WO2011153339A1 - Magnetic particles for determining reservoir parameters - Google Patents

Magnetic particles for determining reservoir parameters Download PDF

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Publication number
WO2011153339A1
WO2011153339A1 PCT/US2011/038912 US2011038912W WO2011153339A1 WO 2011153339 A1 WO2011153339 A1 WO 2011153339A1 US 2011038912 W US2011038912 W US 2011038912W WO 2011153339 A1 WO2011153339 A1 WO 2011153339A1
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magnetic
reservoir
magnetic particles
method
embodiments
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PCT/US2011/038912
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French (fr)
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David K. Potter
Andrew R. Barron
Samuel J. Maguire-Boyle
Alvin W. Orbaek
Arfan Ali
Lauren Harrison
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William Marsh Rice University
University Of Alberta
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    • GPHYSICS
    • G01MEASURING; TESTING
    • G01VGEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS
    • G01V3/00Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/08Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation operating with magnetic or electric fields produced or modified by objects or geological structures or by detecting devices
    • G01V3/087Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation operating with magnetic or electric fields produced or modified by objects or geological structures or by detecting devices the earth magnetic field being modified by the objects or geological structures
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02ATECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
    • Y02A90/00Technologies having an indirect contribution to adaptation to climate change
    • Y02A90/30Assessment of water resources
    • Y02A90/34Hydrogeology; Hydrogeophysics
    • Y02A90/344Hydrogeology; Hydrogeophysics by measuring magnetic field strength

Abstract

A parameter of a reservoir, such as an oil, gas, or water reservoir, is determined by measuring a magnetic susceptibility of magnetic particles added to the reservoir, and then correlating the measured magnetic susceptibility to at least one value associated with a parameter of the reservoir. The correlating process compares predetermined parameter information that is a function of magnetic susceptibility to the measured magnetic susceptibility to determine at least one value that is associated with the at least one parameter of the reservoir. The reservoir parameters may include fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy. In some embodiments, the magnetic particles contain manganese or zinc doped iron-oxide particles.

Description

TITLE

MAGNETIC PARTICLES FOR DETERMINING RESERVOIR PARAMETERS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. Provisional Patent Application No. 61/350,828, filed on June 2, 2010, which is hereby incorporated by reference.

BACKGROUND INFORMATION

[0002] Various methods and apparatus exist for obtaining information on various parameters in a reservoir. However, current methods and apparatus for determining such parameters have numerous limitations. Such limitations include measurement speed, measurement accuracy, and high costs. These limitations necessitate the development of new methodologies and apparatus for characterizing various reservoir parameters.

BRIEF SUMMARY

[0003] Embodiments of the present invention determine at least one value associated with at least one parameter of a reservoir (e.g., oil, gas, water) by measuring a magnetic susceptibility of magnetic particles added to the reservoir, and then correlating the measured magnetic susceptibility to at least one value associated with a parameter of the reservoir.

[0004] In various embodiments, the correlating process compares predetermined parameter information that is a function of magnetic susceptibility to the measured magnetic susceptibility to determine at least one value that is associated with the at least one parameter of the reservoir. In some embodiments, the reservoir parameters may include fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy. [0005] In some embodiments, the magnetic particles comprise magnetic nanoparticles. In some embodiments, the magnetic particles comprise proppant containing magnetic particles. In some embodiments, the magnetic particles comprise the following formula: MxM'yFe204, where x + y = 1, and where M or M' may comprise at least one of zinc, manganese, cobalt, copper, or vanadium. In some embodiments, the magnetic particles comprise at least one of the following formulas: Mn0.5Zn0.5Fe2O4, Mn0.65Zn0.35Fe2O4, and Mn0.iZn0.9Fe2O4.

[0006] Additional aspects of the present invention pertain to methods for making magnetic particles, such as proppant containing magnetic particles. Further embodiments of the present invention pertain to the above-described magnetic particles.

[0007] The methods and magnetic particles of the present invention have numerous applications and advantages. For instance, in some embodiments, the methods and particles may be utilized to determine the efficacy of a hydraulic fracturing. In additional embodiments, the methods and magnetic particles may be utilized to determine a three-dimensional view of the reservoir.

BRIEF DESCRIPTION OF THE FIGURES

[0008] FIG. 1A is a diagram illustrating a process for determining values associated with reservoir parameters.

[0009] FIG. IB is a diagram illustrating a process for determining values associated with fluid permeability in a reservoir before and after hydraulic fracturing.

[0010] FIG. 2 is a graph of metal concentration ratios of iron-copper nanoparticles.

[0011] FIG. 3 is a scanning electron micrograph (SEM) of an unmodified Arizona sand surface.

[0012] FIG. 4 is a SEM of a 1 : 1 Fe nanoparticle:Polyethylenimine (PEI) aqueous solution that was coated at a pH of approximately 1.75 and dried on a surface of Arizona sand at approximately 60°C for approximately 12 hours. [0013] FIG. 5 is a SEM of a coating of 1 : 1 Fe nanoparticle:PEI aqueous solution that was coated at a pH of approximately 4 and dried on a surface of Arizona sand at approximately 60°C.

[0014] FIG. 6 is a SEM of a coating of a 1 : 1 Fe nanoparticle:PEI aqueous solution at a pH of approximately 7 that was dried on a surface of Arizona sand at approximately 60°C.

[0015] FIG. 7 is a SEM of a 1 : 1 Fe nanoparticle:PEI solution at a pH of approximately 9.36 that was coated and dried on a surface of Arizona sand.

[0016] FIG. 8 is a SEM of a 1 : 1 Fe nanoparticle:PEI solution at a pH of approximately 11.8 that was coated and dried on a surface of Arizona sand.

[0017] FIG. 9 is an example of an expected graph of detected concentrations of magnetic nanoparticles or proppant coated magnetic nanoparticles as a function of time after continuous pumping into low permeability rocks and high permeability rocks.

[0018] FIG. 10 is a theoretical graph of detected concentrations of magnetic nanoparticles or proppant coated magnetic nanoparticles as a function of time after the injection of a pulse of the magnetic materials through low permeability rocks, moderate permeability rocks and high permeability rocks.

[0019] FIG. 11 shows schematic representations of various particles that are suitable for use in embodiments of the present invention. Specifically, FIG. 11A shows a schematic representation of a functionalized nanoparticle with functional groups "X" on its surface. FIG. 11B shows a schematic representation of the nanoparticle in FIG. 11A that also contains a protective coating layer that inhibits the reaction of the nanoparticle with hydrogen sulfide or other sulfur containing species.

[0020] FIG. 12 is a low field magnetic susceptibility of various reservoir minerals and fluids.

[0021] FIG. 13 is a digital photograph of a variable field translation balance (VFTB) for determining magnetic hysteresis curves at room temperature and reservoir temperatures. [0022] FIG. 14 shows magnetic hysteresis measurements at room temperature and reservoir temperatures for spinel ferrite P37.

[0023] FIG. 15 shows magnetic hysteresis measurements at room temperature and reservoir temperatures for spinel ferrite P36.

[0024] FIG. 16 shows magnetic hysteresis measurements at room temperature and reservoir temperatures for spinel ferrite P42.

[0025] FIG. 17 is a digital photograph of simulated borehole samples.

[0026] FIG. 18 is a digital photograph of a low field downhole magnetic susceptibility probe.

[0027] FIG. 19 shows a powder X-ray diffraction pattern of a Mn0.iZn0.9Fe2O4 oleylic acid coated nanoparticle.

DETAILED DESCRIPTION

[0028] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only, and are not restrictive of the invention, as claimed. In this application, the use of the singular includes the plural, the word "a" or "an" means "at least one", and the use of "or" means "and/or", unless specifically stated otherwise. Furthermore, the use of the term "including", as well as other forms, such as "includes" and "included", is not limiting. Also, terms such as "particle," "element," and "component" encompass particles, elements, and components, respectively, comprising one unit, and particles, elements, and components that comprise more than one unit, unless specifically stated otherwise.

