Microrheology of Fluids Used at Wellsite Cross-Reference to Related Applications

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 62/211,491, titled "Method and System for Obtaining Rheological Measurements of Stimulation Fluids Using Passive Microrheology," filed August 28, 2015, the entire disclosure of which is hereby incorporated herein by reference in its entirety.

Background of the Disclosure

[0002] Wellbores or boreholes may be drilled to, for example, locate and produce

hydrocarbons. Many different fluids and materials may be used during the production of hydrocarbons. Different properties of various ones of the fluids may affect the efficiency or effectiveness of the fluids in achieving their desired purpose during the production. For example, in hydraulic fracturing, the crosslinking ability of fracturing fluid and the time that elapses before it breaks down due to a breaker may affect how an operator determines how to remove hydrocarbons from the wellbore.

Summary of the Disclosure

[0003] 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

indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

[0004] The present disclosure introduces a method that includes obtaining a sample of a fluid at a wellsite and obtaining a rheological property of the fluid by performing a microrheology analysis on the sample. The fluid is either a well treatment fluid used at the wellsite for an oilfield production or a formation fluid.

[0005] The present disclosure also introduces a method that includes generating a well treatment fluid at a wellsite. The generating is controlled by process parameters. The well treatment fluid is transmitted along a flow path, and a sample of the well treatment fluid is obtained at a microrheology system. The microrheology system is fluidly connected to the flow path. The method also includes obtaining a rheological property of the well treatment fluid by performing a microrheology analysis on the sample using the microrheology system. The rheological property of the well treatment fluid is then compared to a set point, and one or more of the process parameters are adjusted based on the comparison.

[0006] The present disclosure also introduces an apparatus that includes a system to generate a well treatment fluid according to process control parameters. A flow path is fluidly connected to the system, and the system fluidly communicates the well treatment fluid along the flow path. The flow path fluidly communicates the well treatment fluid down a wellbore at a wellsite. The apparatus also includes a microrheology system fluidly connected to the system or the flow path. The microrheology system is to obtain a sample of the well treatment fluid from the system or the flow path, and perform a microrheology analysis on the sample to obtain a rheological property of the well treatment fluid. The apparatus also includes a control system to compare the rheological property of the well treatment fluid with a set point and adjust one or more of the process control parameters in response to the comparison of the rheological property with the set point.

[0007] The present disclosure also introduces a method that includes conveying a tool down a wellbore in a formation. The tool in the wellbore is then used to obtain a sample of a fluid present in the formation. The fluid is a well treatment fluid, a formation fluid, or a combination thereof. The method also includes obtaining, while the tool is in the wellbore, a rheological property of the fluid by performing a microrheological analysis on the sample.

[0008] The present disclosure also introduces an apparatus that includes a downhole tool capable of being conveyed down a wellbore in a formation. The downhole tool includes a probe module to engage the formation to communicate a fluid into the downhole tool. The fluid is a well treatment fluid, a formation fluid, or a combination thereof. The downhole tool also includes a flowline extending from the probe module to communicate the fluid through the downhole tool. The downhole tool also includes a microrheology module to obtain a sample of the fluid from the flowline. The apparatus also includes a processing system operable to obtain a rheological property of the fluid by performing a microrheology analysis on the sample.

[0009] These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims. Brief Description of the Drawings

[0010] The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

[0011] FIG. 1 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

[0012] FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0013] FIG. 3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0014] FIG. 4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0015] FIG. 5 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0016] FIG. 6 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0017] FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0018] FIG. 8 is an image depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0019] FIG. 9 is an image depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0020] FIG. 10 is an image depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0021] FIG. 11 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0022] FIG. 12 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0023] FIG. 13 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure. [0024] FIG. 14 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0025] FIG. 15 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0026] FIG. 16 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0027] FIG. 17 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0028] FIG. 18 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0029] FIG. 19 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0030] FIG. 20 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0031] FIG. 21 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

[0032] FIG. 22 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0033] FIG. 23 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0034] FIG. 24 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0035] FIG. 25 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0036] FIG. 26 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0037] FIG. 27 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure.

[0038] FIG. 28 is a graph depicting one or more aspects of an example implementation according to one or more aspects of the present disclosure. Detailed Description

[0039] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.

Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

[0040] Systems and methods and/or processes according to one or more aspects of the present disclosure may be used to determine rheological properties of various fluids used at various wellsites in the oil and gas industry. According to one or more aspects of the present disclosure, passive microrheology may be implemented to determine various rheological properties, such as a mean squared displacement (MSD), a viscoelastic modulus (G ^* ), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), elastic index (EI), and a macroscopic viscosity index (MVI), among other example properties, of a fluid. In some example

implementations, rheological properties may be determined by an in-line process at a wellsite and may be obtained real-time. Processes for generating and/or using the fluid may be altered based on the rheological properties to obtain target properties of the fluid. In further example implementations, rheological properties of a formation fluid may be determined, such as by a downhole tool, which may inform pumping and/or transportation conditions of the formation fluid or a treating fluid (either while being pumped into the formation or during flowback). Formation fluids can include any naturally occurring fluid present in subterranean formations, such as, but not limited to, oil, gas, oil and water emulsions, foams containing gas and one or both of oil and water.

[0041] According to one or more aspects of the present disclosure, passive microrheology analysis of a fluid used at a wellsite uses colloidal probes in a sample of the fluid to determine rheological properties. The colloidal probes may move according to Brownian motion within the fluid sample, which movement may be driven by thermal energy. A mean squared displacement (MSD) of the colloidal probes is determined, and other rheological properties of the fluid sample are derived from the MSD, such as a viscoelastic modulus (G ^* ) determined using the Generalized Stokes-Einstein relation. [0042] FIG. 1 is a flow-chart diagram of at least a portion of an example implementation of a method (100) for determining rheological properties of a fluid according to one or more aspects of the present disclosure. The method (100) may implement passive microrheology. The method (100) may be performed at a wellsite and may be performed, at least in part, by a processing system, such as described below. The method (100) may be used to obtain real-time data associated with a fluid, e.g., generated by surface processes, obtained from a formation by a downhole sampling tool disposed in a wellbore that extends into a subterranean formation, and other examples. The methods or processes described below are presented in a given order, although other implementations also within the scope of the present disclosure may comprise the described and/or other methods or processes in other orders and/or in parallel. Various other modifications to the methods or processes described below may also be consistent with the scope of the present disclosure. For example, such implementations may include additional or fewer calculations, determinations, computations, logic, monitoring, and/or other aspects.

[0043] The method (100) includes obtaining (102) a fluid sample. The fluid sample can be any fluid used at a wellsite, such as a fracturing fluid, a cementing fluid, a stimulation fluid, a gravel packing fluid, a water control fluid, an acidizing fluid, an oil-based mud (OBM) fluid, a water-based mud (WBM) fluid, a formation fluid, or others. The fluid sample can be obtained, for example, by in-line sampling once the fluid has been generated, by a sampling tool in a downhole tool, or other examples. Some example implementations for obtaining a fluid sample are described in further detail below.

[0044] The method (100) further includes adding (104) one or more tracer particles to the fluid sample. The tracer particles are used as the colloidal probes in some example

implementations. For example, if the fluid sample is clear, tracer particles may be added. Tracer particles can include polystyrene, titanium dioxide (T1O2), silica, and other example tracer particles. In some example implementations, adding (104) tracer particles may be omitted, and in those example implementations, intrinsic particles of the fluid sample may be used as tracer particles in the method (100). For example, if the fluid is turbid, translucent, or opaque, adding tracer particles may be omitted. Tracer particles may be added as solids or as pre-mixed liquid suspensions. In the latter case, the amount of suspension required is expected to be low enough such that the fluid sample is not substantially diluted.

[0045] Tracer particle size a may affect accuracy of an estimation of rheological properties, as will be described in more detail below. In some example implementations, the tracer particles are highly monodispersed. Furthermore, the size of tracer particles may be larger than a characteristic length of the test material (e.g., mesh size in gels, persistence length in

semiflexible polymer solution, or colloidal and emulsion sizes) so that the microscopic measurements may be consistent with macroscopic viscoelasticity results.

[0046] For uncrosslinked polymer solutions, the persistence length can be calculated using the following Equations (l)-(3):

R _g = 0.215M _W °- ^{583±0 031} A Eq. (1) c = ^Mw 3 Eq. (2) ξ = R _g (c /c) ⁰ - ⁷⁵ Eq. (3) where R _g is the radius of gyration of the polymer, c is the overlap concentration of the polymer in the solution, c is the concentration of polymer in the solution respectively, ξ is the persistence length of the semidilute polymer solution (e.g., which may be of order in a few nanometers), and M _w is the weight-averaged molecular weight.

[0047] For crosslinked gels, the mesh size may depend on crosslink density and polymer volume fraction, which can be a few nanometers up to hundreds of nanometers. Some polymers are heterogeneous, and the addition of a crosslinker may generate a broad distribution of mesh sizes. It is assumed that when a tracer particle is trapped in a pore between crosslinked cores, the bulk rheology is dominated by elastic modulus while the microrheology response is more viscous. Oftentimes, the effect of particle size is generally investigated by comparing a r ² for different sizes of tracers. If the test sample property is independent of tracer size, the curves should overlap; otherwise, differences should be observed. However, sometimes tracers larger than the characteristic length may be problematic. Large size tracers may have non-Brownian motion.

[0048] Any interactions between the tracer particles and the test sample can cause deviation from generalized Stokes-Einstein behavior. For example, the electrostatic interaction between oppositely charged tracer and polymer backbone could result in irreversible adsorption of tracer on polymer matrix and constrain the motion of the tracer. Negatively charged fluids may use negative tracers. However, this may not be true in each instance. For weakly negatively charged polyacrylamide, as an example, the tracer surface chemistry may have no effect on

microrheology measurements. Sometimes, the charge groups used to stabilize the colloidal particles can react with polymers (e.g., biopolymers), and this can cause changes of microstructure of test polymer samples.

[0049] Tracers with different surface modifications have been commercially available. The most commonly used tracers are monodispersed polystyrene spheres. Various surface modifications including negatively modified, such as with sulfate or carboxylate, or positively modified, such as with aldehyde-amidine, are made based on the properties of the sample in which the tracers are to be embedded. The tracers also may have a good index of refraction contrast. For opaque samples, the difference of index of refraction between the tracer and the test samples should be large enough to allow observation of the movement. For organic solvent, crosslinked particles may be used to avoid swelling of the tracer particles.

