WO2016007687A1

WO2016007687A1 - Materials for hydraulic fracture mapping

Info

Publication number: WO2016007687A1
Application number: PCT/US2015/039639
Authority: WO
Inventors: Mohan Kanaka Raju PANGA; Alejandro Andres PENA GONZALEZ; Peiwen Xia
Original assignee: Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Holdings Limited; Schlumberger Technology B.V.; Prad Research And Development Limited; Schlumberger Technology Corporation
Priority date: 2014-07-09
Filing date: 2015-07-09
Publication date: 2016-01-14

Abstract

A method for hydraulic fracture mapping of a subterranean formation, the method comprising injecting into a wellbore a first fracturing fluid having a first magnetic and/or conductive material, injecting into the wellbore a second fracturing fluid having a second magnetic and/or conductive material and determining a location of at least one fracture having the first and the second magnetic and/or conductive materials therein using an instrument that is responsive to the first and the second magnetic and/or conductive materials. The first and the second magnetic and/or conductive materials have different material properties, concentrations, and/or shapes.

Description

MATERIALS FOR HYDRAULIC FRACTURE MAPPING

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. Patent Application No. 62/022,331 filed on July 9, 2014, which is herein incorporated by reference.

BACKGROUND

[0002] Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be "produced," that is travel from the formation to the wellbore (and ultimately to the surface), there is a sufficiently unimpeded flowpath from the formation to the wellbore.

[0003] Hydraulic fracturing, also referred to as fracking, is a primary tool for improving well productivity by creating or extending fractures or channels from the wellbore to the reservoir. Pumping of propping granules, or proppants, during the hydraulic fracturing of oil and gas containing earth formations may enhance the hydrocarbon production capabilities of the earth formation.

SUMMARY

[0004] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0005] In one aspect, embodiments disclosed herein relate to a method for hydraulic fracture mapping of a subterranean formation that includes injecting into a wellbore a first fracturing fluid having a first magnetic and/or conductive material; injecting into the wellbore a second fracturing fluid having a second magnetic and/or conductive material; and determining a location of at least one fracture having the first and the second magnetic and/or conductive materials therein using an instrument that is responsive to the first and the second magnetic and/or conductive materials; wherein the first and the second magnetic and/or conductive materials have different material properties, concentrations, and/or shapes.

[0006] In another aspect, embodiments of the present disclosure relate to a method for hydraulic fracture mapping of a subterranean formation, that includes injecting sequentially into a wellbore, alternate stages of at least a clean pulse of fracturing fluid and at least a dirty pulse of a proppant-containing fracturing fluid to fracture the subterranean formation with the formation of at least one fracture, wherein a magnetic and/or conductive material is in at least one of the clean pulse and dirty pulse; and determining a location of the at least one fracture having the magnetic and/or conductive material therein using an instrument that is responsive to the magnetic and/or conductive material.

[0007] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0008] FIGS. 1 and 2 show the proppant distribution following a fracturing treatment.

[0009] FIGS. 3 and 4 show the proppant distribution as a result of alternating proppant fluid-stage.

[0010] FIGS. 5 and 6 show methods of measuring a physical property of a magnetic and/or conductive material according to the present embodiments.

DETAILED DESCRIPTION

[0011] Generally, embodiments disclosed herein relate to materials and methods of using the same for detecting and localizing fractures created during a fracturing treatment and their distribution in a subterranean formation. More specifically, embodiments disclosed herein relate to magnetic and/or conductive materials used for hydraulic fracture mapping of subterranean formations using electromagnetic tools or a combination of seismic and electromagnetic (EM) tools. The inventors of the present disclosure have found that the location of fractures created after a hydraulic fracturing treatment and the extent to which the proppants have penetrated into the fracture may be determined by incorporating magnetic and/or conductive materials in a proppant composition used for propping a subterranean formation, or by suspending such materials in a fracturing fluid in the absence or the presence of proppants, using EM tools or a combination of seismic and electromagnetic tools that are responsive to the magnetic and/or conductive materials.