[0029] The section headings used herein are for organizational purposes only and are not to be construed as limiting the subject matter described. All documents, or portions of documents, cited in this application, including, but not limited to, patents, patent applications, articles, books, and treatises, are hereby expressly incorporated herein by reference in their entirety for any purpose. In the event that one or more of the incorporated literature and similar materials defines a term in a manner that contradicts the definition of that term in this application, this application controls.

[0030] In order to maximize the recovery of oil, gas, or water from reservoirs (e.g., subterranean formations), it desirable to obtain information on various parameters in the reservoir, including flow characteristics or porosity of the rocks within the reservoir. For instance, information on the permeability of a reservoir can be used to determine whether hydraulic fracturing is required, or if it has been successfully implemented.

[0031] Reservoir characterization methodologies may include determining reservoir architecture, establishing fluid-flow trends, constructing reservoir models, and identifying reserve growth potential. However, current methods for making such characterizations have numerous limitations that necessitate the development of new methodologies.

[0032] For instance, permeability measurements are usually made directly on core samples. These direct measurements generally require that the samples be isolated, cleaned, and analyzed by various methods. Such steps can take several days or weeks. Furthermore, since cutting and processing the core samples are costly, permeability measurements are generally performed only on a fraction of the wells drilled.

[0033] Moreover, many rocks and reservoir components have limited permeability that in turn provides further impediments to characterization. For instance, shales ordinarily have insufficient permeability to allow significant fluid flow into a well bore.

[0034] Some broader techniques have been used to predict and characterize reservoir component permeability. Examples of such techniques include nuclear magnetic resonance (NMR) imaging and seismic measurements. However, such techniques are relatively complicated and costly. Furthermore, such techniques generally rely on a close correlation between pore size distribution and permeability.

[0035] More invasive methods for characterizing the fractured formation properties of reservoirs also have limitations. For example, Nguyen et al. (U.S. Patent Publication No. 2005/0274510A1) describes the use of a conductive polymer and/or conductive filler phase in a polymer-coated proppant to determine these parameters via an electric field based remote sensing procedure. In another example, Ayoub et al. (U.S. Patent No. 7,083,993 B2) makes use of either active or passive devices to characterize the fracture parameters. Likewise, McCarthy et al. (U.S. Patent Publication No. 2006/0102345A1) describes a proppant tracking and fracture zone characterization material. However, the aforementioned methods may harm the reservoir or require significant alteration of present processes. Furthermore, the low porosity and permeability of many reservoirs (even after hydraulic fracturing) may make the aforementioned methods ineffective or impractical.

[0036] As such, nanoparticles have represented a potential sensor material for characterizing various reservoir parameters. The special electrical and magnetic properties of certain nanomaterials make them well suited for use as injected sensors and contrast agents. For instance, the magnetic field of certain nanoparticles has been measured in reservoirs during water floods or hydraulic fracturing. However, such methods also present numerous issues.

[0037] An issue is that many rock formations are themselves magnetic. For instance, ferrimagnetic oxides (such as magnetite) are strongly magnetic. Even some paramagnetic reservoir minerals (e.g., siderite, ilmenite, chamosite, leppidocrocite, and chlorite) can be significantly more magnetic than certain nanoparticles. Therefore, in order to detect the magnetic field of a specific nanoparticle in the presence of a magnetic rock, a high concentration of such nanoparticles should be used. However, without a knowledge of the rock composition in a reservoir, it would be difficult to determine the concentration and hence distribution of such nanoparticles.

[0038] Another issue involves the actual measurement of the magnetic field. For instance, magnetic measurements, much like downhole NMR measurements, are generally limited to near the borehole. Thus, such detection limitations do not allow for the characterization of an entire reservoir. [0039] Accordingly, magnetic susceptibility measurements can provide a better method of imaging a reservoir. For instance, methods for determining one or more parameters of a rock sample by measuring the magnetic susceptibility of the sample and determining a value of the parameter using that measured susceptibility has been reported. See, e.g., D. K. Potter, Magnetic susceptibility as a rapid, non-destructive technique for improved petrophyical parameter prediction, Petrophysics, 2007, 48, 191. Also see O. P. Ivakhnenko and D. K., Potter, The use of magnetic hysteresis and remanence measurements for rapidly and non-destructively characterizing reservoir rocks and fluids, Petrophysics, 2008, 49, 47. Also see D. K. Potter et al, U.S. Patent No. 7,439,743.

[0040] However, the aforementioned methods were generally aimed at measuring the magnetic susceptibility of the reservoir rock. In fact, magnetic susceptibility measurements are not routinely performed in the petroleum industry (either in core analysis laboratories, downhole in wireline logging, or in measurements while drilling (MWD) operations). As such, the information obtained by such methods is generally limited to a local region around the well bore for downhole measurements (or core samples for ex situ measurements). Information deeper into the reservoir would be of greater value.

[0041] Thus, the present invention aims to improve on the above-mentioned methods of characterizing various parameters in a reservoir. In particular, Applicants have found that if the magnetic susceptibility of magnetic particles is measured within a reservoir, it is possible to detect magnetic particles at much lower concentrations with greater accuracy. Thus, embodiments of the present invention use a novel technique to detect nanoparticles within reservoirs in order to characterize various parameters within the reservoirs.

[0042] Specifically, some embodiments of the present invention pertain to methods for determining at least one value that is associated with at least one parameter of a reservoir by measuring the magnetic susceptibility of magnetic particles within the reservoir and correlating the measured magnetic susceptibility to values that are associated with various parameters of the reservoir. Some embodiments of the present invention pertain to methods for making magnetic particles that can be utilized in accordance with the methods of the present invention. Some embodiments of the present invention pertain to the magnetic particles.

[0043] Reservoir Parameter Analysis

[0044] FIG. 1A illustrates a process for determining at least one value that is associated with at least one parameter of a reservoir. In step 101, magnetic particles as disclosed herein are added to a reservoir. For example, the magnetic particles may be pumped with another fluid into a mineral formation via a new or existing well bore, such as drilling mud or hydraulic fracturing fluid. In step 102, after a selected time period in which the magnetic particles have been injected into the mineral formation, magnetic susceptibility measurements are made of the magnetic particles residing in the mineral formation. In step 103, the magnetic susceptibility measurements are collected and correlated with magnetic susceptibility values associated with one or more reservoir parameters of interest. Such a correlation process may compare the magnetic susceptibility measurements to predetermined magnetic susceptibility data and its associated parameter information (step 104). Using this comparison, in step 105, at least one parameter value is determined for the mineral formation based on the magnetic susceptibility measurements. For example, predetermined data may provide that a certain magnetic susceptibility value indicates that a certain reservoir parameter value exists in the mineral formation. A comparison of the magnetic susceptibility measurements to the predetermined data would then indicate that the mineral formation exhibits a certain parameter. Such predetermined data may be obtained from theoretical calculations, hypotheses, previous experiments, previous measurements from this particular reservoir or one or more other reservoirs, etc.

[0045] An example of a reservoir parameter to be analyzed is fluid permeability through rock formations, such as before and after hydraulic fracturing. For instance, in some embodiments illustrated in FIG. IB, magnetic particles may be added to a reservoir before hydraulic fracturing (step 201). The magnetic susceptibilities of the magnetic particles may then be measured as they flow through the rock formations (step 202). The measured magnetic susceptibilities may then be correlated to values associated with fluid permeability (step 203). Such a correlation process may compare the magnetic susceptibility measurements to predetermined magnetic susceptibility data and its associated fluid permeability information (step 204). Using this comparison, values associated with fluid permeability of the reservoir may be determined (step 205). Furthermore, this process may be repeated after a hydraulic fracturing (step 206) in order to analyze the efficacy of the hydraulic fracturing (step 207).

[0046] FIG. 9 is an example of a graph of detected concentrations of magnetic nanoparticles or proppant-coated magnetic nanoparticles as a function of time after continuous pumping into low permeability rocks and high permeability rocks. In this example, a magnetometer may be used to detect the magnetic particles. For low permeability rocks, the detected concentrations of magnetic nanoparticles increased as the nanoparticles were pumped into the rocks as a function of time (i.e., the particles cannot permeate into rocks of low permeability and thus increase in concentration). However, the concentration of detected magnetic nanoparticles does not increase as significantly for high permeability rocks (i.e., the higher permeability volume allows magnetic particles to permeate into the well and avoid detection).