[0050] Tracer concentration can be determined by the method used for microrheology measurements. For example, tracer concentration can be, for example, three orders of magnitude higher in dynamic light scattering (DLS) than that in diffusing wave spectroscopy (DWS). In some example implementations, tracer concentration may be in a range from 0.00001 volume percent to 10 volume percent. By changing the tracer concentration, the autocorrelation curve of light scattering can sweep the gap between single and multiple scattering limit, and a dramatic change in moduli was observed for glycerol solution with identical viscosity.

[0051] The velocity of tracer sedimentation also may be considered. For example, a single particle in purely viscous fluid has a sedimentation velocity v _se d, which is expressed as in Equation (4) below.

_ 2a ² g p _p -p _f )

V _S ed ~ _n bq. (4) where a is the particle radius, η is viscosity, g is gravity, p _p is the density of the tracer particle, and yO/is the density of the fluid.

[0052] In an experiment, if a 1 μπι polystyrene sphere is used, its specific gravity is 1.05 gxcm ³ and it will sediment in water with a velocity of 1.1 x 10 ⁵ cmxs ^l . In other words, it will take about 2 h to sediment 1 mm. The sedimentation may not be a problem for samples with higher viscosity than water, which will help the beads remain suspended.

[0053] For stimulation fluids measurements, most rheological measurements are performed under high temperature and high pressure. Some tracer particles can experience thermal instability at high temperature, such as above 80 °C. [0054] The method (100) further comprises obtaining (106) a mean squared displacement (MSD) of tracer particles in the fluid sample. MSD ² (τ) is mathematically expressed below in Equation (5). It is noted that angular brackets used in different equations herein denote a time average.

2( _T ) = (t + T) f(t) ² Eq. (5)

MSD of tracer particles may be obtained using, for example, diffusing wave spectroscopy (DWS), dynamic light scattering (DLS), video particle tracking (VPT), or other example techniques.

[0055] DWS generally analyzes a signal generated by scattering of light through a sample. FIG. 2 is a schematic view of at least a portion of an example implementation of a system 200 that may be used for DWS according to one or more aspects of the present disclosure. In the system 200, a fluid sample 204 is captured in a cell 202, and tracer particles 206 are dispersed in the fluid sample 204. The cell 202 is constructed of a transparent material, such as glass. The system 200 further includes a light source 208, such as a laser, configured to direct light towards the fluid sample 204 in the cell 202, and includes a detector 210, such as a photodetector like a charged coupled device (CCD), photodiode, or the like, capable of detecting a light signal reflected from the fluid sample 204. The cell 202 may have a thickness, e.g., parallel to the propagation of the light before being incident on the cell 202, that is at least 5 times the transport mean free path / ^* of the fluid sample 204. The system 200 may be referred to as a DWS backscattering system.

[0056] The system 200 may further include other components that may be used to capture the fluid sample 204 in the cell 202 and to insert tracer particles 206 into the fluid sample 204, for example. A flowline 220 is in fluid communication between an in-line conduit, flowline, or the like at a wellsite, for example, and, as illustrated, a Tee-coupling to the cell 202 and a tracer particle container 226. A first control valve 222 is disposed in the flowline 220 between the inline flowline and the Tee-coupling. A second control valve 224 is in the Tee-coupling proximate to the tracer particle container 226. Other example implementations may have other

configurations and/or components, such as one or more pumps or displacement units and/or one or more valves to control the flow of a fluid. Additionally, in some example implementations where tracer particles 206 may be omitted, the tracer particle container 226, second control valve, and Tee-coupling may be omitted, for example. [0057] In some example implementations, a fluid sample 204 may be obtained by opening the first control valve 222 to allow fluid to flow through the flowline 220 and into the cell 202, while the second control valve 224 remains closed. Once the fluid sample 204 has been captured in the cell 202, the first control valve 222 is closed, and the second control valve 224 is opened to allow the tracer particles 206 in the tracer particle container 226 to be dispersed in the fluid sample 204. In some example implementations, tracer particles 206 are in the cell 202 when the fluid sample 204 is captured through the flowline 220, and in such examples, the tracer particle container 226, second control valve, and Tee-coupling may be omitted. Additionally, in another example implementation, the tracer particles 206 may be pre-loaded into the cell 202 before introducing the fluid sample 204 into the cell.

[0058] FIG. 3 is a schematic view of at least a portion of an example implementation of a system 300 that may be used for DWS according to one or more aspects of the present disclosure. In the system 300, a fluid sample 204 is captured in a cell 202, and tracer particles 206 are dispersed in the fluid sample 204. The system 300 further includes a light source 208, such as a laser, configured to direct light towards the fluid sample 204 in the cell 202, and includes a detector 302, such as a photodetector like a CCD, photodiode, or the like, capable of detecting a light signal transmitted through the fluid sample 204. The systems 200 and 300 may be referred to as a DWS transmission system.

[0059] The system 300 may further include other components that may be used to capture the fluid sample 204 in the cell 202 and to insert tracer particles 206 into the fluid sample 204, for example, as described above with respect to the system 200 of FIG. 2. Other example implementations may have other configurations and/or components, such as one or more pumps or displacement units and/or one or more valves to control the flow of a fluid, and/or may omit components, as previously described. Additionally, in another example implementation, the tracer particles 206 may be pre-loaded into the cell 202 before introducing the fluid sample 204 into the cell.

[0060] In DWS, light, such as from the light source 208 in the system 200, 300, is incident on a fluid sample, such as fluid sample 204. The light is scattered as a result of reflections off of the tracer particles, such as tracer particles 206, or intrinsic particles if tracer particles are not added to the fluid sample. Brownian motion of the tracer particles or intrinsic particles in the fluid sample can result in random scattering of the light that is incident on the fluid sample. The scattering can cause constructive and destructive interference in a light signal that is reflected back from and transmitted through the fluid sample. An intensity signal Ift), which may include a speckle image, is detected by a detector, such as detector 210 in system 200, from reflected backscattering in a DWS backscattering system, or is detected by a detector, such as detector 302 in system 300, from scattering transmitted through the fluid sample in a DWS transmission system.

[0061] The intensity signal Ift) is used to obtain a normalized intensity autocorrelation function g2f τ), as shown below by Equation (6) below.

/(t)/(t+T) , .

0 ₂ (τ) = _{/(t) 2} Eq. (6)

[0062] According to the Siegert relation, the normalized intensity autocorrelation function g2(x) can be normalized into an electric field autocorrelation function gift), which is shown below in Equation (7).

g ₂ (T) = l + \ _gi (T) \ ² Eq. (7) where β is a coherence factor (which may depend on the system set-up).

[0063] An MSD ² (t) can be determined by solving Equations (8) and (9) below.

Δ _Ρ ² ( = l A ² (t) Eq. (9) where s is a photon path length, Pfs) is a probability density function (PDF) that light travels a path length s, φ _ρ is the phase shift in the light due to scattering, ko is the incident wavevector, and / ^* is the transport mean free path. The path length s can be determined as shown in Equation (10) below.

s = Nl Eq. (10) where N is the number of scatters along a path length s, and / is the average distance between scatters. The average distance between scatters / can be determined as shown in Equation (11) below.

1 = (ρσ) Eq. (l l) where p is particle number density, and σ is total scattering cross section (which may depend on incident wavevector ko and scattering wavevector q). The transport mean free path / ^* can be determined as shown in Equation (12) below.

i

I =

l-cos Θ Eq. (12) where Θ is the average scattering angle. [0064] DLS also generally analyzes a signal generated by scattering of light through a sample. FIG. 4 is a schematic view of at least a portion of an example implementation of a system 400 that may be used for DLS according to one or more aspects of the present disclosure. In the system 400, a fluid sample 204 is captured in a cell 202, and tracer particles 206 are dispersed in the fluid sample 204. The cell 202 is constructed of a transparent material, such as glass. The system 200 further includes a light source 208, such as a laser, configured to direct light towards the fluid sample 204 in the cell 202, and includes a detector 402, such as a photodetector like a CCD, photodiode, or the like, capable of detecting a light signal scattered through the fluid sample 204 at an angle 404 from the direction of the light from the light source 208. The cell 202 may have a thickness, e.g., parallel to the propagation of the light before being incident on the cell 202, that is less than the transport mean free path f of the fluid sample 204, and hence, the concentration of the tracer particles 206 in the fluid sample 204 may be sufficiently low such that the thickness of the cell 202 is less than the transport mean free path / ^* of the fluid sample 204. The system 400 may be configured such that incident light from the light source 208 is scattered in the fluid sample 204 once before exiting the cell 202. The system 400 may be referred to as a DLS system.

[0065] In some examples, the light source 208 is a laser light source that focuses on an area having a diameter of about 50-100 μπι in the sample. The laser power in the sample may be in the range of 50-300 mW. Local heating and convection effect in the sample can be prevented by avoiding absorbance lines. In some examples, the angle 404 is in a range from 15 to 150°, and in more particular examples, the angle 404 is at about 90°, which may avoid a disturbance of scattering by large dusty particles.

[0066] The system 400 may further include other components that may be used to capture the fluid sample 204 in the cell 202 and to insert tracer particles 206 into the fluid sample 204, for example, as described above with respect to the system 200 of FIG. 2. Other example implementations may have other configurations and/or components, such as one or more pumps or displacement units and/or one or more valves to control the flow of a fluid, and/or may omit components, as previously described. Additionally, in another example implementation, the tracer particles 206 may be pre-loaded into the cell 202 before introducing the fluid sample 204 into the cell.

[0067] In DLS, light, such as from the light source 208 in the system 400, is incident on a fluid sample, such as fluid sample 204. The light is scattered as a result of reflections off of the tracer particles, such as tracer particles 206, or intrinsic particles if tracer particles are not added. In DLS, scattering may occur once for each photon. Brownian motion of the tracer particles or intrinsic particles in the fluid sample can result in random scattering of the light that is incident on the fluid sample. The scattering can cause constructive and destructive interference in a light signal that is scattered through the fluid sample. An intensity signal 1ft) is detected by a detector, such as detector 402 in system 400, at an angle, such as angle 404, from the original propagation direction of the light in a DLS system.

[0068] As described above, the intensity signal 1ft) is used to obtain a normalized intensity autocorrelation function g2fi), as shown by Equation (6) above. The normalized intensity autocorrelation function g2fi) can be normalized into an electric field autocorrelation function gift), which is shown above in Equation (7).

[0069] An MSD r ² (t) can be determined by solving Equation (13) below, which is simplified to Equation (14) below.

