FIG. 5  depicts an example apparatus  500  that may be used to determine the compatibility of formation fluids obtained from different production zones. In contrast to the apparatus  400  of  FIG. 4 , the apparatus  500  includes example first storage chambers and a pump  502  and example second storage chambers and a pump  504 . In this example, the sample storage chambers and pumps  502  and  504  include pistons (e.g., motorized micropistons)  506 ,  508  and a plurality of first and second chambers (e.g., piston bores)  510 ,  512 . Each of the chambers  510  and  512  enables more than one fluid sample (e.g., formation fluid, formation water) to be obtained and/or stored and/or enables the storage of other fluids (e.g., toluene, heptane, water, gas, sea water, carbon dioxide, methane, ethane, propane or hydrogen sulfide or sulfur dioxide, etc.) that can be used downhole. Toluene may be used downhole to remove asphaltenes and/or other substances from the filter  436 . Heptane may be mixed with a fluid sample to determine the asphaltene content thereof in a manner described in U.S. patent application Ser. No. 12/790,927, filed May 31, 2010, assigned to the assignee of the present patent and hereby incorporated herein by reference in its entirety. 
         [0056]    In some examples, the example apparatus  500  may be used to determine the compatibility of water (e.g., dead or live waters). Water may be injected in the reservoir and/or mixed with different waters during enhanced oil recovery (EOR) processes. However, water to be injected and/or water to be mixed may be incompatible, which may lead to precipitation of scale. Using the examples disclosed herein, the compatibility of water may be determined using a process as described above. For example, if the compatibility of water from a first zone and a second zone is to be determined, the apparatus  500  may be used to obtain fluid samples from the respective zones. These samples can then be mixed using the mixer  435  and analyzed using the sensor  438  to identify any particulate (e.g., scale) that may have formed (e.g., the filter  436  may or may not be used). The observance of particulate may be identified by light scattering when shone through the fluid. If substantially no particulate is identified, the water from the first and second zones is substantially compatible. However, if the particulate is identified, the water from the first and second zones is not substantially compatible. 
         [0057]    In some examples, one or more gasses (e.g., carbon dioxide, methane, ethane, propane or hydrogen sulfide or sulfur dioxide) may be injected into a reservoir to decrease the viscosity of the oil. However, depending on the temperature, pressure and oil/gas ratios, injecting such gasses may cause asphaltenes to precipitate. The precipitation of asphaltenes may negatively impact reservoir porosity by plugging formation pores and/or decreasing production rates. 
         [0058]    In some example, the optical density of the oil, and the optical density of the oil and the gas mixture are measured using, for example, the sensors  432  and/or  438 , in a manner as described above. The optical density values may be compared to determine whether the addition of gas caused asphaltene to flocculate. Based on the comparison, a concentration of gas (e.g., the gas/oil ratio) may be changed. If the addition of the gas to the fluid did not cause asphaltenes to flocculate, the optical density values are to be substantially the same. If the addition of the gas to the fluid caused asphaltenes to flocculate, the optical density value of the mixture is less than the optical density value of the fluid without the gas. In some examples to quantify an amount of asphaltenes that flocculated, in accordance with the teachings of this disclosure, the asphaltene content versus optical density method may be used. 
         [0059]    To control fluid flow relative to the respective chambers  510 ,  512 , the piston  506  can be selectively fluidly coupled to one of the first chambers  510  using a fluid control device(s)  514  and the piston  508  can be selectively fluidly coupled to one of the second chambers  512  using a fluid control device(s)  516 . 
         [0060]      FIG. 6  depicts an example floating piston  600  positioned in a piston bore  602 . The piston  600  includes an O-ring  604  to substantially separate hydraulic oil used to move the piston  600  from the sample obtained. 
         [0061]    A flowchart representative of an example method that may be used to implement the apparatus  180 ,  400  and/or  500  of  FIGS. 1 ,  4  and  5  and/or the examples disclosed herein is shown in  FIG. 7 . In this example, the method may be implemented using machine readable instructions comprising a program for execution by a processor such as the processor P 105  shown in the example processor platform P 100  discussed below in connection with  FIG. 13  and/or the processor  442  of  FIGS. 4  and/or  5 . The program may be embodied in software stored on a tangible computer readable medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a BluRay disk, or a memory associated with the processor P 105 , but the entire program and/or parts thereof could alternatively be executed by a device other than the processor P 105  and/or embodied in firmware or dedicated hardware. Further, although the example program is described with reference to the flowchart illustrated in  FIG. 7 , many other methods of implementing the example apparatus  180 ,  400  and/or  500  may alternatively be used. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated or combined. 