[0047] FIG. 10 is an example of a graph of detected concentrations of magnetic nanoparticles or proppant-coated magnetic nanoparticles as a function of time after the injection of a pulse of the magnetic materials through low permeability rocks, moderate permeability rocks, and high permeability rocks. The graph is similar to the graph shown in FIG. 9. The pulse method used (as opposed to the set concentration pumping method associated with FIG. 9) displays a plateau for low permeability rocks, as the nanoparticles have nowhere to go. However, there is a dissipation in detected particle concentrations for high permeability and moderate permeability rocks. This rate drop corresponds to the amount of permeability a rock will have and is thus indicative of the fracturing of that rock but not the area. By coupling these two parameters, a full characterization of a hydraulic fracture can be undertaken. Both parameters of fracture area and fracture permeability can be understood.

[0048] The examples of FIGS. 9 and 10 show that measurements of the magnetic susceptibilities of injected magnetic particles may be utilized to determine the permeability of a reservoir. For example, such magnetic susceptibility measurements may be graphed and then the graphs compared to predetermined graphs that represent predetermined values associated with fluid permeability. Alternatively, the magnetic susceptibility measurements may be statistically analyzed and compared to predetermined fluid permeability data to produce a set of information from which the permeability of the reservoir can be estimated.

[0049] Reservoirs

[0050] The methods of the present invention may be applied to various reservoirs. In some embodiments, the reservoir is a subterranean formation. In some embodiments, the reservoir is an oil or gas reservoir. Other reservoirs may include water, carbonates, siliciclastics, water drives, retrograde gas condensates, water drive oil, heavy oil, and light oil.

[0051] In various embodiments, the reservoir may also include various rocks, such as shales. By way of information, most shales can be unconventional sources of natural gas (other unconventional sources of natural gas include coalbed methane, tight sandstones, and methane hydrates). Shales generally have low matrix permeability. Thus, gas production in commercial quantities requires shale fractures to provide permeability.

[0052] Reservoir Parameters

[0053] The methods of the present invention may be used to evaluate various reservoir parameters. Such parameters may include, without limitation, fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy. The parameters may also include wireline gamma ray response. Other parameters may include fractional mineral content, cation exchange capability per unit pore volume, and flow zone indicator.

[0054] Various embodiments of the present invention reside at least in part in the previously unknown realization that the aforementioned parameters can be correlated with magnetic susceptibility of magnetic particles in a reservoir (or a function thereof). As set forth in more detail below, the reservoir parameter values may be used for various applications, such as determining a three-dimensional view of the reservoir. [0055] Measuring Magnetic Susceptibility

[0056] Magnetic susceptibility is generally defined as the degree of magnetization of a material in response to a magnetic field (i.e., magnetization divided by the applied magnetic field). Magnetization may be measured in the laboratory using standard susceptibility bridges (usually low applied field devices), or by determining hysteresis curves (e.g., using a variable field translation balance), where the slope at each point on the curve is the magnetic susceptibility at that point. The advantage of the latter technique is that the magnetic susceptibility over a range of low and high applied fields can be determined.

[0057] The measurement of magnetic susceptibility downhole may be performed using a series of coils for applying a (generally weak) magnetic field into the rock formation and sensing the magnetization produced. However, one of the problems in imaging downhole is creating an image of the reservoir beyond the region that the magnetic susceptibility can be measured. For instance, the measurement of magnetic susceptibility may generally be limited to a distance of up to around 1 inch (in current prototypes), or at best a few inches from the well bore. However, it is desirable to obtain information on the rock formation up to 100-200 feet away or greater from the well bore. Various embodiments of the present invention solve the aforementioned problems by measuring the magnetic susceptibility of magnetic particles in a reservoir, since such magnetic particles may be injected into the reservoir after which the magnetic particles migrate through the mineral formation such desired distances from the well bore. The magnetic susceptibility of the migrated magnetic particles is then measured as described herein.

[0058] Various methods may be used to measure the magnetic susceptibility of magnetic particles in a reservoir. For instance, in some embodiments, the measurement process may involve detecting magnetic particles in the reservoir. Such embodiments may utilize various detection devices, such as remote sensing devices. In some embodiments, the remote sensing device is a magnetometer, such as an airborne magnetometer survey. In other embodiments, the remote sensing device is a ground penetrating radar. The operation and use of such devices are well-known to persons of ordinary skill in the art. [0059] In some embodiments, magnetic susceptibility may be detected using a high-resolution accelerometer or geophone. The operation and use of such devices are also well-known to persons of ordinary skill in the art. Such embodiments may be suitable where the magnetic particles contain proppant or a piezoelectric component (as described in more detail below).

[0060] Some embodiments of the present invention may also utilize highly magnetic "tags" as contrast agents for detection of changes in the magnetic field of the reservoir. The use of low frequency (LF)/DC magnetic fields may enable the sensing of probe ensembles where suitable magnetic probes may be either mobile or static.

[0061] In some embodiments, magnetic susceptibility may be detected using a low field downhole magnetic susceptibility probe. An Example of such a device is shown in FIG. 18. Similar devices, which may be used or modified for use in embodiments of the present invention, are commercially available from Bartington Instruments Ltd., Oxford Instruments, Schlumberger Limited, and Geonics Limited. The operation and use of such devices are also well-known to persons of ordinary skill in the art. For instance, such probes can be operated by utilizing an oscillating magnetic field to induce a current in the probe. The oscillating current produces a secondary field that is detected by receiver coils.

[0062] Magnetic particles may also be detected by the detection of magnetic perturbations caused by the magnetic particles. Such modes of detection may be facilitated by using a magnetic antenna (e.g., using the casing of the well bore, in combination with a magnetometer in some embodiments, as well-known by persons of ordinary skill in the art). Such downhole magnetometer probes, which may be used or modified for use in embodiments of the present invention, include model 2DVA-1000 commercially available from Mount Sopris Instrument Company, Inc.

[0063] In some embodiments, the measurements may occur in a well before, during, or after various processes, such as drilling, water flooding, or hydraulic fracturing. In various embodiments, the measuring may involve measurements while drilling (MWD), using various commercially available instruments, such as those available from MicroTesla LTD and Schlumberger Limited. In further embodiments, the magnetic particles may be pumped continuously through a reservoir during the measuring process. In other embodiments, the magnetic particles may be pumped in pulses through the reservoir during the measuring process. In some embodiments, magnetic susceptibility measurements may occur after the placement of magnetic particles in a reservoir during or after a hydraulic fracture, a subsequent water flood, or an injection.

[0064] In some embodiments, the measuring process may occur before and after a fracturing of a reservoir. See FIG. IB. In such embodiments, the obtained parameter values may be utilized to determine the efficacy of the fracturing. This can be done in situ downhole, in real time, or sequentially across several locations.

[0065] In various embodiments, the tools or devices used to measure magnetic susceptibility downhole can be positioned along various heights of a reservoir (such as a borehole). In addition, tools and devices can be oriented such that a series of strata can be measured to create a three-dimensional image of permeability.

[0066] Correlating Magnetic Susceptibility to Reservoir Parameter Values

[0067] Various methods may be used to correlate the measured magnetic susceptibility of magnetic particles in reservoirs to one or more values that are associated with one or more parameters of the reservoir. For instance, in some embodiments, the correlating process may involve comparing predetermined parameter information that is a function of magnetic susceptibility to the measured magnetic susceptibility to determine at least one value that is associated with at least one parameter of the reservoir. In some embodiments, the correlating process may utilize a computer program. In some embodiments, the computer program is on an electronically-readable medium.

[0068] Some embodiments of the present invention utilize the measured magnetic susceptibility of magnetic particles as a function of time and position within a reservoir (e.g., a well bore) to obtain the actual value of various parameters, such as permeability. This can be done by comparing the measured magnetic susceptibility (or a function thereof) with parameter values that are stored as a function of magnetic susceptibility (or a function thereof). Thus, in some embodiments, methods of the present invention may further involve storing parameter information as a function of magnetic susceptibility (or a function thereof), and using the stored parameter information to determine a parameter value for a new sample.