-q Ar ² (t)

9ι (τ) = e 6 Eq. (14) where q is a scattering wavevector.

[0070] VPT generally uses image processing of images of a fluid sample to track movement of particles in the fluid sample. FIG. 5 is a schematic view of at least a portion of an example implementation of a system 500 that may be used for VPT according to one or more aspects of the present disclosure. In the system 500, a fluid sample 204 is captured in a cell 202, and tracer particles 206 are dispersed in the fluid sample 204. The cell 202 is constructed of a transparent material, such as glass. The system 500 further includes an imaging device 502 and a lens 504 through which the imaging device 502 views the fluid sample 204 in the cell 202 with a field of view 506. The system 500 may be configured such that magnified images, e.g. , through the use of lens 504, are captured by the imaging device 502 and are processed to track movement of tracer particles 206 or intrinsic particles if tracer particles 206 are not added. The system 500 may be referred to as a VPT system.

[0071] The system 500 may further include other components that may be used to capture the fluid sample 204 in the cell 202 and to insert tracer particles 206 into the fluid sample 204, for example, as described above with respect to the system 200 of FIG. 2. Other example implementations may have other configurations and/or components, such as one or more pumps or displacement units and/or one or more valves to control the flow of a fluid, and/or may omit components, as previously described. Additionally, in another example implementation, the tracer particles 206 may be pre-loaded into the cell 202 before introducing the fluid sample 204 into the cell.

[0072] In VPT, video microscopy is applied to directly visualize motions of one or more tracer or intrinsic particles as a function of time. Direct visualization can be useful to check the distribution of the tracer particles to confirm that no aggregation has occurred. This tracking method allows an individual particle trajectory to be measured, and also provides an ensemble average over the trajectories by tracking a number of particles simultaneously, such as 100 particles. For homogeneous samples, it is assumed that the result from one-particle

microrheology measurements reflects the bulk properties. However, if the sample has heterogeneity at the length scale comparable to the particle size, multiparticle tracking may be used to study the bulk properties, since single particle measurements may represent local mechanics and microstructure. The trajectory of one particle can be obtained by locating the particle position in a sequence of images with a time step At.

[0073] In some examples, bright field microscopy is used for imaging, such as for particles on the scale of one hundred nanometers and larger, and in some examples, epi-fluorescence microscopy is used, such as for particles on the scale of one hundred nanometers and smaller. Temporal resolution of VPT can be determined by the frame rate of the imaging device (e.g., camera), and a high speed camera allows recording of 40-250,000 (or more) frames per second. Exposure time may be long enough to detect motion. Spatial resolution of the microscope may be determined by detectable distance between each movement of a tracer particle. VPT may detect extremely small displacements of the particle at high frequencies.

[0074] An example algorithm used for determining particle positions and trajectories analysis has been developed, and the software has been made available online at

http://www.physics.emory.edu/faculty/weeks//idl/, which software is incorporated herein by reference in its entirety. Accordingly, image processing can determine an MSD of particles that are tracked.

[0075] FIG. 6 is a graph showing generalized MSD curves for different types of materials in accordance with one or more aspects of the present disclosure. For a purely viscous fluid, the Brownian motion of a particle is determined from a diffusion equation: r ² (t) = 4aDt, and the viscous fluid MSD curve 602 evolves linearly with time and has a slope equal to 1. For a viscoelastic material, the particles exhibit subdiffusive motion due to elasticity, which is characterized by a viscoelastic material MSD curve 604 having a slope that is greater than 0 and less than 1. For a purely elastic material, the motion of particles is constrained in the medium such that an elastic material MSD curve 606 has a slope of 0, and the particles reach the equilibrium when the elastic energy is balanced with the thermal energy of the probes.

[0076] Referring back to FIG. 1 , the method (100) further includes obtaining (108) other rheological properties, such as a viscoelastic modulus G*(co), an elastic modulus (G'), a viscous modulus (G"), viscosity (η*), EI, and MVI, of the fluid sample. The Generalized Stokes- Einstein Equation can be used to quantify some rheological properties of the fluid sample and calculate the viscoelastic modulus G*(co) from the MSD measurement according to Equation (15) shown below.

G(s) = ^keT _{2 i} , Eq. (15) nas r ² (s) ¹ ' where G (s) is the viscoelastic modulus in the Laplace domain, ² (s) is the Laplace transform of the MSD ² (τ) , r is the decorrelation time, ke is Boltzmann's constant, J is the absolute temperature, a is a tracer particle radius, and s is a Laplace frequency. An arbitrary functional form is fit to G (s) . The modulus in Laplace frequency space G(s) is transformed to Fourier frequency space by fitting G (s) with an arbitrary function and compared with bulk mechanical measurements. Accuracy of this method may be limited by truncation errors introduced by numerical transformation of data over a limited range and an appropriate functional form to fit to G (s) .

[0077] Another numeric method can calculate the viscoelastic modulus G*(co) from Equation (15) above. In this method, the MSD of the particle tracer is fitted with a local power law, and the viscoelastic modulus G*(co) is estimated algebraically by the local power law, as shown in Equations (16) and (17).

, d In<Af ² > _r

(ω ) = Eq. (16)

where the lag time t is the reciprocal of frequency co, Ar ² (t) is the MSD at lag time t, and Γ is the gamma function. The gamma function is a result of the Fourier transform of the power law. It can be approximated by a polynomial fit over the range of a, as shown in Equation (18) below.

Γ[1 + a] ~ 0.457(1 + a) ² - 1.36(1 + a)+\ .90 Eq. (18) [0078] The frequency dependent storage (elastic) modulus G' and loss (viscous) modulus G" can be obtained from the viscoelastic modulus G ^* (co) by Euler's equation, as shown below in Equations (19) and (20).

G' (6>) = | G (6)) |cos(^) Eq. (19) G"(o)) = \G (6,) |sin(^) Eq. (20)

The complex viscosity η ^* is calculated from the complex viscoelastic modulus G ^* (co) as shown below in Equation (21).

η = \G (ω) |/ω Eq. (21)

The complex viscosity of the fluid thus obtained may be compared to the steady shear viscosity of the fluid (η) via the Cox Merz rule as shown in Equation (22). Here, γ is the shear rate applied in the steady shear measurement.

η (ω) = η (y) at ω = γ Eq. (22)

[0079] For highly curved MSD, the slope of the curve changes rapidly, and Equations (16) and (17) may not be able to be used to estimate the moduli. A modified algorithm including second order derivatives of the MSD can be used to capture the curvature, which can give a better estimate of the moduli in the curved regions of the data.

[0080] Some assumptions are made using the General Stokes-Einstein Equation. First, it is assumed that the medium is homogeneous, continuous, and incompressible. This assumption holds true when the tracer particle is larger than the characteristic length scale of the medium, e.g., mesh size of the gel, emulsion or colloidal size. Next, it is assumed that the inertial effects of particles and fluid are negligible. Further, it is assumed that compressibility of the medium is negligible. For thermally driven Brownian motion, the tracer particle responds to both shear and longitudinal forces generated in the fluid. If the frequency is less than its lower bound, the surrounding fluid starts to drain from the network, and the longitudinal mode becomes noteworthy. If the frequency is above this value, the fluid is considered incompressible, and the longitudinal mode of the network is restrained. Additionally, it is assumed that the tracer particles are monodispersed and spherical, and that they do not interact with each other or with the medium. With these assumptions, microrheological measurements can provide the bulk rheological properties.

[0081] In some example implementations, EI can be obtained. For example, EI can be the inverse of a plateau height of logarithmic MSD. The EI of a sample can be an indication of the evolution of the elasticity of the sample as a function of time. In some example

implementations, MVI can be obtained. For example, MVI can be inversely proportional to the slope of MSD in a linear scale.

[0082] Another aspect about microrheology is its capability of providing insights into local dynamics, such as non-Brownian motion, and particle-particle interaction that is inaccessible to bulk measurements for complex fluids such as drilling mud, cement, etc. at static condition. For example, such complex fluids can be a heterogeneous system that contains two distinct phases or emulsions, as well as a homogeneous system that undergoes phase changes or phase transitions due to particle coagulation by particle-particle interaction or particle-fluid interaction.

[0083] The complex interactions between the different species cause the change of dynamic motion of the particles and further affect the rheology and diffusion properties. The photon transport mean free path / ^* is generally the length over which the direction of the photon is fully randomized in the multiple scattering regime. For non-interacting scatters, the photon transport mean free path / ^* is related to the form factor F(q) that is a function of particle size, refraction indices of scatters, and dispersion medium. For interacting scatters, the photon transport mean free path / ^* is related to both the form factor F(q) and structure factor S(q) which indicate particle-particle interactions. If the volume fraction and refractive index contrast between the particles and the continuous phase are constant, a change in the photon transport mean free path / ^* tells the change in the interactions between particles. Additionally, Generalized Stoke-Einstein relation may not hold in this case, and information related to the stability and characteristic length of the system may still be extracted from raw MSD curves. A lower plateau corresponds to a reduction of the size of the "cage" that the scatterer is bound to. It can be used as an indication of the evolution of the elasticity of the product as a function of time. Macroscopic viscosity index (MVI) is inversely proportional to slope of MSD after the plateau-an indication of the viscosity of sample; as the slope gets smaller, the viscosity of the sample becomes larger. Also, the slope of MSD curve larger than 1 indicating sedimentation phenomena.

[0084] FIG. 7 is a schematic view of at least a portion of an example implementation of a processing system 700 according to one or more aspects of the present disclosure. The processing system 700 may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein. For example, the processing system 700 may execute example machine-readable instructions to obtain (106) a MSD of a tracer particle and to obtain (108) other rheological properties, as described above with respect to the method (100) of FIG. 1. The processing system 700 may be implemented in a portion of one or more of the example surface equipment at a wellsite and/or a portion of one or more of the example downhole tools described herein.

[0085] The processing system 700 may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, servers, personal computers, personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices. Moreover, while it is possible that the entirety of the processing system 700 shown in FIG. 7 is implemented within a microrheology system at a surface of a wellsite or within a downhole tool, one or more components or functions of the processing system 700 may also or instead be implemented in various wellsite surface equipment, perhaps including a logging and control unit and/or wellsite surface equipment described below and illustrated in subsequent figures, and/or other wellsite surface equipment.