         [0062]    As mentioned above, the example operations of  FIG. 7  may be implemented using coded instructions (e.g., computer readable instructions) stored on a tangible computer readable medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage media in which information is stored for any duration (e.g., for extended time periods, permanently, brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term tangible computer readable medium is expressly defined to include any type of computer readable storage and to exclude propagating signals. Additionally or alternatively, the example operations of  FIG. 7  may be implemented using coded instructions (e.g., computer readable instructions) stored on a non-transitory computer readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage media in which information is stored for any duration (e.g., for extended time periods, permanently, brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable medium and to exclude propagating signals. As used herein, when the phrase “at least” is used as the transition term in a preamble of a claim, it is open-ended in the same manner as the term “comprising” is open ended. Thus, a claim using “at least” as the transition term in its preamble may include elements in addition to those expressly recited in the claim. 
         [0063]    The example method  700  may be used to implement the examples described herein. While the below method  700  describes a commingling analysis, this method  700  may alternatively be used to determine the asphaltene content of a fluid sample obtained. In such examples, a downhole tools is lowered into a wellbore with one of the chambers  426 ,  428 ,  510  and/or  512  filled with heptane and the other of the chambers  426 ,  428 ,  510  and/or  512  to be filled with a fluid sample, once obtained. Prior to mixing the fluid sample and the heptane, an optical cell(s) may determine a first optical density value for a portion of the first sample. The fluid sample and the heptane are then pumped toward and/or through the mixer  435  having a torturous flowpath and/or the filter  436 . A second optical density value of the filtered mixture may be determined. To determine an amount of asphaltenes contained in the fluid sample, a difference between the first and second optical density values may be interpreted using methods described in U.S. patent application Ser. No. 12/790,927, filed May 31, 2010. 
         [0064]    Turning to method of  FIG. 7 , initially, a downhole tool such as the wireline tool  151  may be lowered into a wellbore (block  702 ). The wireline tool may then obtain a first sample from a first formation zone (block  704 ) and a second sample from a second formation zone (block  706 ). The first and second formation zones may be independent from one another. Using pumps  422 ,  424 ,  506  and/or  508 , the samples may be pumped to and stored in respective chambers  426 ,  428 ,  510  and/or  512  at any suitable pressure. 
         [0065]    Prior to mixing the samples, an optical cell(s) may independently determine a first optical density value for a portion of the first sample and a second optical density value for a portion of the second sample. The fluid samples may then be mixed and/or commingled by independently pumping the fluid samples from the respective sample chambers  426 ,  428 ,  510  and/or  512  at a controlled flow rate(s) (e.g., substantially equal volumetric flow rates, different flow rates) toward and/or through the mixer  435  having a torturous flowpath and/or the filter  436  (block  708 ). 
         [0066]    It may then be determined whether the first and second formation zones can be commingled during production based on a characteristic of the mixed fluids (block  710 ). In some examples, the characteristic is associated with an amount of asphaltenes that have flocculated when mixing the fluid samples. The amount of flocculated asphaltenes can be determined by obtaining a third optical density value for the mixed fluid samples, averaging the first and second density values to generate an average value and then comparing the average value to the third optical density value. If the third optical density value is less than the average optical density value, asphaltenes have flocculated from the mixed fluid samples and have been filtered out of the mixed fluid samples by the filter  436 . If the third optical density value is substantially similar to the average optical density value, substantially no asphaltenes have flocculated from the mixed fluid samples. In some examples, a difference between the third optical density and the average optical density corresponds to the optical spectrum of the asphaltenes in the samples. The asphaltene content of the fluid samples can be determined using a calibration curve, the optical density difference and/or a coefficient of determination (R 2 ). 
         [0067]    While an example manner of implementing the examples disclosed herein has been illustrated in  FIG. 7 , one or more of the elements, processes and/or operations illustrated in  FIG. 7  may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way. Further, the example apparatus  180 ,  400  and/or  500  and/or, more generally, the example method  700  of  FIG. 7  may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware. Thus, for example, any of the apparatus  180 ,  400  and/or  500  and/or, more generally, the example method could be implemented by one or more circuit(s), programmable processor(s), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)) and/or field programmable logic device(s) (FPLD(s)), etc. When any of the apparatus or system claims of this patent are read to cover a purely software and/or firmware implementation, at least one of the example apparatus  180 ,  400  and/or  500  are hereby expressly defined to include a tangible computer readable medium such as a memory, DVD, CD, BluRay, etc., storing the software and/or firmware. Further still, the example method of  FIG. 7  may include one or more elements, processes and/or operations in addition to, or instead of, those illustrated in  FIG. 7 , and/or may include more than one of any or all of the illustrated elements, processes and operations. 