[0069] Various embodiments of the present invention may also include a computer program, such as on a data carrier or computer readable medium. In such embodiments, the program may have codes or instructions for receiving or accessing the measured magnetic susceptibility of the sample from the downhole measurement apparatus, and determining a value of the parameter using that measured susceptibility. In various embodiments, the computer program may have codes or instructions for receiving the identity of at least two components of the sample, identifying the magnetic susceptibility of the two identified components, and using the measured magnetic susceptibilities of the two identified components to determine the fraction of the total sample contributed by at least one of the components. In such embodiments, the codes or instructions for determining the value of the parameter may be operable to use the determined fraction to determine the value of the parameter.

[0070] In some embodiments, the magnetic susceptibility of magnetic particles can be measured downhole in real time. In such embodiments, the variation of the concentration of the magnetic particles as a function of time may be used to relate to the permeability of the rock formation through which the magnetic particles are moving. Thus, in a low permeability rock, a continuous flow of magnetic particles downhole can result in an increase in their concentration with time (i.e., the magnetic particles will have nowhere to go). However, if the rock has a high permeability, the concentration of magnetic particles may reach an equilibrium value, since additional magnetic particles that are pumped downhole are transported away from the borehole. Furthermore, in some embodiments, the concentration of magnetic particles detected downhole can also be compared to the concentration pumped downhole. [0071] In various embodiments where magnetic particles are pumped downhole as part of a continuous flow, a low permeability rock can be indicated by an increase in the detected magnetic particle concentration, as previously discussed with respect to FIGS. 9-10. Where sufficient permeability exists to remove the magnetic particles away from the volume surrounding the borehole, then the detected magnetic particle concentration may eventually be reduced to a very low value, possibly below the detection limit of the instruments. The rate of which this loss occurs can be related to the transport rate and hence permeability.

[0072] Magnetic Particles

[0073] Various magnetic particles may be utilized in various embodiments of the present invention. In some embodiments, the magnetic particles that are utilized are magnetic nanoparticles. Nanoparticles are generally defined as particles in which one of their dimensions (i.e., sizes) is less than approximately 100 nm. In some embodiments, the nanoparticles have a size between approximately 1 nm and approximately 100 nm. In some embodiments, the nanoparticles have a size between approximately 0.5 nm and approximately 200 nm. In some embodiments, the nanoparticles have a size between approximately 2 nm and approximately 20 nm. Nanoparticles of the present invention may or may not exhibit size-related properties that differ significantly from those observed in fine particles or bulk materials.

[0074] In some embodiments, the magnetic particles of the present invention contain various metals. For instance, in some embodiments, the magnetic particles of the present invention contain iron and cobalt. See, e.g., Example 1. In some embodiments, the magnetic particles of the present invention contain iron and copper. See, e.g., Example 2.

[0075] By way of background, previous downhole particle detection research has concentrated on ferrite nanoparticles, such as Fe3C"4 nanoparticles. While such nanoparticles are magnetic, they suffer from various limitations for use in the present invention. First, their magnetic susceptibility is low. Second, ferrite nanoparticles react readily with hydrogen sulfide, which alters their magnetic susceptibility. Thus, some embodiments of the present invention use magnetic nanoparticles that do not react with hydrogen sulfide or other sulfur containing compounds.

[0076] Thus, some embodiments of the present invention utilize magnetic particles that contain Mn and/or Zn doped iron-oxide particles. Such particles are both more paramagnetic and have a lower reactivity to hydrogen sulfide. Some embodiments of the present invention provide magnetic particles with the following formula: MxM'yFe204, where x + y = 1. In some embodiments, M or M' contains at least one of zinc, manganese, cobalt, copper, or vanadium. In some embodiments, the magnetic particles have one or more of the following formulas: Mn0.5Zno.5Fe204, Mn0.65Zno.35Fe204, Mno.35Zn0.65Fe204, and Mno.iZn0.9Fe204.

[0077] In some embodiments, the magnetic particles may also be associated with one or more polymers. Such polymers may include charged polymers, such as polyethylenimine (PEI). Additional suitable polymers include, without limitation, polyurethanes, polyesters, polyacrylates, and co-polymers thereof.

[0078] Without being bound by theory, it is believed that polymers can be used to more effectively transport magnetic particles to desired sites in various reservoirs. For instance, PEI may be used along with proppant to coat nanoparticles for more effective transport of the nanoparticles into an oil well. See, e.g., R. Barati et al., "Fracturing Fluid Cleanup by Controlled Release of Enzymes from Polyelectrolyte Complex Nanoparticles," Journal of Applied Polymer Science, Vol. 121, Issue 3, pages 1292-1298, August 5, 2011 (article first published online March 2, 2011); U.S. Patent Application Publication No. US 2010/0197966 Al; and PCT Publication No. WO/2008/030758.

[0079] In various embodiments, the magnetic particles may also include a functionalized surface. For instance, FIGS. 11A and 11B show exemplary magnetic nanoparticles with functional groups "X" on the surface of the nanoparticles. In some embodiments, the functionalized surface may include hydrophilic functional groups, hydrophobic functional groups, anionic functional groups, cationic functional groups, and/or zwitterionic functional groups. Without being bound by theory, it is believed that such functional groups aid in the solubility or miscibility of the magnetic particles in various solvents. In addition, functional groups may dictate how well the magnetic particles deposit onto a reservoir rock or travel within the reservoir formation (e.g., fractured rocks).

[0080] In some embodiments, the functional groups on the magnetic particles can be chosen to either promote transport through a specific rock formation but have low transport through other formations. For instance, different molecules with specific head groups (X) (as shown in FIGS. 11A and 11B) may have different polarities and/or sizes that will dictate how they will deposit onto different rock sources. In this regard, pumping pulses of different magnetic particles can be used to determine the relative composition of the reservoir.

[0081] In some embodiments, the solubility or miscibility of the magnetic particles can be chosen to either promote solubility in water or in hydrocarbons. For instance, if water solubility is chosen in a permeable formation, the magnetic particles may concentrate in water as opposed to any oil layer.

[0082] Various methods may be used to tailor the choice of functional groups on magnetic particles in order to ensure a desired solubility. For example, water solubility can be attained through the use of substituents that promote hydrogen bonding. See, e.g., R. L. Callender et al, Aqueous synthesis of water soluble alumoxanes: environmentally benign precursors to alumina and aluminum-based ceramics, Chem. Mater., 1997, 9, 2418. Also see C. D. Jones et al, Synthesis and characterization of carboxylate-FeOOH nanoparticles (ferroxanes) and ferroxane- derived ceramics, Chem. Mater., 2002, 14, 621. In some embodiments, water solubility may be attained through the use of charged substituents. See, e.g., L. Zeng et al, Tailoring aqueous solubility of functionalized single-wall carbon nanotubes over a wide pH range through substituent chain length, Nano Lett., 2005, 5, 2001. In some embodiments, the use of hydrophobic substituents allows for solubility within organic solvents. See, e.g., C. C. Landry et al., From minerals to materials: synthesis of alumoxanes from the reaction of boehmite with carboxylic acids, J. Mater. Chem., 1995, 5, 331. [0083] It is noted that the above-referenced studies primarily pertained to biological systems, such as drug delivery and MRI contrast agents. Though research has also been aimed towards the environmental fate of nanoparticles, there have been fewer studies on how magnetic particles (such as nanoparticles) may be suspended or dissolved in a solvent to interact with various mineral surfaces.

[0084] In some embodiments of the present invention, the magnetic particles may have magnetic susceptibilities that do not change significantly with increased temperatures. For instance, in some embodiments, magnetic particles are configured to have a magnetic susceptibility that remains relatively unchanged at environmental temperatures higher than room temperature. In some embodiments, the magnetic particles are configured so that their mass magnetization does not vary more than 10 Am2 kg"1 at all environmental temperatures.

[0085] In some embodiments, magnetic particles are configured to have a magnetic susceptibility that increases no more than approximately 10% in a temperature range between approximately 20 °C to approximately 125 °C. In some embodiments, magnetic particles are configured to have a magnetic susceptibility that increases no more than approximately 10% to 40% in a temperature range between approximately 20 °C to approximately 125 °C. In some embodiments, magnetic particles are configured to have a magnetic susceptibility that increases no more than approximately 10% to 60% in a temperature range between approximately 20 °C to approximately 125 °C.