[0086] The processing system 700 comprises a processor 712 such as, for example, a general-purpose programmable processor. The processor 712 may comprise a local memory 714, and may execute program code instructions 732 present in the local memory 714 and/or in another memory device. The processor 712 may execute, among other things, machine-readable instructions or programs to implement the methods and/or processes described herein. The programs stored in the local memory 714 may include program instructions or computer program code that, when executed by an associated processor, enable a microrheology system, surface equipment, and/or a downhole tool to perform tasks as described herein. The processor 712 may be, comprise, or be implemented by one or more processors of various types operable in the local application environment, and may include one or more general purpose processors, special- purpose processors, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), processors based on a multi- core processor architecture, and/or other processors. More particularly, examples of a processor 712 include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs, etc.

[0087] The processor 712 may be in communication with a main memory 717, such as via a bus 722 and/or other communication means. The main memory 717 may comprise a volatile memory 718 and a non-volatile memory 720. The volatile memory 718 may be, comprise, or be implemented by tangible, non-transitory storage medium, such as random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 720 may be, comprise, or be implemented by tangible, non-transitory storage medium, such as read-only memory, flash memory and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 718 and/or the nonvolatile memory 720.

[0088] The processing system 700 may also comprise an interface circuit 724. The interface circuit 724 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, and/or a cellular interface, among other examples. The interface circuit 724 may also comprise a graphics driver card. The interface circuit 724 may also comprise a communication device such as a modem or network interface card to facilitate exchange of data with external computing devices via a network, such as via Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, and/or satellite, among other examples.

[0089] One or more input devices 726 may be connected to the interface circuit 724. One or more of the input devices 726 may permit a user to enter data and/or commands for utilization by the processor 712. Each input device 726 may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an image/code scanner, and/or a voice recognition system, among other examples.

[0090] One or more output devices 728 may also be connected to the interface circuit 724. One or more of the output device 728 may be, comprise, or be implemented by a display device, such as a liquid crystal display (LCD), a light-emitting diode (LED) display, and/or a cathode ray tube (CRT) display, among other examples. One or more of the output devices 728 may also or instead be, comprise, or be implemented by a printer, speaker, and/or other examples.

[0091] A light source device 740 may also be connected to the interface circuit 724. The light source device 740 can be the light source 208 in the systems 200, 300, 400 of FIGS. 2-4. The light from the light source device 740 may be directed at a fluid sample in a cell, such as the fluid sample 204 in the cell 202 shown in FIGS. 2-4. The processing system 700 can control the operation of the light source device 740, such as by turning the light source device 740 on and off. [0092] A sensor device 742 may also be connected to the interface circuit 724. The sensor device 742 can be the detector 210, 302, 402 in the system 200, 300, 400 of FIGS. 2-4 and the imaging device 502 in the system 500 of FIG. 5. The sensor device 742 can be positioned to receive light scattered by a fluid sample in a cell, such as the fluid sample 204 in the cell 202 shown in FIGS. 2-4, and/or to view a fluid sample in a cell, such as the fluid sample 204 in the cell 202 shown in FIG. 5. The processing system 700 can receive one or more signals input from the sensor device 742 through the interface circuit 724 and may perform operations on the one or more signals to determine rheological properties of a fluid sample.

[0093] The processing system 700 may also comprise a mass storage device 730 for storing machine-readable instructions and data. The mass storage device 730 may be connected to the interface circuit 724, such as via the bus 722. The mass storage device 730 may be or comprise tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples. The program code instructions 732 may be stored in the mass storage device 730, the volatile memory 718, the non-volatile memory 720, the local memory 714, and/or on a removable storage medium 734 (which may be connected to the interface circuit 724), such as a CD or DVD.

[0094] The modules and/or other components of the processing system 700 may be implemented in accordance with hardware (such as in one or more integrated circuit chips, such as an ASIC), or may be implemented as software or firmware for execution by a processor. In the case of firmware or software, the implementation can be provided as a computer program product including a computer readable medium or storage structure containing computer program code (i.e., software or firmware) for execution by the processor.

[0095] EXAMPLES

[0096] Some example experiments were performed on sample fluids used at various wellsites. The method (100) of FIG. 1 was performed using a processing system 700 of FIG. 7 to implement microrheology. A DWS backscattering system, such as a Rheolaser™ from Formulaction, was used for the example experiments. This setup was configured to measure dynamic rheology over a frequency range of 0.01 to 100 Hz. The setup allows measurements of samples from ambient to 60 °C. Sample cells held 20 mL of sample fluid volume. The frame rate of the CCD detector that was used was 27 frames/sec. The wavelength of the laser used as the light source was 635 nm, and the laser focused on a 50 μιη diameter spot. The speckle size was about twice the pixel size, which in these examples, the pixel size was 12 μπι.

[0097] Two different tracer particles were employed in different examples: (a) Polybead® polystyrene tracer (0.5 μπι, 0.75 μπι, and 1 μιη) from Polysciences, Inc; and (b) 0.5 μιη titanium dioxide (T1O2) from Formulaction. The tracer particles were dispersed in deionized (DI) water in a Waring blender, and sonication was applied to prevent aggregation. Then, the tested polymer was added to tracer stock solutions and hydrated for 15 minutes at 3000 rpm.

[0098] As shown in FIG. 8, the polystyrene beads (2.6 wt% suspension in water) provided from the manufacturer still have aggregates even with a small amount of surfactant coating. After sonication, the particles are evenly distributed in DI water, as illustrated in FIG. 9 with 0.15 wt% polystyrene beads after sonication. When the polymer is added, most of the samples still have well-dispersed tracers, as illustrated in FIG. 10 with 0.15 wt% polystyrene beads after mixing with polymer after 6 hr. In most of the samples, no tracer aggregates were observed for the first 6 hr.

[0099] In a first example, a hydraulic fracturing fluid containing CarboxyMethyl

HydroxyPropyl Guar (CMHPG) viscosifier, was tested. 0.6 wt% of CMHPG was hydrated in DI water with 0.15% Ti0 ₂ suspension in a Waring blender for 20 minutes. An amine pH buffer and a boron/zirconium dual crosslinker were added to prepare the fluid. The fluid was then loaded into the DWS instrument at 40 °C. The crosslinker was gradually released and led to gelation at 40 °C.

[00100] FIG. 11 shows the elastic modulus (G') 1102 and viscous modulus (G") 1 104 of boron/zirconium crosslinked CMHPG measured at 1 Hz as a function of time at 40 °C. Both the elastic modulus (G') 1102 and viscous modulus (G") 1104 increase with time, eventually reaching a plateau. After a certain amount of time, the elastic modulus (G') 1102 and viscous modulus (G") 1104 cross, indicating a transition of sol to gel. These observations are consistent with gelation of the fluid due to gradual release of metallic crosslinker and are also consistent with visual observations of the fluid.

[00101] In a second example, a hydraulic fracturing fluid containing Guar viscosifier with a breaker, was tested. 1 wt % Guar in 0.15 % Ti0 ₂ was mixed with varying concentrations of ammonium persulfate breaker. The microrheology tests were performed at 25 °C. FIG. 12 shows the variation of elastic modulus (G') at 1 Hz with time. A first elastic modulus (G') 1202 is shown for Guar with no breaker (ammonium persulfate). A second elastic modulus (G') 1204 is shown for Guar with 2 pounds-per-thousand-gallons (ppt) breaker (ammonium persulfate). A third elastic modulus (G') 1206 is shown for Guar with 5 ppt breaker (ammonium persulfate). The steady decrease in the modulus of the fluid containing breaker is tracked by DWS. Gel breaking gets faster with increase of breaker concentrations. In contrast, the fluid without breaker displays a stable elastic modulus over the duration of the test.

[00102] In a third example, a water control fluid, Inter-polymer complex (IPC) including Polyacryl amide (PAM) and Polyvinylpyrrolidone (PVP), was tested. IPCs having 6% PVP and 3% PAM were formulated at different pH values - 7, 8, 9, 10, and 11. These fluids were tested with the DWS system at 25 °C. DWS is able to test samples at different pH values, even at extreme acidity. The crosslinking kinetics at different pH values were captured well. The crossover point of the elastic modulus (G') and viscous modulus (G") shifted to a lower point with higher pH which indicates increasing pH accelerates the crosslinking process. FIGS. 13-15 are graphs showing the elastic moduli (G') 1302, 1402, 1502 and viscous moduli (G") 1304, 1404, 1504 of IPCs having 6% PVP and 3% PAM with pH values of 9, 10, and 11, respectively, tested at 1 Hz. Crossover points 1306, 1406, 1506 are shown where the elastic moduli (G') 1302, 1402, 1502 cross the viscous moduli (G") 1304, 1404, 1504, respectively. FIG. 16 is a graph showing relative crossover times of IPCs having 6% PVP and 3% PAM with pH values of 7, 8, 9, 10, and 11.

[00103] A fourth example illustrates features of passive microrheology. Passive

microrheology can predict, for example, the elastic modulus (G') and viscous modulus (G") of a fluid based on a time dependency to a number of hours by a test performed in a matter of seconds or minutes. Additionally, highly acidic fluids can be analyzed by microrheology. A useful property of IPCs is that they can be formulated in strong acids to form gelled acids after exposure to time and temperature. An IPC formulation comprising 3% PVP, 6% PAM, and 0.25% T1O2 tracer at pH 1 was prepared using concentrated hydrochloric acid (HC1). The fluid was poured into a glass vial and loaded into a DWS backscattering system at 60 °C. Data acquisition then began. A sample of the same fluid was poured into a bottle and placed in an oven at 60 °C for visual observations. FIG. 17 is a graph showing the elastic modulus (G') 1702 and viscous modulus (G") 1704 of an IPC having 3% PVP, 6% PAM, and 0.25% T1O2 tracer at pH 1 tested at 1 Hz and 60 °C. While the viscous modulus (G") is relatively unchanged, the elastic modulus (G') increases sharply beyond the crossover time, which may be considered to be a representation of gelation time. The evolution of moduli captured by passive microrheology in this example was consistent with visual observations of the sample placed in the oven. Passive microrheology provides a straightforward measurement of gelation kinetics of acidic fluids.

[00104] FIGS. 18-20 are schematic views of at least respective portions of example implementations of wellsite systems in which in-line microrheology systems, such as passive microrheology systems, may be implemented. These example wellsite systems are illustrated to provide context for one or more aspects of the present disclosure, and various aspects of the present disclosure may be incorporated into other wellsite systems. Additionally, various modifications to the example wellsite systems may be made within the scope of the present disclosure.