[0012] As shown in FIG. 1, hydraulic fracturing injects a viscous fluid into a wellbore 1 penetrating an oil and gas bearing earth formation 2 and forcing the fracturing fluid through perforations 4 against the formation strata by pressure, which results in the creation or growth of fractures 5 within the earth formation 2. These fractures 5 serve as conduits for the flow of hydrocarbons trapped within the formation 2 to the wellbore 1. To keep the fractures 5 open and capable of supporting the flow of hydrocarbons to the wellbore 1 , proppants 6 are delivered to the fracture 5 within the formation by a carrier fluid and fill the fracture 5 with a proppant pack 6 that is strong enough to resist closure of the fracture 5 due to formation pressure and is also permeable for the flow of the fluids within the formation. Once the pressure is released, the fracture 5 shrinks to fracture 15 as shown in FIG. 2, packing down the proppant 16 that remains in the same location near the perforations. In such a case, the "wedge of proppant" can maintain an open (conductive) fracture for some distance above and laterally away.

[0013] Referring now to FIG. 3, a heterogeneous proppant placement in a fracture is shown. As seen in FIG. 3, a wellbore 1 can be completed with perforations 4 in the formation 2. Proppant materials may be intermitently injected into the same fracturing fluid 29 through the wellbore 1 into a fracture 5. The fracturing fluid has sufficient viscosity to suspend the proppants during injection and heterogeneous ly place them in bundles of proppant or proppant cluster 8 spread along the fracture. In one or more embodiments, the proppant clusters 8 may be separated by channelant-rich regions (not shown) which may be removed, after the fracture is allowed to close, by various methods such as flushing, dissolving, softening, melting, breaking, etc. [0014] Referring still to FIG. 3, the clusters 8 of proppant are spread out along a large fraction (if not all) of the fracture length. Upon closing of fracture 5, the proppant clusters 8 compress to form pillars 28 to support the fracture 25 (as shown in FIG. 4) and prevent the opposing fracture faces from contacting each other, creating higher overall conductivity and effective fracture half-length. As a result, when the pressure is released, the clusters 28 remain spread along the whole fracture and minimize the shrinkage of the fracture 25. Next, the formation fluid may be allowed to invade (not shown) the fracture 5 to displace any channelant, or any unconsolidated proppant or other particles from the proppant-lean regions. A network of interconnected open channels 26 can thus be formed around the pillars 28 to provide the fracture 25 with high conductivity for fluid flow. The fluid systems can be alternated many times to achieve varied distribution of the clusters in the hydraulic fracture. By sequentially injecting into the wellbore alternate stages of fracturing fluids having a contrast in their ability to transport propping agents to improve proppant placement, or having a contrast in the presence or amount of transported propping agents, the well productivity is increased.

[0015] Proppants may comprise naturally occurring sand grains or gravel, man-made or specially engineered proppants, such as fibers, resin-coated sand, or high-strength ceramic materials, e.g. sintered bauxite. The proppant collects heterogeneously or homogenously inside the fracture to "prop" open the new cracks or pores in the formation. The proppant creates planes of permeable conduits through which production fluids can flow to the wellbore. The fracturing fluids are of high viscosity, and therefore capable of carrying effective volumes of proppant material.

[0016] Hydraulic fractures can extend to several hundred to thousand feet away from the wellbore, and in some cases complex fracture networks are generated depending on the reservoir. Conventionally, it is very difficult to predict how far the fracture has extended, the direction in which it propagated and the number of secondary and tertiary fractures that are created. Further, the extent to which proppant has penetrated into the fractures is also difficult to predict. Often the proppant pumped does not enter all the fractures and the depth of penetration is not known. Therefore, it is not clear how many of the created fractures are propped and are contributing to the production. Without the knowledge of created fracture network and propped fractures, it is not an easy task to determine which parts of the reservoir are drained through the fracture network and which parts still contain valuable hydrocarbons. While hydraulic fractures may be mapped using seismic tools that detect acoustic signals which are generated during the fracturing job, these tools cannot detect how far proppant has penetrated into the fractures.

[0017] Thus, the fracturing fluids of the present disclosure incorporate magnetic and/or conductive materials therein to provide for hydraulic fracture mapping of subterranean formations using electromagnetic tools. The magnetic and/or conductive materials act as a "tracer" that helps in determining the path of the fracturing fluid and the complexity of the fractures created, as well as the location and the extent to which proppants have penetrated into a fracture after the fracturing job has been completed. According to the present disclosure, the magnetic and/or conductive materials may have different material properties, concentrations and/or shapes. In various embodiments, the amount of magnetic and/or conductive materials present in a fracturing fluid may be up to 15 pounds/gallon.