[0086] The ability to detect a particle under temperature conditions found downhole in an oil or gas reservoir may be related to the magnetic hysteresis measurements of the particle. In order to detect small quantities of a particle, the magnetic susceptibility of the particle is generally held constant at high temperatures. This property is related to the Curie temperature. The Curie temperature (Tc, or Curie point) is a term in physics that refers to a characteristic property of a ferromagnetic or piezoelectric material. For magnetic materials, such as magnetic particles, it appears that the higher the Curie temperature, the more constant the magnetic susceptibility of the particle at temperatures consistent with downhole. In contrast, if the Curie temperature is too low, then the magnetic susceptibility of the particle will decrease dramatically at elevated temperatures resulting in a loss of signal to noise. Thus, in some embodiments, it may be desirable to choose magnetic particles with the highest Curie temperature and the highest magnetic susceptibility such that the highest signal-to-noise ratio may be obtained.

[0087] Several magnetic particle compositions, which may be used in embodiments of the present invention, were tested for their responses to different environmental temperatures, including environmental temperatures experienced in downhole and reservoir environments (e.g., 89°C-125°C). The magnetic particles tested were spinel ferrite magnetic particles P36 (containing Mn0.65Zn0.35Fe2O4), P37 (containing Mn0.35Zn0.65Fe2O4), and P42 (containing

Figure imgf000021_0001

[0088] Low field magnetic susceptibility measurements were made using standard magnetic susceptibility bridges on the particles, and also on typical reservoir rocks and fluids. Magnetic hysteresis curves were obtained for the particles using a variable field translation balance (VFTB), such as the VFTB shown in FIG. 13, and which is commercially available from Peterson Instruments. This type of VFTB uses an electromagnet (rather than a solenoid) in order to generate higher fields. The VFTB provides a means of estimating the magnetic susceptibility at a range of low and high fields (up to approximately 1 Tesla). The slope of the hysteresis curve at any point (magnetization/applied field) is the magnetic susceptibility at that point. The magnetic hysteresis curves were determined not only at room temperature, but also at higher temperatures in order to simulate downhole reservoir temperatures. The particles were mixed with calcium fluoride powder and this mixture was then poured into the sample containers in order to do the measurements. The calcium fluoride powder provides a good medium in which to disperse the particles to minimize interactions between the particles, and also provides an inert matrix for the temperature measurements. The VFTB is also capable of doing low temperature magnetic measurements, if necessary. Table 5 provides a summary of the magnetic susceptibility measurements.

Figure imgf000022_0001

Table 5

[0089] FIGS. 14-16 show magnetic hysteresis measurements at room temperature and reservoir temperatures for spinel ferrite P37, P36, and P42, respectively. Generally, the results indicate that the magnetic susceptibility of spinel ferrite P42 does not change significantly with increased temperatures. In contrast, the magnetic susceptibilities of spinel ferrite P36 and P37 fluctuated more significantly with increased temperatures.

[0090] For example, Mn0.65Zn0.35Fe2O4 ferrite nanoparticles have a room temperature magnetic susceptibility of 40,700 x 10"8 m3kg_1. However, the magnetic susceptibility of such particles is decreased significantly at higher temperatures (e.g., 89°C and 125°C). In contrast, magnetic nanoparticles of the composition Mno.5Zno.sFe204 only have a room temperature magnetic susceptibility of 16,440 x 10"8 m3kg_1. However, this magnetic susceptibility is not changed at higher temperatures (e.g., 89°C and 125°C).

[0091] Thus, the use of magnetic nanoparticles of the composition Mno.5Zno.sFe204 and other similar nanoparticles may be utilized in some embodiments of the present invention. In some embodiments, such nanoparticles have a diameter of approximately 7 nm. In some embodiments, the magnetic nanoparticles are coated with olelylic acid and have a spinel ferrite x-ray diffraction pattern shown in FIG. 19 for Mno.iZno.9Fe204. The diffraction pattern displays a spinel ferrite form. This form may be the same for all nanoparticles containing MnxZnyFe204. Moreover, such magnetic particles provide a very good contrast agent compared to the surrounding reservoir rocks and fluids, which have significantly lower magnetic susceptibilities, as indicated in FIG. 12. Thus, as little as a 1% mass concentration of such magnetic particles may be sufficient as a contrast agent in a reservoir. [0092] In some embodiments, the magnetic particles that are utilized are associated with proppant. In some embodiments, the proppant may include sand, ceramic, hollow ceramic, resin coated sand, and resin-coated walnut shells. In some embodiments, the proppant is coated on a surface of the magnetic particle. In some embodiments, the proppant is incorporated into the structure of the magnetic particles.

[0093] By way of background, the use of proppant may find applications during a hydraulic fracture process, or frac job, where the reservoir rock is fractured to increase the permeability. In such embodiments, proppant is added to inhibit the rock fractures from closing up again after the pressure is released. The proppant in such instances is generally either a uniform size of sand, ceramic particles, or polymers. In each case, it is desirable to be able to locate the position of the proppant after the frac job has been accomplished. In order to do this, the proppant generally needs a high magnetic content. One way in which this can be accomplished is the creation of a coating on a magnetic particle by way of the reaction of a preformed proppant with a magnetic particle in the presence of a polymer cross-linker. The resulting coated magnetic particle in such embodiments would have the same physical properties as its base material. Furthermore, the coating could be removed at a later date. The process described with respect to FIG. IB may utilize such magnetic particles.

[0094] The magnetic particles of various embodiments of the present invention may also be dissolved or suspended in various fluids. Exemplary fluids include, without limitation, drilling mud, water, brine, hydrocarbons, and combinations thereof.

[0095] Methods of Making Magnetic Particles

[0096] Various embodiments of the present invention pertain to methods for making the above- described magnetic particles, including proppant-containing magnetic particles. In general, such methods generally comprise reacting magnetic particles with proppant. In some embodiments, the reacting comprises coating magnetic particles with proppant. In some embodiments, the reacting comprises incorporating proppant into the structures of the magnetic particles during the fabrication of the magnetic particles. In some embodiments, the incorporation may involve spray coating the proppant onto or into the structure of the magnetic particles. In some embodiments, the reacting step may occur in the presence of a polymer, such as PEL

[0097] Some embodiments of the present invention pertain to the reaction of magnetic particles with a binder on the surface of a proppant material, such as sand or a ceramic particle. The magnetic particle in such embodiments may be functionalized to react with a suitable cross- linking agent (or polymer, such as PEI) to create a stable sheath on the sand grain or proppant. Various aspects of the present invention also pertain to the inclusion of magnetic particles into the proppant structure, such as resin-coated sand, or resin-coated walnut husks.

[0098] Some embodiments of the present invention pertain to the synthesis of magnetic particles with controlled compositions to maximize the magnetic susceptibility under downhole conditions. Some embodiments of the present invention pertain to the functionalization of these particles to maximize transport through a particular rock or mineral formation within the subterranean reservoir.

[0099] Some aspects of the present invention relate to methods of making magnetic particles to control reactivity with species encountered downhole. For example, the particle may be designed to either react with hydrogen sulfide (H2S) or be stable to hydrogen sulfide, depending on the need. See, e.g., FIG. 11B, which shows a schematic representation of a nanoparticle that contains a protective coating layer that inhibits the reaction of the nanoparticle with hydrogen sulfide or other sulfur containing species. In some embodiments, the use of particles that react with hydrogen sulfide (and other sulfur species by which the magnetic susceptibility of the particle is different before and after reaction with hydrogen sulfide) may be used for detecting the hydrogen sulfide by the changes observed in the downhole magnetic susceptibility.