[00105] FIG. 18 is a schematic view of at least a portion of an example implementation of a drilling system 1810 operable to drill a wellbore 1826 into one or more subsurface formations 1812. One or more aspects described above may be performed by or in conjunction with one or more aspects of the drilling system 1810 shown in FIG. 18.

[00106] A drilling rig 1814 at the wellsite surface 1816 is operable to rotate a drill string 1818 that includes a drill bit 1820 at its lower end. As the drill bit 1820 is rotated, a drilling fluid circulation system circulates drilling fluid through the drill string 1818. As illustrated in the drilling fluid circulation system, a pump 1822 pumps drilling fluid, such as oil-based mud (OBM) or water-based mud (WBM) in this example, through one or more conduits 1823 and downward through the center of the drill string 1818 in the direction of arrow 1824 to the drill bit 1820. The drilling fluid cools and lubricates the drill bit 1820 and exits the drill string 1818 through ports (not shown) in the drill bit 1820. The drilling fluid then carries drill cuttings away from the bottom of the wellbore 1826 as it flows back to the wellsite surface 1816 through an annulus 1830 between the drill string 1818 and the subsurface formation 1812, as shown by arrows 1828. At the wellsite surface 1816, the return drilling fluid is filtered and/or cleaned by one or more cleaning/filtering tools 1831, such as a shale shaker, a desander, a desilter, and/or a degasser, in the drilling fluid circulation system. The drilling fluid is then conveyed back to a mud pit 1832 for reuse. The drilling fluid circulation system can also include a mixer hopper 1833 that can mix an additive fluid or material with the returned drilling fluid in the mud pit 1832, such as to decrease the viscosity of the drilling fluid when the drilling fluid contains solid contaminant.

[00107] An in-line microrheology system 1850 is fluidly connected to the drilling fluid circulation system in the illustrated example drilling system 1810. As illustrated, the microrheology system 1850 is fluidly connected to the one or more conduits 1823, and in other examples, the microrheology system 1850 may be fluidly connected to the pump 1822, the mud pit 1832, another conduit, or the like. The microrheology system 1850 can be any of the systems 200, 300, 400, 500 of FIGS. 2-5 or another system. Using systems 200, 300, 400, 500 as examples, the flowline 220 may be fluidly connected to the one or more conduits 1823 such that the first control valve 222 is disposed between the one or more conduits 1823 and the Tee- coupling. Additionally, the microrheology system 1850 can include a processing system, such as the processing system 700 in FIG. 7, and can implement the method (100) of FIG. 1. One or more aspects of the processing system and/or performance of the method (100) can be distributed across one or more devices, including various surface equipment, such as logging and control unit 1844. In these examples, the microrheology system 1850 can obtain a sample of the drilling fluid from the drilling fluid circulation system and can determine rheological properties of the drilling fluid.

[00108] The lower end of the drill string 1818 includes a bottom -hole assembly (BHA) 1834, which includes the drill bit 1820 and a plurality of drill collars 1836, 1838. The drill collars 1836, 1838 may include various instruments, such as sample-while-drilling (SWD) tools that include sensors, telemetry equipment, and so forth. For example, the drill collars 1836, 1838 may include logging-while-drilling (LWD) modules 1840 and/or measurement-while drilling (MWD) modules 1842. The LWD modules 1840 may include tools operable to measure formation parameters and/or fluid properties, such as resistivity, porosity, permeability, sonic velocity, optical density (OD), pressure, temperature, rheological properties, and/or other example properties. The MWD modules 1842 may include tools operable to measure wellbore trajectory, borehole temperature, borehole pressure, and/or other example properties. The LWD modules 1840 may each be housed in one of the drill collars 1836, 1838, and may each contain one or more logging tools and/or fluid sampling devices. The LWD modules 1840 include capabilities for measuring, processing, and/or storing information, as well as for communicating with the MWD modules 1842 and/or with surface equipment such as, for example, a logging and control unit 1844. That is, the SWD tools (e.g., LWD modules 1840 and MWD modules 1842) may be communicatively coupled to the logging and control unit 1844 disposed at the wellsite surface 1816. In other implementations, portions of the logging and control unit 1844 may be integrated with downhole features. [00109] The LWD modules 1840 and/or the MWD modules 1842 may include a downhole formation fluid sampling tool operable to selectively sample fluid from the subsurface formation 1812. The drilling system 1810 may be operable to determine, estimate, or otherwise obtain various properties associated with the sampled formation fluid. These properties may be determined within or communicated to the logging and control unit 1844, such as for subsequent utilization as input to various control functions and/or data logs. For example, one or more of the LWD modules 1840 and/or the MWD modules 1842 can include a microrheology system to determine rheological properties of a formation fluid. Aspects of a microrheology system incorporated into a tool conveyed into a wellbore are described in further detail below, and one of ordinary skill in the art will readily understand the applicability of those details to a microrheology system incorporated into one or more of the LWD modules 1840 and/or the MWD modules 1842 of the drill string 1818 illustrated in FIG. 18.

[00110] While a drill string 1818 is illustrated in FIG. 18, it will be understood that implementations described herein may be applicable or readily adaptable to work strings and wireline tools as well. Work strings may include a length of tubing (e.g., coiled tubing) lowered into the wellbore 1826 for conveying well treatments or well servicing equipment. Wireline tools may include formation testing tools suspended from a multi -conductor cable as the cable is lowered into the wellbore 1826 to measure formation properties at depths.

[00111] The location and environment of the drilling system 1810 may vary depending on the subsurface formation 1812 penetrated by the wellbore 1826. Instead of being a surface operation, for example, the wellbore 1826 may be formed under water of varying depths, such as on an ocean bottom surface. Some components of the drilling system 1810 may be specially adapted for underwater wells in such instances.

[00112] FIG. 19 is a schematic diagram of an example implementation of downhole equipment (equipment configured for operation downhole) operable to sample fluid from a formation, such as the subsurface formation 1912 shown in FIG. 19. The downhole equipment includes an example implementation of a downhole formation fluid sampling tool 1918, hereinafter referred to as the downhole tool 1918. The downhole tool 1918 is conveyable within the wellbore 1914 to the subsurface formation 1912 and subsequently operable to sample formation fluid from the subsurface formation 1912. In the illustrated example implementation, the downhole tool 1918 is conveyed in the wellbore 1914 via a wireline 1920. The downhole tool 1918 may be suspended in the wellbore 1914 from a lower end of the wireline 1920, which may be a multi-conductor cable spooled from a winch 1922 at the surface. The wireline 1920 may be electrically coupled to wellsite surface equipment 1924, such as to communicate various control signals and logging information between the downhole tool 1918 and the wellsite surface equipment 1924. The wellsite surface equipment 1924 shown in FIG. 19 and the logging and control unit 1844 shown in FIG. 18, or functions thereof, may be integrated in a single system at the wellsite surface.

[00113] The downhole tool 1918 includes a probe module 1926, a pumpout module 1928, and an in-line microrheology module 1930, one or more of which may comprise, be part of, be substantially similar to, or otherwise have similar functionality relative to one or more of the SWD tools, LWD modules 1840, and/or MWD modules 1842 shown in FIG. 18 and/or described above. One or more additional modules 1946, such as a sampling module, a spectroscopy module, or other example modules, may be included in the downhole tool 1918. However, other arrangements and/or modules may make up the downhole tool 1918.

[00114] The probe module 1926 may comprise an extendable fluid communication line (probe 1932) operable to engage the subsurface formation 1912 and communicate fluid samples from the subsurface formation 1912 into the downhole tool 1918. The probe module 1926 may also comprise one or more setting mechanisms 1934. The setting mechanisms 1934 may include pistons and/or other apparatus operable to improve sealing engagement and thus fluid

communication between the subsurface formation 1912 and the probe 1932. The probe module 1926 may also comprise one or more packer elements (not shown) that inflate or are otherwise operable to contact an inner wall of the wellbore 1914, thereby isolating a section of the wellbore 1914 for sampling. The probe module 1926 may also comprise electronics, batteries, sensors, and/or hydraulic components used, for example, to operate the probe 1932 and/or the

corresponding setting mechanisms 1934.

[00115] The pumpout module 1928 may comprise a pump 1936 operable to create a pressure differential that draws the formation fluid in through the probe 1932 and pushes the fluid through a flowline 1938 of the downhole tool 1918. The pump 1936 may comprise an

electromechanical, hydraulic, and/or other type of pump operable to pump formation fluid from the probe module 1926 to the microrheology module 1930 and/or out of the downhole tool 1918. The pump 1936 may operate as a piston displacement unit (DU) driven by a ball screw coupled to a gearbox and an electric motor, although other types of pumps 1936 are also within the scope of the present disclosure. Power may be supplied to the pump 1936 via other components located in the pumpout module 1928, or via a separate power generation module (not shown).

[00116] In a continuous pumping mode, the pump 1936 moves the formation fluid into the downhole tool 1918 through the probe 1932, through the flowline 1938, and then out of the downhole tool 1918 through an exit port 1944. The exit port 1944 may be a check valve that releases the formation fluid into the annulus 1916 of the wellbore 1914. The downhole tool 1918 may operate in the continuous pumping mode until the formation fluid flowing through the flowline 1938 is determined to be clean enough for sampling. That is, when the formation fluid is first obtained from the subsurface formation 1912, drilling fluid filtrate that has been forced into the subsurface formation 1912 via the drilling operations may enter the downhole tool 1918 along with the obtained formation fluid. After pumping the formation fluid for an amount of time, the formation fluid flowing through the downhole tool 1918 will provide a cleaner fluid sample of the subsurface formation 1912 than would otherwise be available when first drawing fluid in through the probe 1932.

[00117] Once the formation fluid flowing through the downhole tool 1918 has been determined to be clean, a sampling period may begin. During the sampling period, the pump 1936 moves the formation fluid through the flowline 1938 toward the in-line microrheology module 1930. The in-line microrheology module 1930 includes at least a portion of an in-line microrheology system that is fluidly connected to the flowline 1938. The microrheology system of the in-line microrheology module 1930 can be any of the systems 200, 300, 400, 500 of FIGS. 2-5 or another system. Using systems 200, 300, 400, 500 as examples, the flowline 220 may be fluidly connected to the flowline 1938 such that the first control valve 222 is disposed between the flowline 1938 and the Tee-coupling. Additionally, the microrheology system can include a processing system, such as the processing system 700 in FIG. 7, and can implement the method (100) of FIG. 1. One or more aspects of the processing system and/or performance of the method (100) can be distributed across one or more devices, such as in the in-line microrheology module 1930, distributed between the in-line microrheology module 1930 and the surface equipment 1924, in the surface equipment 1924, or another configuration. In the sampling period, the in-line microrheology module 1930 can draw a fluid sample from the flowline 1938 into a cell of the microrheology system. In these examples, the microrheology system can obtain a sample of the formation fluid from the flowline 1938 and can determine rheological properties of the formation fluid. [00118] In some example implementations, a production rate of a formation fluid produced from the wellbore 1914 can be altered in response to one or more determined rheological properties of the formation fluid. For example, a production rate can be increased or decreased based on one or more rheological properties of the formation fluid.