         [0068]      FIG. 8  is an example plot of optical densities of various fluid samples in which the optical spectra of filtered mixed fluids (e.g., the first and second fluid samples) have been subtracted from the average optical spectra of the fluid samples.  FIG. 8  depicts optical density at a particular wavelength (i.e., 600 nm) for asphaltenes of different fluid samples and/or crude oil samples. Reference number  802  represents a linear model generated using the resulting optical density and asphaltene contents of the samples. In this example, the coefficient of determination is 0.96. 
         [0069]      FIG. 9  depicts an example mixer  900  that can be used to implement the examples described herein. The example mixer  900  includes a flowpath  902  that is torturous and/or has a plurality of bends and/or curves. 
         [0070]      FIGS. 10 and 11  depict an example filter  1000  that can be used to implement the examples described herein. Specifically,  FIG. 10  depicts a top view of the example filter  1000  and  FIG. 11  depicts a side view of the example filter  1000 . The example filter  1000  includes a flowpath  1002  having an inlet  1004 , an outlet  1006  and a membrane  1008 . The fluid path  1002  may be relatively long to enable the fluid sample(s) to be in contact with membrane  1008 . The membrane  1008  defines pores (e.g., relatively small pores)  1010  that block the passage of flocculates (e.g., large flocculates) but enables the passage of the fluid sample(s) therethrough. 
         [0071]      FIG. 12  depicts an example apparatus  1200  that may be used to determine the compatibility of formation fluids obtained from different production zones. The apparatus  1200  includes first and second solvent and fluid sample assemblies  1202  and  1204 . The first solvent and fluid sample assembly  1202  includes a solvent chamber  1206  that is selectively fluidly coupled to a first pump  1208  via a first valve  1210 . The first solvent and fluid sample assembly  1202  also includes a fluid sample chamber  1211  that is selectively fluidly coupled to a second pump  1212  via a second valve  1214 . The second solvent and fluid sample assembly  1204  includes a solvent chamber  1216  that is selectively fluidly coupled to a third pump  1218  via a third valve  1220 . The second solvent and fluid sample assembly  1204  also includes a fluid sample chamber  1222  that is selectively fluidly coupled to a fourth pump  1224  via a fourth valve  1226 . 
         [0072]    In operation, to determine a first optical density value of a first sample, the first valve  1210  is operated to enable the first pump  1208  to be filled with solvent from the reservoir  1206  and the second valve  1214  is operated to enable the second pump  1212  to be filled with sample fluid from the chamber  1211 . The chamber  1211  may be filled with fluid (e.g., formation fluid, water, gas, etc.) downhole or uphole. To ensure that flowlines  1228  and  1230  are filled with the first fluid sample (e.g., primed with formation fluid), the second valve  1214  is operated to enable the second pump  1212  to pump the fluid sample through the flowlines  1228  and  1230  and to waste (e.g., to the borehole)  1232 . A valve (e.g., a six way valve)  1234  may then be rotated (e.g., counterclockwise) to enable a flowline  1235  to be fluidly coupled to the flowline  1230 , a flowline  1236  and a mixer  1238 . Thus, pumping the solvent through the flowlines  1235 ,  1230 ,  1236  via the pump  1208  pushes the fluid sample from the flowline  1230  to the mixer  1238  while also removing any asphaltenes that may flocculate. After the first sample passes through the mixer  1238 , a sensor  1239  may determine a first optical density value of the first sample. 
         [0073]    Similarly, to determine a second optical density value of the second sample, the third valve  1220  is operated to enable the third pump  1218  to be filled with solvent from the reservoir  1216  and the third valve  1226  is operated to enable the second pump  1224  to be filled with sample fluid from the chamber  1222 . To ensure that flowlines  1240  and  1242  are filled with the second fluid sample (e.g., primed with formation fluid), the fourth valve  1226  is operated to enable the fourth pump  1224  to pump the fluid sample through the flowlines  1240  and  1242  and to waste (e.g., to the borehole)  1244 . A valve (e.g., a six way valve)  1246  may then be rotated (e.g., counterclockwise) to enable a flowline  1248  to be fluidly coupled to the flowline  1242 , a flowline  1250  and the mixer  1238 . Thus, pumping the solvent through the flowlines  1248 ,  1242 ,  1250  via the pump  1218  pushes the fluid sample from the flowline  1242  to the mixer  1238  while also removing any asphaltenes that may flocculate. After the second sample passes through the mixer  1238 , the sensor  1240  may determine a second optical density value of the second sample. 
         [0074]    With the optical density values of the first and second samples obtained and the flowlines  1230  and  1242  filled with fluid samples, the respective pumps  1208 ,  1218  pump and/or urge the first and second fluid samples from the flowlines  1230  and  1242  toward the mixer  1238 . The pumps  1208  and/or  1218  may selectively and simultaneously pump the first and second fluid samples at the same, similar or different flowrates. The mixer  1238  may be an active and/or passive mixer including a torturous flowpath that accelerates the rate at which the samples mix. Mixing the samples may cause asphaltenes to flocculate from the mixture. 