[00100] Some embodiments of the present invention pertain to methods for synthesizing mixed metal-oxide particles. In some embodiments, such methods may utilize a wide range of magnetite (iron oxide) precursors. In each case, the synthesis can result in a metal oxide particle that is surface stabilized or functionalized with a molecular group (often based upon a carboxylic acid) that allows for the miscibility or solubility of the particle in a desired medium. [00101] In some embodiments, the starting materials are iron acetylacetonate and cobalt acetylacetonate, which are combined with a specific starting ratio (given in mmol). To this mixture is added (also in predetermined ratios) oleic acid, oleylamine, 1 ,2-hexadecanediol and benzyl ether. The oleic acid and oleylamine act as surfactants. The 1 ,2-hexadecanediol is used to either promote nucleation or limit growth, thereby allowing for small particles that are monodisperse to be formed. In some embodiments, benzyl ether is a preferred solvent. After the reaction is run and the particles are cleaned and suspended in hexanes, analysis is performed in order to obtain the ratio of iron to the formed particles.

[00102] Correlations between the starting ratios and end product ratios in the aforementioned embodiments are a goal, as a simple formula is desired. This formula will then allow for the ease of making particles with specific end product ratios. This will allow for the control of the magnetic properties of the particles, as the magnetic properties of the particles are dependent on the ratio of the iron to the other metal. Controlling the magnetic properties of the nanoparticles (and potentially modifying the surface of the particle) allows for magnetic imaging to be done with ease. This imaging can be used when performing hydraulic fracturing of slate in order to obtain oil and natural gas wells.

[00103] Magnetic particles of the present invention may also be made under various pH conditions. Varying the pH levels may help vary the structure of the magnetic particles. This can in turn allow for a more controlled release of particles into a reservoir.

[00104] For instance, as shown in FIGS. 3-8, magnetic particles may be coated with a polymer (e.g., PEI) and dried on the surface of a proppant (e.g., Arizona sand) at different pH levels (e.g., pH 1.7-9). FIG. 3 is a scanning electron micrograph (SEM) of an unmodified Arizona sand surface. The image was taken in high vacuum mode on a FEI Quanta 400 field emission scanning electron microscope (FEESEM) after the sample was sputtered with 2 nm of gold.

[00105] FIG. 4 is a SEM of a 1 : 1 Fe nanoparticle:Polyethylenimine (PEI) aqueous solution that was coated at a pH of approximately 1.75 and dried on a surface of Arizona sand at approximately 60°C for approximately 12 hours. The image indicates no display of visible aggregations of Fe nanoparticle:PEI coatings on the surface of the sand grain. The image was taken in high vacuum mode on a FEl Quanta 400 FEESEM after the sample was sputtered with 2 nm of gold.

[00106] FIG. 5 is a SEM of a coating of 1 : 1 Fe nanoparticle:PEI aqueous solution that was coated at a pH of approximately 4 and dried on a surface of Arizona sand at approximately 60°C. The image was taken on a FEl Quanta 400 FEESEM in high vacuum mode after the sample was sputtered with 2 nm of gold. The image shows an initial display of surface membrane characteristics and a skin-like membrane that is stretched over a pocket indentation on a sand grain.

[00107] FIG. 6 is a SEM of a coating of a 1 : 1 Fe nanoparticle:PEI aqueous solution at a pH of approximately 7 that was dried on a surface of Arizona sand at approximately 60°C. The image was taken on a FEl Quanta 400 FEESEM in high vacuum mode after the sample was sputtered with 2 nm of gold. The image displays full membrane encapsulation of the sand grain by PEI- coated nanoparticles, as indicated by a skin-like structure.

[00108] FIG. 7 is a SEM of a 1 : 1 Fe nanoparticle:PEI solution at a pH of approximately 9.36 that was coated and dried on a surface of Arizona sand. The image was taken on a FEl Quanta 400 FEESEM in high vacuum mode after the sample was sputtered with 2 nm of gold. The image displays bimodal aggregation of the PEI-coated nanoparticle.

[00109] FIG. 8 is a SEM of a 1 : 1 Fe nanoparticle:PEI solution at a pH of approximately 11.8 that was coated and dried on a surface of Arizona sand. The image was taken on a FEl Quanta 400 FEESEM in high vacuum mode after the sample was sputtered with 2 nm of gold.

[00110] Various methods may also be used to make iron-oxide and mixed iron-metal-oxide nanoparticles. See, e.g., C. A. Crouse et al, J. Mater. Chem., 2008, 18, 4146. However, there have been no previous attempts to determine a correlation between starting ratios and end product ratios in order to control the properties of magnetic particles. The aforementioned aspects of the present invention can allow for that control to be possible. [00111] The methods and magnetic particles of the present invention can find numerous applications. For instance, in some embodiments of the present invention, the methods are used to determine the fluid permeability (and permeability anisotropy) of a subterranean reservoir that contains a hydrocarbon, such as natural gas or oil. In some embodiments of the present invention, the methods are used to determine the location, concentration, and location anisotropy of a proppant in a subterranean reservoir that contains a hydrocarbon (such as natural gas or oil) after a hydraulic fracture has been performed. Some embodiments of the present invention relate to methods for determining the fracture anisotropy in a subterranean reservoir containing hydrocarbons (such as natural gas or oil) after a hydraulic fracture has been performed. Such embodiments of the present invention can also be used to determine the extent of the produced fractures.

[00112] Various aspects of the present invention can also be used to obtain a three-dimensional permeability profile or fracture profile of a reservoir. In some embodiments, such information is attained by pumping magnetic nanoparticles downhole as a component of a hydaulic fracture fluid, a water flood, or drilling mud. The concentration of the nanoparticles downhole is then determined from the magnetic susceptibility measurements. The variation in concentration of the magnetic nanoparticles as a function of time and pumping rate will be a function of the permeability of the rock formation. Furthermore, the permeability anisotropy or fracture anisotropy can be determined at each depth by utilizing such methods.

[00113] Some embodiments of the present invention may also be used to determine one or more parameters of a rock sample in an oil or gas reservoir. Such methods may involve measuring the magnetic susceptibility of the rock sample prior to and post injection of magnetic particles, and determining a value of the parameter using that measured susceptibility.

[00114] Various methods of the present invention may also be used to estimate fluid permeability. Fluid permeability is the ability of fluids to flow through rock, and is a key parameter in determining how best to access oil, as well as in determining where to drill in an oil or gas field. [00115] In some embodiments of the present invention, the methods are applied to magnetic susceptibility measurements made in the laboratory on core samples configured within a simulated borehole sample using a low field downhole magnetic susceptibility probe. The method may also be applied to downhole magnetic susceptibility data, thereby enabling in situ estimates of fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy.

[00116] Various methods of the present invention may also be applied to currently known downhole data activity (such as wireline gamma ray). By correlating the magnetic susceptibility and/or the fractional content with various parameters (and in addition with the wireline gamma ray response), various methods of the present invention can enable mineral content and consequent petrophysical parameter prediction information to be derived from the wireline gamma ray tool data.

[00117] Methods and magnetic particles of the present invention provide numerous advantages. Currently, downhole detection methods in the oil and gas industry (including magnetic methods) are limited in the depth (distance) from the well bore. In practice, prior methods are limited to a few inches. Unfortunately, it is generally desirable to obtain information at a greater distance away from the borehole. Various embodiments of the present invention provide methods for calculating properties away from the borehole by measuring the variation of a property with time near the borehole. For instance, by determining the magnetic susceptibility as a function of time as magnetic nanoparticles are pumped down an oil or gas well, it is possible to infer various petrophysical properties. Thus, static properties such as permeability and position can be determined by making a dynamic measurement. When such methods are carried out at different heights in the well bore and directionally approximately 360°, then a three-dimensional picture of permeability or proppant position can be obtained. To Applicants' knowledge, such methods have not been described for making measurements downhole in the oil and gas industry. [00118] Thus, an advantage of the present invention is that it can allow for the efficient and reliable estimation of the permeability of an oil or gas reservoir. Such information is a useful predictor of the production rate of the reservoir.

[00119] Another advantage of the present invention is that it allows for an efficient and reliable estimation of the permeability of an oil or gas reservoir before and after a hydraulic fracture. Such information is a useful measure of the success of the hydraulic fracture (or frac job). Various aspects of the present invention also allow for the determination of the flow of a proppant into a reservoir as a useful measure of defining the success of a frac job.

[00120] Various embodiments of the present invention will now be described with respect to the Examples below.