[0018] According to the present embodiments, the magnetic and/or conductive materials may be dispersed in a body of a proppant, may be coated on a surface of a proppant or may be incorporated in a resin of a proppant. The coating may be accomplished by any coating technique well known to those of ordinary skill in the art such as spraying, sputtering, vacuum deposition, dip coating, extrusion, powder coating, transfer coating, air knife coating, roller coating and brush coating. In various embodiments a coating on a magnetic and/or conductive material may be formed by way of a reaction of a preformed proppant with a magnetic and/or conductive material in the presence of a polymer crosslinker. In such embodiments, the resulting coated magnetic and/or conductive material may have the same physical properties as its base material. Further, depending on the particular fracturing job being mapped, it is also envisioned that the magnetic and/or conductive material may be suspended in a fracturing fluid in the presence or the absence of a proppant. In cases where the magnetic and/or conductive material is pumped in the absence of a proppant, flakes, fibers, springs, finely ground particles, hollow particles, or the like of the magnetic and/or conductive material may be used. Further, it is also envisioned that such flakes may be used in a fracturing fluid in conjunction with proppants. Such shapes may have particular use in determining the location of secondary and tertiary fractures. Specifically, the shape of the flakes may make the magnetic and/or conductive materials more easily transported into those secondary and tertiary fractures so that the complexity of the fractures created may be visualized. In the case of flakes, it is believed that the flakes may become concentrated into a mat or other three-dimensional framework, which holds the proppant thereby limiting its flowback. Further, it is also envisioned that fluids containing the magnetic and/or conductive materials in the shape of flakes may have varied concentrations in different stages so that when the magnetic and/or conductive materials are detected at the end of the fracturing treatment, the complexity of fractures created during a fracturing job can be detected.

[0019] As described herein, magnetic materials generally refer to materials that are affected by magnetic fields. Depending on the influence that a magnetic field has on a material, magnetic materials are classified as paramagnetic, diamagnetic and antiferromagnetic. As described herein, conductive materials, or electrically conductive materials, are materials that have the ability of conducting an electric current. Electrical resistivity, or resistivity, is an intrinsic property that quantifies how strongly a given material opposes the flow of electric current. Different methods of deploying these materials can be used to map the hydraulic fractures and the extent to which the proppant has penetrated into these fractures. According to the present embodiments, the materials that have shown utility in the fracturing slurries of the present disclosure are magnetic and/or conductive materials, exhibiting both magnetic properties and electric conductivity. The magnetic and/or conductive materials that have shown utility in the fracturing slurries of the present disclosure may be ferromagnetic or paramagnetic materials.

[0020] Various magnetic and/or conductive materials such as metals or alloys may be used in a fracturing fluid. The magnetic and/or conductive materials that have shown utility in the fracturing slurries of this disclosure may include metal, metal alloys, metal oxides, sulphides and minerals that contain iron, nickel, cobalt, copper, silver, magnesium, titanium and manganese. Examples of some metal alloys and minerals may include steel, permalloy, magnetite, and haematite. Other materials that may be used include graphite, conductive carbon black, ilmenite, pyrrhotite, staurolite, rutile, leucoxene, lodestone.

[0021] According to the present disclosure, the hydraulic fracturing treatment may be performed for example as described above in FIGS. 1-2 or 3-4. As the fracturing fluid is forced against the formation strata by pressure, the formation strata or rock is forced to crack and fracture. As a result, the magnetic and/or conductive material present in the fracturing fluid migrates through the mineral formation a desired distance from the wellbore and may be detected using an EM tool alone or in combination with a seismic tool.

[0022] In various embodiments, magnetic and/or conductive materials may be incorporated in a fracturing fluid and pumped continuously in all proppant stages of a fracturing job. After the job, a source and detector EM tools are used to visualize the difference of resistivity images before and after fracturing treatment, and before and after different proppant stages. In such embodiments, it may be desirable to vary the proppant concentration through the different stages and use the visualization to determine the optimum proppant concentration for the job. The EM tools may be run between the stages and/or after the job is complete. In embodiments where the EM tool is run between the stages, the development of the fracture network may be visualized and depending on the results, any aspect of the job design (such as proppant concentration, size, density, fluid viscosity, pump rate, etc.) may be changed accordingly. Further, the magnetic and/or conductive materials may be used at the beginning, middle and/or the end of the fracturing job. It is also envisioned that during a continuous pumping of the magnetic and/or conductive proppants-containing fracturing fluids, the concentration of the proppant may increase, stay constant, or decrease during the propped stage.