         [0075]    In this example, the mixed fluid samples pass through a filter  1252  that substantially prevents flocculated asphaltenes from flowing therethrough. After the mixed fluids have passed through the filter  1252 , the mixed fluids pass by a sensor  1254  that determines a third optical density value of the mixed fluids. 
         [0076]    To determine if and/or an amount of asphaltenes that may have flocculated when mixing the fluid samples, a processor  1256  may average the first and second optical density values to generate an averaged optical density value. The processor  1256  may then compare the averaged optical density value to the third optical density value. If the third optical density value is less and/or different than the averaged optical density value, asphaltenes have flocculated from the mixed fluid samples and, thus, the fluid samples may not be compatible. If the third optical density value is substantially similar to the averaged optical density value, substantially no asphaltenes have flocculated from the mixed fluid samples and, thus, the fluid samples may be compatible. 
         [0077]      FIG. 13  is a schematic diagram of an example processor platform P 100  that may be used and/or programmed to implement to implement the electronics and processing system  156 , the processor  442  and/or any of the examples described herein. For example, the processor platform P 100  can be implemented by one or more general purpose processors, processor cores, microcontrollers, etc. 
         [0078]    The processor platform P 100  of the example of  FIG. 13  includes at least one general purpose programmable processor P 105 . The processor P 105  executes coded instructions P 110  and/or P 112  present in main memory of the processor P 105  (e.g., within a RAM P 115  and/or a ROM P 120 ). The processor P 105  may be any type of processing unit, such as a processor core, a processor and/or a microcontroller. The processor P 105  may execute, among other things, the example methods and apparatus described herein. 
         [0079]    The processor P 105  is in communication with the main memory (including a ROM P 120  and/or the RAM P 115 ) via a bus P 125 . The RAM P 115  may be implemented by dynamic random-access memory (DRAM), synchronous dynamic random-access memory (SDRAM), and/or any other type of RAM device, and ROM may be implemented by flash memory and/or any other desired type of memory device. Access to the memory P 115  and the memory P 120  may be controlled by a memory controller (not shown). 
         [0080]    The processor platform P 100  also includes an interface circuit P 130 . The interface circuit P 130  may be implemented by any type of interface standard, such as an external memory interface, serial port, general purpose input/output, etc. One or more input devices P 135  and one or more output devices P 140  are connected to the interface circuit P 130 . 
         [0081]    The examples disclosed herein can be used to determine the compatibility of two or more fluids (e.g., formation fluids, waters, gas and water, etc.) and/or to determine an asphaltene content of a formation fluid (e.g., crude oil) downhole. In some examples, two formation fluids are mixed at different ratios to determine their compatibility at the ratio at which the fluids are to be mixed during production (e.g., 30% of fluid from a first formation zone and 70% from a second formation zone). 
         [0082]    The examples disclosed herein can be used to determine compatibility of mixing two or more fluids by varying an amount of time that the fluids are in contact with one another (e.g., varying the flow rate) prior to determining an amount of asphaltene precipitation. For example, if a long period (e.g., 100 seconds) of time lapses prior to analysis and it is determined that no asphaltenes have precipitated from the mixed fluids, the mixed fluids are relatively stable. If a short period (e.g., one second) of time lapses prior to analysis and it is determined that asphaltenes have precipitated from the mixed fluids, the mixed fluids are not relatively stable. 
         [0083]    In other examples an apparatus in accordance with the teachings of this disclosure includes a plurality of chambers and/or bottles (e.g., two, six) that may be used to independently house, obtain, dispense, fluid samples, solvents, gasses, etc. The apparatus may include one or more valves to direct the flow of fluid, solvent, gas, etc., to different flowlines and/or to different portions of the apparatus (e.g., the mixer, to the borehole, etc.). In some examples, a piston or other device is used to urge the fluid sample to flow toward the mixer. In other examples, a solvent or other substance (e.g., liquid, gas) is used to urge the fluid sample to flow toward the mixer. By mixing heptane with formation fluid, the examples disclosed herein can be used to determine an asphaltene content of the formation fluid downhole. 
         [0084]    In some examples, before determining whether two formation fluids can be commingled without asphaltene flocculation, a determination can be made as to whether asphaltenes are present in fluid obtained from a first zone by measuring the asphaltene content of a fluid sample obtained therefrom. Similarly, a determination can be made as to whether asphaltenes are present in fluid obtained from a second zone by measuring the asphaltene content of a fluid sample obtained therefrom. In some examples, if the first and second formation zones are to be simultaneously produced and/or if asphaltenes are present in fluid from either of the formation zones, the compatibility of the fluid from the first and second zones may be determined by commingling the fluids and performing an analysis thereon. 
         [0085]    Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 
         [0086]    The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Technology Category: 3