[00119] FIG. 20 is a schematic view of at least a portion of an example implementation of an additive system 2000 at an oilfield wellsite that provides an example in which an in-line microrheology system may be implemented according to one or more aspects of the present disclosure. The oilfield wellsite can be a hydraulic fracturing wellsite or another wellsite. The figure depicts a wellsite surface 2002 adjacent to a wellbore 2004 and a partial sectional view of a subterranean formation 2006 penetrated by the wellbore 2004 below the wellsite surface 2002. The additive system 2000 may be operable to transfer an additive or other material from a source location to a destination location for blending or mixing with another additive or material and eventual injection into the wellbore 2004.

[00120] The additive system 2000 may comprise a first mixer 2008 connected with one or more first containers 2010 and a second container 2012. The second container 2012 may contain a first additive and the first containers 2010 may contain water or another liquid comprising water. When the additive system 2000 is operable as a fracturing system, the first additive may be or comprise a hydratable material or gelling agent, such as guar, a polymer, a synthetic polymer, a galactomannan, a polysaccharide, a cellulose, and/or a clay, among other examples, and the liquid may be or comprise an aqueous fluid, which may comprise water or an aqueous solution comprising water, among other examples. When the additive system 2000 is operable as a cementing system, the first additive may be or comprise cement powder.

[00121] The liquid may be transferred from the first containers 2010 to the first mixer 2008 by a first material transfer device 2014, such as may be driven by a first prime mover 2015. The first material transfer device 2014 may be or comprise a pump, while the first prime mover 2015 may be or comprise an electric motor, an engine, or another rotary actuator. The first additive may be transferred from the second container 2012 to the first mixer 2008 by a second material transfer device 2016, such as may be driven by a second prime mover 2017. The second material transfer device 2016 may be or comprise a conveyer, a bucket elevator, or a feeding screw, while the second prime mover 2017 may be or comprise an electric motor, an engine, or another rotary actuator. The first mixer 2008 may be operable to receive the first additive and the liquid via two or more conduits 2018, 2020, and mix or otherwise combine the first additive and the liquid to form a base fluid. The first mixer 2008 may then discharge the base fluid via one or more conduits 2022.

[00122] The first mixer 2008 and the second container 2012 may each be disposed on corresponding trucks, trailers, and/or other mobile carriers 2024, 2026, respectively, to permit their transportation to the wellsite surface 2002. However, the first mixer 2008 and/or second container 2012 may be skidded or otherwise stationary, and/or may be temporarily or

permanently installed at the wellsite surface 2002.

[00123] The additive system 2000 may further comprise a second mixer 2028 fluidly connected with the first mixer 2008 and a third container 2030. The third container 2030 may contain a second additive that may be substantially different than the first additive. When the additive system 2000 is operable as the fracturing system, the second additive may be or comprise a crosslinker, a proppant material, such as sand, sand-like particles, silica, quartz, and/or propping agents, among other examples. When the additive system 2000 is operable as the cementing system, the second additive may be or comprise accelerators, retarders, fluid-loss additives, dispersants, extenders, weighting agents, lost circulation additives and/or other chemicals or materials operable to modify the characteristics of the base fluid. The second additive may be a solid material (e.g., particulate material, powder) or a liquid.

[00124] The second additive may be transferred from the third container 2030 to the second mixer 2028 by a third material transfer device 203 1 driven by a third prime mover 2032. The third material transfer device 2031 may be or comprise a pump when the second additive is a liquid, or the third material transfer device 2031 may be or comprise a conveyer, a bucket elevator, or a feeding screw when the second additive is a solid material. The third prime mover 2032 may be or comprise an electric motor, an engine, or another rotary actuator. The second mixer 2028 may be operable to receive the base fluid from the first mixer 2008 via one or more conduits 2022, and a second additive from the third container 2030 via one or more conduits 2033, and mix or otherwise combine the base fluid and the second additive to form a mixture. The mixture may comprise a fracturing fluid when the additive system 2000 is operable as the fracturing system, or the mixture may comprise a cement slurry when the additive system 2000 is operable as the cementing system. The second mixer 2028 may then discharge the mixture via one or more conduits 2034.

[00125] The second mixer 2028 and the third container 2030 may each be disposed on corresponding trucks, trailers, and/or other mobile carriers 2036, 2038, respectively, to permit their transportation to the wellsite surface 2002. However, the second mixer 2028 and/or third container 2030 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite surface 2002.

[00126] An in-line microrheology system 2072 is fluidly connected to the one or more conduits 2034 in this example, although in other examples, the microrheology system 2072 may be fluidly connected to other conduits, mixers, containers, or the like. The microrheology system 2072 can be any of the systems 200, 300, 400, 500 of FIGS. 2-5 or another system. Using systems 200, 300, 400, 500 as examples, the flowline 220 may be fluidly connected to the one or more conduits 2034 such that the first control valve 222 is disposed between the one or more conduits 2034 and the Tee-coupling. Additionally, the microrheology system 2072 can include a processing system, such as the processing system 700 in FIG. 7, and can implement the method (100) of FIG. 1. One or more aspects of the processing system and/or performance of the method (100) can be distributed across one or more devices, including various surface equipment, such as in a control center 2070. In these examples, the microrheology system 2072 can obtain a sample of the fluid that is communicated through the one or more conduits 2034 to a fourth container 2040 and can determine rheological properties of the fluid.

[00127] The mixture may be communicated from the second mixer 2028 to the fourth container 2040, which may be or comprise a mixing, displacement, or storage tank for the mixture prior to being injected into the wellbore 2004. The mixture may be communicated from the fourth container 2040 to a common manifold 2042 via the one or more conduits 2044. The common manifold 2042 may comprise a combination of valves and/or diverters, as well as a suction line 2046 and a discharge line 2048, such as may be collectively operable to direct flow of the mixture in a selected or predetermined manner. The common manifold 2042, which may be known in the art as a missile or a missile trailer, may distribute the mixture to a pump fleet. The pump fleet may comprise multiple pump assemblies 2050 each comprising a pump 2052, a prime mover 2054, and a heat exchanger 2056. Each pump assembly 2050 may receive the mixture from the suction line 2046 of the common manifold 2042, via one or more conduits 2058, and discharge the mixture under pressure to the discharge line 2048 of the common manifold 2042, via one or more conduits 2060.

[00128] The pump assemblies 2050 may each be mounted on corresponding trucks, trailers, and/or other mobile carriers 2064, such as may permit their transportation to the wellsite surface 2002. However, the pump assemblies 2050 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite surface 2002.

[00129] The mixture may then be discharged from the common manifold 2042 into the wellbore 2004 via one or more conduits 2062, such as may include various valves, conduits, and/or other hydraulic circuitry fluidly connected between the common manifold 2042 and the wellbore 2004. During operations, the mixture and/or wellbore fluid may be ejected from the wellbore 2004 and communicated to a fifth container 2066 via one or more conduits 2068.

Although the additive system 2000 is shown comprising a fourth container 2040, it is to be understood that the fourth container 2040 may not be included as part of the additive system 2000, such that the mixture may be communicated from the second mixer 2028 directly to the common manifold 2042. The additive system 2000 may also omit the common manifold 2042, and the conduits 2060 may be fluidly connected to the wellbore 2004 via a wellhead (not shown) and/or other means.

[00130] The additive system 2000 may also comprise a control center 2070, which may be operable to monitor and control at least a portion of the additive system 2000 during operations. Signals may be communicated between the control center 2070 and other components of the additive system 2000 via a communication system including wired connections, wireless communication such as using an aerial mobile communication vehicle, or a combination of these. For example, the control center 2070 may be operable to monitor and/or control the production rate of the mixture, such as by increasing or decreasing the flow of the liquid from the first containers 2010, the first additive from the second container 2012, the base fluid from the first mixer 2008, the second additive from the third container 2030, and/or the mixture from the second mixer 2028.

[00131] Control signals may be communicated between the control center 2070 and other wellsite equipment units via electric conductors (not shown). Control signals may also be communicated between the control center 2070 and communication devices associated with the field personnel operating the wellsite equipment units via a communication path (e.g., a wireless communication path). Currently known and future-developed types of signal communication are within the scope of the present disclosure.

[00132] The control center 2070 may be disposed on a corresponding truck, trailer, cabin, and/or other mobile carrier 2071, such as may permit its transportation to the wellsite surface 2002. However, the control center 2070 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite surface 2002.

[00133] FIG. 20 depicts the additive system 2000 as being operable to transfer additives and produce mixtures that may be pressurized and injected into the wellbore 2004 during hydraulic fracturing or cementing operations. However, it is to be understood that the additive system 2000 may be operable to transfer other additives and produce other mixtures that may be pressurized and injected into the wellbore 2004 during other oilfield operations, such as drilling, gravel packing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples.

[00134] According to one or more aspects of the present disclosure, in-line microrheology analysis of a fluid generated at a wellsite can be used to control the generation of the fluid. One or more rheological properties of the fluid may be determined by the microrheology analysis. The rheological property can be compared to a set point, and when appropriate, the process control for generating the fluid can be adjusted in response to the comparison of the rheological property to the set point.

[00135] FIG. 21 is a flow-chart diagram of at least a portion of an example implementation of a method (2100) for generating a fluid according to one or more aspects of the present disclosure. The method (2100) may use in-line passive microrheology. The method (2100) may be performed at a wellsite and may be performed, at least in part, by a processing system, such as the processing system 700 of FIG. 7. The method (2100) may be used to obtain real-time data associated with a fluid, e.g., generated by surface processes and other examples, and to responsively adjust processing conditions or parameters relating to the fluid. The methods or processes described below are presented in a given order, although other implementations also within the scope of the present disclosure may comprise the described and/or other methods or processes in other orders and/or in parallel. Various other modifications to the methods or processes described below may also be consistent with the scope of the present disclosure. For example, such implementations may include additional or fewer calculations, determinations, computations, logic, monitoring, and/or other aspects.