EXAMPLES

[00121] Example 1. The synthesis of magnetic nanoparticles containing iron and cobalt

[00122] This Example demonstrates the synthesis of iron-cobalt magnetic nanoparticles for use as magnetic particles in various embodiments of the present invention. Table 1 summarizes the starting ratios used in the experiments.

Figure imgf000029_0001

Table 1 [00123] The starting materials have a known starting ratio. The 1 ,2-hexadecandiol, oleic acid, and oleylamine are in a molar ratio of 2: 1 :8, respectively. With these ratios, 37.5 mL of benzyl ether or other solvent may be added.

[00124] Process steps for the reaction are as follows: (1) calculate the grams or milliliters needed as determined by the mmol required; (2) weigh or measure out each chemical and add it to a three-neck round bottom flask; (3) record the mass or volume that was added of each chemical; (4) add 37.5 milliliters of benzyl ether or other suitable solvent; (5) add a stir bar; (6) heat the system to 270°C at 10°C.min"1; (7) let the reaction remain at 270°C for 15 min and then cool to room temperature; (8) remove the sample from the three-neck round bottom flask and put 20 mL into 50 mL centrifuge tubes; (9) add ethanol to bring the volume content to 40 mL; (10) weigh and add ethanol so centrifuge tubes weigh the same; (11) centrifuge at 4400 rpm for 30 minutes with a slow deceleration; (12) decant and discard the supernatant and wash again with ethanol; (13) discard the supernatant; (14) let the samples air dry overnight; (15) suspend dried samples in hexanes; (16) centrifuge sample to remove aggregates; and (17) save the supernatant, which constituted the synthesized product (i.e., this is the sample).

[00125] Samples were prepared for small-angle X-ray scattering (SAXS) by having them suspended in hexanes in concentrated form. Samples were prepared for atomic force microscopy (AFM) by spin coating onto mica. Samples were prepared for inductively coupled plasma-mass spectroscopy (ICP-MS) by digesting 500 microliters (μί) of the sample in 9.5 mL concentrated nitric acid in a 15 mL centrifuge tube. Samples remained for two days with a loose cap inside a fume hood. From this, 0.5 mL was taken and added to 9.5 mL of HPLC-grade water.

[00126] A summary of synthetic ratios is given in Table 1. The difference between initial reaction conditions and the isolated nanoparticles is shown in Table 2. mg Fe (initial) mg Co (initial) Ratio Fe:Co Ratio Fe:Co in product Size

177.1 88.3 2.01 3.24 9.047 nm

251.6 13.6 18.50 38.17 6.402 nm

225 40.3 5.58 7.54 7.358 nm

197.4 67.3 2.93 4.96 7.015 nm

177.8 179.8 0.99 205 7.040 nm

88.3 178.2 0.50 1.44 5.231 nm

176.1 17.8 9.89 18.23 6.392 nm

177.1 30.2 5.86 11.97 5.599 nm

Table 2

[00127] Example 2. The synthesis of bi-metallic nanoparticles containing iron and copper

[00128] This Example demonstrates the synthesis of iron-copper magnetic nanoparticles for use as magnetic particles in various embodiments of the present invention. Table 3 summarizes the starting ratios used in the experiments.

[00129] Bi-metallic nanoparticles were made by a modified method described in S. Sun et al. (Size-controlled synthesis of magnetite nanoparticles, J. Am. Chem. Soc, 2002, 124, 28, 8204- 8205). Sun et al. described methods that produce iron oxide (Fe3C"4) nanoparticles in a non- coordinating solvent in the presence of alcohols at high temperatures (reflux 260°C) using fatty acids and long chain amines as capping agents that can control the shape, size, and size dispersion of the nanoparticles. The nanoparticles have an inverse spinel ferrite cubic close packed form. At room temperature, electrons move between the Fe2+ and Fe3+ atoms that sit in the tetrahedral and octahedral sites, respectively, and give rise to some of the interesting magnetic behavior of these materials.

[00130] A spinel ferrite has the stoichiometric form AB203, whereby A occupies the tetrahedral sites and is comprised of cations with a +2 charge. B occupies the octahedral sites and is comprised of cations with a +3 charge. For this reason, it is possible to choose metal acetylacetonate salts of +2 charge to be incorporated into the iron oxide crystal lattice in the place of the Fe2+ of the original iron-oxide nanoparticles. By this rationale, bi-metallic nanoparticles of iron and copper were made.

[00131] The methods kept a total metal concentration constant at 0.75 mmol. This enabled the equal sharing of contributions from iron and copper to create bi-metallic particles that had various amounts of iron and copper within them. Referring to FIG. 2, it was found experimentally through the use of Inductively Coupled Plasmon Atomic Emission Spectroscopy (ICP-AES) that until 40% loading of copper in the nanoparticle was achieved in the nanoparticle matrix, an excess of copper reagent was required. The graph in FIG. 2 shows the amount of iron and copper as a ratio per nanoparticle synthesized. After 40% of the nanoparticle was filled with copper, then a 1 : 1 ratio between the metal content in the reagent and solution existed. In order to make nanoparticles with small amounts of metal content, for example in the cases where 1-10% of copper was added as reactant, the metal salts were first diluted in the solvent in a large batch and then added from the solvent based on values that are tabulated below. In essence, a solution was created that contained all the copper acetylacetonate required for ten reactions, for the reactions involving 1—10% copper content, thus overcoming issues of accuracy when weighing reactants of very small weights. In total, 129.57 mg was added to 66 mL solvent and then dispersed as a solution where 1 mL was equal to 1% accordingly. This solution was added to Fe(acac)3 that was weighed out accordingly. Copper has an advantage of exhibiting plasmon spectral response in the UV-visible spectrum, along with silver and gold. See J.A. Creighton et al., Ultraviolet-Visible Absorption Spectra of the Colloidal Metallic Elements, J. Chem. Soc. Faraday Trans, 1991, 87, 3881.

[00132] All materials were purchased from Sigma-Aldrich and used as received. In brief, to a 100 mL three-neck round-bottomed flask was added a combined total of 0.75 mmol metal acetylacetonate, 1.5 mmol 1 ,2-hexadecanediol, 3 mmol oleic acid, 3 mmol oleyl amine, and 37.5 mL benzyl ether. This was brought to reflux for 15 minutes and then allowed cool to room temperature. The particles solution precipitated in EtOH. The solution was then centrifuged for 5 min at 4400 rpm. The supernatant was discarded, and the pellet made soluble in approximately 10 mL of hexanes using light bath sonication to ensure complete solubility. Washing of the product was carried out by successive precipitation in EtOH and centrifugation. This removed unreacted chemical species and by-products from the nanoparticle synthesis reaction.

[00133] The total metal concentration was kept at 0.75 mmol. Successive amounts of Cu(acac)2 were added (starting at 1% increments) until reactions with a total of 10% Cu(acac)2 were obtained. Next, copper was added in increments of 10% until a total of 90% copper nanoparticle composition was obtained. Based on Table 3, a solution of Cu(acac)2 was made using the solvent. The total amount of Cu for a reaction containing 1-10% Cu(acac)2 was weighed and added to the solvent, which was equivalent to 107.98 mg Cu(acac). This amount of Cu(acac)2 was then added to a total of 55 mL of the solvent Benzyl ether such that every 1 mL of the solvent was equivalent to 1% of the total molar concentration of the metal. The total amount of metal is set at 0.75 mmol. If a 1% solution is required then 1 mL of the solution will be taken and used accordingly.

Figure imgf000033_0001

Table 3 [00134] Analysis of the metal content was carried out by ICP-AES, in which the metal nanoparticles are digested in an acid solution prior to analysis. This was carried out to ensure that all metal was in solution prior to characterization. Digestion of metals was carried out by the use of concentrated nitric acid, whereby in a typical reaction, 9.5 mL concentrated HN03 was added to 0.5 mL nanoparticle solution. Upon complete digestion, an aliquot of the acidic solution was then diluted to a 7% HNO3 concentration by addition of nanopure water (or HPLC grade water) that was previously cleaned of metal contaminants in order to prevent spurious results.