[00136] The method (2100) includes performing (2102) a process to generate a fluid used at a wellsite. For example, in the system 1810 of FIG. 18, the process to obtain a drilling fluid, such as by an initial mixing and/or by filtering/cleaning during recirculation, may be considered a process to generate a fluid. Similarly, in the system 2000 of FIG. 20, a process to mix or combine constituent components to generate, for example, a cement slurry, a fracturing fluid, a stimulation fluid, or other example fluids may be considered a process to generate a fluid. Other fluids may be generated in the example systems or in different systems. A processing system, such as a processing system of the logging and control unit 1844 in the system 1810 of FIG. 18 and a processing system of the control center 2070 in the system 2000 of FIG. 20 may control the performance (2102) of the process that generates the fluid, for example.

[00137] The method (2100) comprises performing (2104) an in-line microrheology analysis on the fluid. The microrheology analysis can be a passive microrheology analysis. A

microrheology system may perform the microrheology analysis. For example, the

microrheology system 200, 300, 400, 500 of FIG. 2-5 may be used as the microrheology system, and in these examples, the flowline 220 is fluidly connected to an in-line flow of the fluid that is generated at the wellsite, such as described above in the context of the microrheology systems 1850, 2072 of FIGS. 18 and 20. The microrheology system further includes a processing system, such as the processing system 700 of FIG. 7.

[00138] The microrheology system can perform the method (100) of FIG. 1, as described above, to perform (2104) the in-line microrheology analysis. In the context of the systems 1810, 2000 of FIGS. 18 and 20 as examples, the microrheology system 1850, 2072 obtains a fluid sample from the one or more conduit 1823, 2034, respectively, such as through the flowline 220 and using the first control valve 222 to capture the fluid sample in the cell 202 as previously described. If used, tracer particles can be added to the fluid sample by the microrheology system 200, 300, 400, 500 as previously described. The processing system, such as the processing system 700, obtains an MSD of particles in the fluid sample, such as by using a light source 208 and detector 210, 302, 402, and/or an imaging device 502, and obtains rheological properties of the fluid sample as previously described.

[00139] The method (2100) further includes comparing (2106) one or more rheological properties determined by the performance (2104) of the in-line microrheology analysis to a set point. The set point may be a target characteristic of the fluid for the application for which it is used. One or more set points may be stored in a database. The database may be maintained in a non-transitory, tangible storage medium and operated by a processing system. The database may be maintained and operated as part of the processing system of the microrheology system and/or as part of a processing system separate from the microrheology system. The set point may be maintained in the database and accessed from the database using any currently known and future-developed techniques, which are within the scope of the present disclosure. Accessing the set point from the database may further include any currently known and future-developed communication techniques, such as by wired and/or wireless communication and using any communication protocol.

[00140] The comparison (2106) may be performed by the processing system of the microrheology system that performed (2104) the microrheology analysis in some examples. In other examples, a processing system different from the processing system of the microrheology system may perform the comparison (2106). For example, a processing system of the control center 2070 in the system 2000 of FIG. 21 may receive the rheological properties from the microrheology system 2072 and compare the received rheological properties with a set point. Other configurations and/or processing systems performing various functions are within the scope of the present disclosure.

[00141] The method (2100) includes adjusting (2108) the process for generating the fluid based on the comparison (2106). Example processing parameters that can be changed in different wellsite systems include additive concentration, water amount, pH, hydration time, and other example parameters. The determination for the adjustment (2108) can be based on, for example, one or more functions of one or more rheological properties (e.g., that was compared (2106)) based on one or more processing parameters of the fluid. For example, a database can contain a data set of multiple fluid samples for a type of fluid having varying characteristics, such as concentrations of various chemicals or solutions, pH of the fluid, etc. A function, such as a polynomial fit, may be determined from the data set to obtain one or more rheological properties as a function of the one or more processing parameters. If the compared rheological properties are not at the set point or target level, the function can indicate which processing parameter to change, and by what amount, to bring the rheological properties of subsequently generated fluid closer to the set point.

[00142] The method (2100) continues with performing (2102) the process to generate the fluid based on the adjustment (2108) of the process. The processing system, such as a processing system of the logging and control unit 1844 in the system 1810 of FIG. 18 and a processing system of the control center 2070 in the system 2000 of FIG. 20, that controls the performance (2102) of the process that generates the fluid may also adjust (2108) the process, although other systems may adjust the process, as is within the scope of the present disclosure. Various examples are provided below to illustrate different fluids, set points, and comparisons that may be implemented.

[00143] A first example includes analyzing fracturing fluids comprising guar solutions of different concentrations. The fracturing fluids can be generated and analyzed at a wellsite having the system 2000 of FIG. 20, for example. Raw MSD curves of guar solutions with different concentrations are shown in FIG. 22. FIG. 22 illustrates a raw MSD 2202 with a guar concentration of 30 ppt, a raw MSD 2204 with a guar concentration of 60 ppt, and a raw MSD 2206 with a guar concentration of 85 ppt. The MSDs for these guar solutions with different concentrations are largely different from each other. No clear plateau emerges for guar solution having a concentration less than 60 ppt. Viscosity vs shear rate functions for different concentrations are shown in FIG. 23. FIG. 23 illustrates a function 2302 with a guar

concentration of 30 ppt, a function 2304 with a guar concentration of 60 ppt, and a function 2306 with a guar concentration of 85 ppt. The viscosity is calculated from complex modulus by frequency sweep based on Cox-Merz rule. The viscosity increases with guar concentration, and it follows power law at different concentrations.

[00144] For in-line process control of the fluid, after the fluid is mixed or during the mixing, it is introduced into the microrheology system for measurement, and the results can be obtained in a range from about 0.001 s to about 1,000 s. The results are compared with the setpoint at fixed shear rate, for example, from the database of data as shown in FIG. 23. If the rheological properties of the fluid do not match the setpoint, the added amount of guar/water is calculated by using a calibration curve, for example, the calibration curve 2402 in the graph of FIG. 24, to ensure the viscosity of the base fluid can reach the setpoint.

[00145] Another example includes analyzing drilling mud to determine a contamination level. Effects of solid contamination in drilling mud can be distinguished, as shown in FIG. 25, for example. FIG. 25 illustrates a raw MSD curve 2502 of mud without contamination, a raw MSD curve 2504 of mud with 7.6% solid contamination, a raw MSD curve 2506 of mud with 11.5% solid contamination, and a raw MSD curve 2508 of mud with 15.2% solid contamination. The MSD curves shift downward and the slope of MSD decreases with addition of solid contaminate indicating an increase of both viscosity and elasticity. Mud without solid contaminant has a lower macroscopic viscosity index (MVI) than the mud with solid contaminant, as shown in FIG. 26. FIG. 26 is a graph of MVI of mud as a function of solid contamination concentration. FIG. 26 illustrates raw, real data points 2604 fitted with a fitted curve of MVI 2602. By monitoring the MVI for mud sample from microrheology inline, the solid contaminate in mud sample can be determined from a calibration curve (e.g., the fitted curve of MVI 2602), and the additives can, in response, be added to mitigate the effect of solid contamination increasing the drilling mud viscosity.

[00146] A further example includes analyzing a cement slurry for hydration. For cement samples, the MSD curve measured by microrheology can capture early gelation process, and different parameters extracted from the raw MSD curves can be used to provide insightful information about cement hydration and effects of different additives. Example effects of retarder concentrations are shown in FIGS. 27 and 28, and is identified at very early stage of cement hydration. FIG. 27 illustrates a fitted curve of MVI 2702 fitted to raw, real data points 2704 of cement samples as a function of retarder concentration. FIG. 28 illustrates a fitted curve of elastic index (EI) 2802 fitted to raw, real data points 2804 of cement samples as a function of retarder concentrations. The addition of retarder reduced MVI but increased EI during early cement hydration. For inline process control, by comparing the MVI and/or EI value (e.g., measured EI EI _m in FIG. 28) with a set point (e.g., set point EI EI _se t in FIG. 28) from in-line microrheology analysis, the amount of added retarder can be calculated (such as by difference between the concentration at the measured EI C _m and the concentration at the set point EI C _a dd

[00147] In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art should readily recognize that the present disclosure introduces a method comprising: obtaining a sample of a fluid at a wellsite, wherein the fluid is either a well treatment fluid used at the wellsite for an oilfield production or a formation fluid; and obtaining a rheological property of the fluid by performing a microrheology analysis on the sample.

[00148] The fluid may be the well treatment fluid, and may be selected from the group consisting of a stimulation fluid, a cementing fluid, a spacer fluid, a drilling fluid, a completion fluid, a gravel packing fluid, and a water control fluid.

[00149] The microrheology analysis may be a passive microrheology analysis. The microrheology analysis may use one or more of diffusing wave spectroscopy (DWS)

backscattering, diffusing wave spectroscopy (DWS) transmission, dynamic light scattering (DLS), and/or video particle tracking (VPT). [00150] The method may further comprise dispersing tracer particles in the sample before performing the microrheology analysis on the sample, wherein the microrheology analysis analyzes movement of the tracer particles. The tracer particles may be selected from the group consisting of polystyrene beads, titanium dioxide beads, silica, and a combination thereof. The fluid may be transparent.

[00151] The microrheology analysis may analyze movement of particles intrinsic in the fluid. In such implementations, among others within the scope of the present disclosure, the fluid may be opaque, translucent, turbid, or a combination thereof.

[00152] Performing the microrheology analysis may comprise: directing light from a light source towards the sample; collecting, by a detector, a signal in response to the light being scattered by the sample; and operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the detector and calculating the rheological property based on the signal. The signal may be in response to light that is reflected back from the sample, light that is transmitted through the sample, and/or light that is reflected once at an angle through the sample.

[00153] Performing the microrheology analysis may comprise: (A) generating, by an imaging device, a signal capturing particle displacement as a function of time; and (B) operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the imaging device, tracking particle displacement as a function of time, and calculating the rheological property based on the particle displacement as a function of time.

[00154] The rheological property may be at least one of a mean squared displacement (MSD), a viscoelastic modulus (G*), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), an elastic index (EI), or a macroscopic viscosity index (MVI).

[00155] The method may further comprising, based on the rheological property, adjusting one or both of (i) a property of the fluid and/or (ii) concentrations of components in the fluid.

[00156] The present disclosure also introduces a method comprising: generating a well treatment fluid at a wellsite, wherein the generating is controlled by process parameters;

transmitting the well treatment fluid along a flow path; obtaining a sample of the well treatment fluid at a microrheology system, wherein the microrheology system is fluidly connected to the flow path; obtaining a rheological property of the well treatment fluid by performing a microrheology analysis on the sample using the microrheology system; comparing the rheological property of the well treatment fluid to a set point; and adjusting one or more of the process parameters based on the comparing the rheological property to the set point.

[00157] Generating the well treatment fluid at the wellsite may comprise filtering a spent drilling fluid to form a filtered drilling fluid. Generating the well treatment fluid may further comprise mixing an additive with the filtered drilling fluid.

[00158] Generating the well treatment fluid may comprise mixing components.

[00159] The flow path may include a conduit, wherein the microrheology system is fluidly connected to the conduit, and wherein the sample is obtained from the conduit.

[00160] The microrheology system may be a passive microrheology system, and the microrheology analysis may be a passive microrheology analysis.

[00161] The microrheology analysis may use at least one of diffusing wave spectroscopy (DWS) backscattering, DWS transmission, dynamic light scattering (DLS), and/or video particle tracking (VPT).

[00162] The method may further comprise dispersing tracer particles in the sample before performing the microrheology analysis on the sample, wherein the microrheology analysis may analyze movement of the tracer particles. The tracer particles may include polystyrene beads and/or titanium dioxide beads. The well treatment fluid may be transparent.

[00163] The microrheology analysis may analyze movement of particles intrinsic in the well treatment fluid. In such implementations, the well treatment fluid may be opaque, translucent, turbid, or a combination thereof.

[00164] Performing the microrheology analysis may comprise: directing light from a light source towards the sample; generating, by a detector, a signal in response to the light being scattered by the sample; and operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the detector and calculating the rheological property based on the signal. The signal may be in response to light that is reflected back from the sample, light that is transmitted through the sample, and/or light that is reflected once at an angle through the sample.

[00165] Performing the microrheology analysis may comprise: generating, by an imaging device, a signal capturing particle displacement as a function of time; and operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the imaging device, tracking particle displacement as a function of time, and generating the rheological property based on the particle displacement as a function of time.

[00166] The rheological property may be at least one of a mean squared displacement (MSD), a viscoelastic modulus (G*), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), an elastic index (EI), and/or a macroscopic viscosity index (MVI).

[00167] Adjusting one or more of the process parameters may modify an additive

concentration, a pH, water concentration, a hydration time, or a combination thereof of a subsequently generated fluid relative to the fluid.

[00168] The method may further comprise operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises the comparison of the rheological property to the set point and the adjustment of the one or more of the process parameters, and wherein the processing system controls the generation of the well treatment fluid.

[00169] The present disclosure also introduces an apparatus comprising: a system configured to generate a well treatment fluid according to process control parameters; a flow path fluidly connected to the system, wherein the system fluidly communicates the well treatment fluid along the flow path, and wherein the flow path is configured to fluidly communicate the well treatment fluid down a wellbore at a wellsite; a microrheology system fluidly connected to the system or the flow path, wherein the microrheology system is configured to obtain a sample of the well treatment fluid from the system or the flow path and to perform a microrheology analysis on the sample to obtain a rheological property of the well treatment fluid; and a control system configured to compare the rheological property of the well treatment fluid with a set point and adjust one or more of the process control parameters in response to the comparison of the rheological property with the set point.

[00170] The system may be configured to filter a spent drilling fluid circulated from the wellbore and form a filtered drilling fluid. In such implementations, among others within the scope of the present disclosure, the system may be configured to mix an additive with the filtered drilling fluid.

[00171] The system may be a mixing system configured to mix components from separate containers to form the well treatment fluid.

[00172] The flow path may include a conduit, wherein the microrheology system is fluidly connected to the conduit, and wherein the sample is obtained from the conduit. [00173] The microrheology system may be a passive microrheology system, and the microrheology analysis may be a passive microrheology analysis.

[00174] The microrheology analysis may use at least one of diffusing wave spectroscopy (DWS) backscattering, DWS transmission, dynamic light scattering (DLS), and/or video particle tracking (VPT).

[00175] The microrheology system may comprise: a transparent cell operable to hold the sample; a laser light source disposed to direct laser light along a direction towards the transparent cell; a detector disposed to receive at least some of the laser light incident on the sample in the transparent cell and configured to generate a signal in response to the received light; and a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to receive the signal from the detector and generate the rheological property based on the signal. The detector may be disposed to receive at least some laser light that is reflected back from the sample. The detector may be disposed to receive at least some laser light that is transmitted through the sample, and disposed to intersect the direction. The detector may be disposed to receive at least some laser light that is transmitted through the sample, and disposed to off-axis from the direction.

[00176] The microrheology system may comprise: a transparent cell operable to hold the sample; an imaging device disposed to view the sample in the transparent cell and configured to generate a signal representing particle displacement in the sample as a function of time; and a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to receive the signal from the imaging device, track particle displacement in the sample as a function of time, and generate the rheological property based on the particle displacement in the sample as a function of time.

[00177] The rheological property may be at least one of a mean squared displacement (MSD), a viscoelastic modulus (G*), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), an elastic index (EI), and/or a macroscopic viscosity index (MVI).

[00178] Adjusting one or more of the process control parameters may modify an additive concentration, a pH, water concentration, a hydration time, or a combination thereof of a subsequent fluid generated by the system relative to the well treatment fluid.

[00179] The control system may comprise a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to compare the rheological property to the set point and adjust one or more of the process control parameters, and wherein the processing system is operable to control the system.

[00180] The present disclosure also introduces a method comprising: conveying a tool down a wellbore in a formation; obtaining, by the tool in the wellbore, a sample of a fluid present in the formation selected from the group consisting of a well treatment fluid, a formation fluid, or a combination thereof; and obtaining, while the tool is in the wellbore, a rheological property of the fluid by performing a microrheological analysis on the sample.

[00181] The method may further comprise altering a production rate of the fluid from a zone in the wellbore based on the rheological property, wherein the fluid is the formation fluid.

[00182] The tool may be conveyed down the wellbore using a wireline, coiled tubing, or as a part of a drill string.

[00183] Obtaining the sample may comprise: engaging a probe of the tool in the formation; pumping the fluid through the probe and through a flowline in the tool; and fluidly

communicating the sample from the flowline to a cell.

[00184] The microrheology analysis may be a passive microrheology analysis.

[00185] The microrheology analysis may use at least one of diffusing wave spectroscopy (DWS) backscattering, DWS transmission, dynamic light scattering (DLS), and/or video particle tracking (VPT).

[00186] The method may further comprise dispersing tracer particles in the sample before performing the microrheology analysis on the sample, wherein the microrheology analysis analyzes movement of the tracer particles. The tracer particles may include polystyrene beads and/or titanium dioxide beads.

[00187] The microrheology analysis may analyze movement of particles intrinsic in the formation fluid.

[00188] Performing the microrheology analysis may comprise: (A) in the tool while the tool is in the wellbore: (1) directing light from a light source towards the sample; and (2) generating, by a detector, a signal in response to the light being scattered by the sample; and (B) operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the detector and generating the rheological property based on the signal. The signal may be in response to light that is reflected back from the sample, light that is transmitted through the sample, and/or light that is reflected once at an angle through the sample. Operating the processing system may be performed in the tool while the tool is in the wellbore. Operating the processing system may be performed in surface equipment while the tool is in the wellbore.

[00189] Performing the microrheology analysis may comprise: in the tool while the tool is in the wellbore, generating, by an imaging device, a signal capturing particle displacement as a function of time; and operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises receiving the signal from the imaging device, tracking particle displacement as a function of time, and generating the rheological property based on the particle displacement as a function of time. In such implementations, among others within the scope of the present disclosure, operating the processing system may be performed in the tool while the tool is in the wellbore, or operating the processing system may be performed in surface equipment while the tool is in the wellbore.

[00190] The rheological property may be at least one of a mean squared displacement (MSD), a viscoelastic modulus (G*), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), an elastic index (EI), and/or a macroscopic viscosity index (MVI).

[00191] The present disclosure also introduces an apparatus comprising: (A) a downhole tool capable of being conveyed down a wellbore in a formation, wherein the downhole tool comprises: (1) a probe module configured to engage the formation to communicate a fluid present in the formation selected from the group consisting of a well treatment fluid, a formation fluid, or a combination thereof to the downhole tool; (2) a flowline extending from the probe module and configured to communicate the fluid through the downhole tool; and (3) a microrheology module configured to obtain a sample of the fluid from the flowline; and (B) a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to obtain a rheological property of the fluid by performing a microrheology analysis on the sample.

[00192] The downhole tool may be configured to be conveyed down the wellbore using a wireline, coiled tubing, or as part of a drill string.

[00193] The microrheology module may include a passive microrheology configuration, and the microrheology analysis may be a passive microrheology analysis.

[00194] The microrheology analysis may use at least one of diffusing wave spectroscopy (DWS) backscattering, DWS transmission, dynamic light scattering (DLS), and/or video particle tracking (VPT). [00195] The microrheology module may comprise: a transparent cell operable to hold the sample; a laser light source disposed to direct laser light along a direction towards the transparent cell; and a detector disposed to receive at least some of the laser light scattered by the sample in the transparent cell and configured to generate a signal in response to the received light. In such implementations, among others within the scope of the present disclosure, the processing system may be operable to receive the signal from the detector and generate the rheological property based on the signal. The detector may be disposed to receive at least some laser light that is reflected back from the sample. The detector may be disposed to receive at least some laser light that is transmitted through the sample, and may be disposed to intersect the direction. The detector may be disposed to receive at least some laser light that is transmitted through the sample, and may be disposed to off-axis from the direction.

[00196] The microrheology module may comprise: a transparent cell operable to hold the sample; and an imaging device disposed to view the sample in the transparent cell and configured to generate a signal representing particle displacement in the sample as a function of time. In such implementations, among others within the scope of the present disclosure, the processing system may be operable to: receive the signal from the imaging device; track particle displacement in the sample as a function of time; and generate the rheological property based on the particle displacement in the sample as a function of time.

[00197] The rheological property may be at least one of a mean squared displacement (MSD), a viscoelastic modulus (G*), an elastic modulus (G'), a viscous modulus (G"), viscosity (η), an elastic index (EI), and/or a macroscopic viscosity index (MVI).

[00198] The processing system may be disposed in the microrheology module or surface equipment.

[00199] The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. [00200] The Abstract at the end of this disclosure is provided to permit 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.