[00135] Concentrations of iron and cobalt were acquired using energy wavelengths that did not overlap. Metallic concentrations were determined by back calculation, and the results were graphed according to the metal concentration of copper that was used as a reagent. See FIG. 2. The results were compared to the copper concentration that was found in the solution. In this way, it was possible to determine how much copper was required as a reagent to acquire bimetallic nanoparticles of specific metallic content. It was found that at low concentrations of copper, there was a dominance of iron in the nanoparticle solution. However, as the copper content increased to 40% of the total reagent concentration, the nanoparticle solution appeared more copper rich.

[00136] Example 3. Synthesis of magnetic nanoparticles containing iron, manganese and zinc

[00137] This Example demonstrates the synthesis of magnetic nanoparticles containing iron, manganese and zinc with the following formula: MnxZnyFe204, where x + y = 1. Table 4 summarizes the starting ratios of iron to metal used in the experiments in this Example.

[00138] Process steps for the reaction were as follows: (1) weigh or measure out each chemical and add it to a three-neck round bottom flask; (2) add 37.5 mL of benzyl ether or some other suitable solvent; (3) heat the reaction solution to 200°C at 10°C.min"1; (4) let the reaction remain at 200°C for 15 min; (5) reflux at 270°C for 12 hrs; (6) allow the reaction to cool to room temperature; (7) add ethanol and precipitate the reaction solution with ethanol; (8) centrifuge at 4400 rpm for 30 minutes, with a slow deceleration; (9) decant and discard the supernatant and wash again with ethanol; (10) discard the supernatant; (11) let the samples air dry overnight; (12) once samples are dry, suspend in hexanes; (13) centrifuge samples to remove aggregates; and (14) save the supernatant, which constituted the synthesized product (i.e., the sample).

[00139] Samples were prepared for small-angle X-ray scattering (SAXS) by suspending them in hexanes in concentrated form. Samples were prepared for atomic force microscopy (AFM) by spin coating them onto mica. Samples were prepared for inductively coupled plasma-mass spectroscopy (ICP-MS) by digesting 500 microliters (μί) of the sample in 9.5 mL concentrated nitric acid in a 15 mL centrifuge tube. The samples remained for two days with a loose cap inside a fume hood. From this, 0.5 mL was taken and added to 9.5 mL of HPLC-grade water. A summary of synthetic ratios is given in Table 4.

Figure imgf000035_0001

Table 4

[00140] Example 4. Preparation of Magnetite Nanoparticles

[00141] This Example demonstrates the synthesis of Magnetite nanoparticles (MPs) for use as magnetic particles in various embodiments of the present invention. MPs were synthesized by co-precipitation of ferric and ferrous salts in a basic solution. For pre-modification by citric acid, as prepared magnetite nanoparticles (0.69 g) and citric acid (CA) monohydrate (0.2 g) were both added into 20 mL of deionized water. The mixture was sonicated for 40 min, and then neutralized by 0.5 mol/L NaOH solution. In order to remove excess electrolytes, the neutralized dispersion was subjected to dialysis against deionized water in a 12-14 kD cutoff cellulose tube for 48 hours. The dispersion of CA stabilized particles (MP-CA) was centrifuged at 9500 rpm for 20 min. The pellet was discarded, and the dispersion was used for subsequent operations. For PEI coating, the above dispersion was mixed with different amounts of 5% (m/m) PEI solution. After being gently shaken for 3 min, the mixture was then neutralized with 0.5 mol/L HC1 solution. As prepared, PEI-coated magnetic particles (MP-PEI-N) were washed three times by magnetic separation in order to remove unbound PEI and salts.

[00142] The dispersion of MP-PEI-N was acidified to pH 2 by 0.5 mol/L HC1 solution and kept for 10 min before being neutralized by 0.5 mol/L NaOH solution. The PEI-coated magnetic particles after this process (MP-PEI-A) were washed three times by magnetic separation. The as-prepared nanoparticles were dispersed in solution at differing pH values. Arizona basin sand was dip-coated in these solutions and oven dried. Morphology and size of the nanoparticles over different pH gradients were examined by transmission electron microscopy (TEM). Morphology of dried nanoparticles on the surface of the Arizona sand was also investigated using scanning electron microscopy. See FIGS. 3-8.

[00143] The embodiments described herein are to be construed as illustrative and not as constraining the remainder of the disclosure in any way whatsoever. While various embodiments have been shown and described, many variations and modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. Accordingly, the scope of protection is not limited by the description set out above. The disclosures of all patents, patent applications and publications cited herein are hereby incorporated herein by reference, to the extent that they provide procedural or other details consistent with and supplementary to those set forth herein.

Claims

WHAT IS CLAIMED IS:
1. A method for determining at least one value associated with at least one parameter of a reservoir, wherein the method comprises:
adding MxM'yFe204 magnetic particles to the reservoir, where x + y = 1, and wherein M or M' is at least one of zinc, manganese, cobalt, copper, or vanadium;
measuring a magnetic susceptibility of the magnetic particles in the reservoir; and correlating the measured magnetic susceptibility to at least one value associated with the at least one parameter of the reservoir.
2. The method of claim 1, wherein the correlating step comprises comparing predetermined parameter information that is a function of magnetic susceptibility to the measured magnetic susceptibility to determine at least one value associated with the at least one parameter of the reservoir.
3. The method of claim 1, wherein the magnetic particles have a composition of
Figure imgf000037_0001
4. The method of claim 1, wherein the at least one parameter is selected from the group consisting of fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy.
5. The method of claim 1, wherein the magnetic particles comprise proppant containing magnetic particles.
6. The method of claim 1, wherein the magnetic particles are configured so that their mass magnetization does not vary more than 10 Am2 kg"1 at all environmental temperatures.
7. The method of claim 1, wherein the magnetic particles are configured to have a room temperature magnetic susceptibility of 16,440 x 10"8 m3kg_1 or greater.
8. The method of claim 1, wherein the magnetic particles are configured to have a magnetic susceptibility that remains relatively unchanged at environmental temperatures higher than room temperature.
9. The method of claim 1, wherein the magnetic particles comprise at least one of the following formulas: Mn0.5Zno.5Fe204, Mno.65Zn0.35Fe204, Mno.35Zn0.65Fe204, and
Figure imgf000038_0001
10. The method of claim 1, wherein the measuring comprises detecting the magnetic particles in the reservoir.
11. The method of claim 10, wherein the detecting comprises the utilization of a magnetometer.
12. The method of claim 1, wherein the measuring is performed with a low field downhole magnetic susceptibility probe.
13. The method of claim 1, wherein the magnetic particles are coated with olelylic acid.
14. A method for determining fluid permeability of a reservoir, wherein the method comprises:
(a) adding magnetic particles to the reservoir;
(b) measuring a magnetic susceptibility of the magnetic particles in the reservoir;
(c) determining the fluid permeability of the reservoir as a function of the measured magnetic susceptibility, wherein the (a), (b), and (c) processes are performed previous to performing a hydraulic fracturing of the reservoir;
(d) performing a hydraulic fracturing of the reservoir; and
(e) repeating the (a), (b), and (c) processes.
15. The method of claim 14, wherein the correlating step comprises comparing predetermined parameter information that is a function of magnetic susceptibility to the measured magnetic susceptibility to determine at least one value associated with the at least one parameter of the reservoir.
16. The method of claim 14, wherein the at least one parameter is selected from the group consisting of fluid permeability, permeability anisotropy, fracture location, and fracture anisotropy.
17. The method of claim 14, wherein the magnetic particles comprise the following formula: MxM'yFe204, where x + y = 1, wherein M or M' comprises at least one of zinc, manganese, cobalt, copper, or vanadium.
18. The method of claim 17, wherein the magnetic particles comprise at least one of the following formulas: Mno.5Zn0.5Fe204, Mno.65Zn0.35Fe204, Mno.35Zn0.65Fe204, and
Figure imgf000039_0001
19. The method of claim 14, wherein the magnetic particles are configured so that their mass magnetization does not vary more than 10 Am2 kg"1 at all environmental temperatures.
20. The method of claim 14, wherein the magnetic particles are configured to have a room temperature magnetic susceptibility of 16,440 x 10"8 m3kg_1 or greater.
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