[0023] In various embodiments, magnetic and/or conductive proppants with different concentrations may be used during different proppant stages. For example, in one or more embodiments, the magnetic and/or conductive proppants incorporated into a fracturing fluid may contain two different concentrations of the magnetic and/or conductive material. In the initial fracturing stages, a first set of proppants containing a given concentration of a magnetic and/or conductive material may be pumped. In the later stages of the fracturing treatment, proppants containing a different concentration of magnetic and/or conductive material may be pumped. In such embodiments, at the end of the treatment, the location of the magnetic and/or conductive material is detected to determine the evolution of the fracture during the treatment. As mentioned above, depending on the visualization of the evolution, one or more aspects of the job design may be changed.

[0024] In addition to and/or instead of using different concentrations of magnetic and/or conductive materials, another embodiment may provide for magnetic and/or conductive proppants containing two different types of magnetic and/or conductive material being used in a fracturing job. In the initial stages of the treatment, a first set of proppants containing the first type of magnetic and/or conductive material may be pumped. In the later stages, proppants containing a different type of magnetic and/or conductive material may be pumped. At the end of the fracturing treatment, the location of proppants may be detected to determine the evolution of the fracture during the treatment.

[0025] Various embodiments may also use a diverter fluid in combination with a magnetic and/or conductive proppant-containing fracturing fluid. For example, within a given fracturing stage, the location and network of a first set of fracture clusters formed in a horizontal well may be determined by first pumping a magnetic and/or conductive proppant in the first stage of a fracturing zone. Afterwards, a diverter slug may be pumped into the fracturing zone to divert the fracturing fluid to other fracture clusters. After the diverter slug is pumped, a fracturing fluid containing a different concentration of magnetic and/or conductive material may be pumped. It is also envisioned that after the diverter slug is pumped, magnetic and/or conductive proppants that contain a different type of magnetic material may instead be pumped downhole. At the end of the fracturing treatment, EM tools may be used to determine the location of the two concentrations or types of magnetic and/or conductive material and determine if the fracture diversion was successful.

[0026] As mentioned above, embodiments of the present disclosure may involve the use of magnetic and/or conductive proppants in fracturing treatments when the proppant is pumped continuously, as well as sequentially injecting into the wellbore alternate stages of fracturing fluids with and without proppant, which may be referred to as "pulse fracturing".

[0027] The general concept of "pulse fracturing" will now be described. In a hydraulic fracturing method for a subterranean formation, a first stage referred to as the "pad stage" involves injecting a fracturing fluid into a wellbore at a sufficiently high flow rate that creates a hydraulic fracture in the formation. The pad stage is pumped until the fracture is of sufficient dimensions to accommodate the subsequent slurries pumped in the proppant stages. After the "pad stage", several stages referred to as "proppant stages" or "propped stages" are injected into formation, in which solid proppant particles are suspended in the fluid. While conventional fracturing techniques may include the continuous introduction of proppants, embodiments also include the periodic introduction of proppants. In such embodiments, referring back to FIG. 3, a proppant stage 29 involves the periodical introduction of proppants into the fracturing fluid to form a suspension. Thus, the propped stage may be divided into two periodically repeated sub- stages, the "carrier sub-stage" or the "clean pulse" 26 that involves injection of fracturing fluid without proppant, and the "propping sub-stage" or the "dirty pulse" 27 that involves addition of proppant into the fracturing fluid. As a result of the periodic slugging of slurry containing proppant, the proppant does not completely fill the fracture. Rather, spaced proppant clusters 28 (as shown in FIG. 4) form as posts or pillars with channels 26 between them for fluids to pass between the pillars. The volumes of dirty pulse 27 and clean pulse 26 as pumped may be different, or may change over time.

[0028] In one or more embodiments, the dirty pulse 27 may include a fracturing fluid containing proppant and magnetic and/or conductive materials (optionally integrated into proppant) while the clean pulse 26 may contain the fracturing fluid (free of proppants and magnetic and/or conductive materials). In such embodiments, the magnetic and/or conductive materials may be included in the fracturing fluid 29 at the beginning, middle and/or the end of a dirty pulse 27. In such a way, the location (and/or distribution) of proppant pillars in the fracture may be determined

[0029] In one or more embodiments, the clean pulse 26 may contain a magnetic and/or conductive material-containing fracturing fluid, while the dirty pulse 27 may contain a proppant-containing fracturing fluid. In various embodiments, the magnetic and/or conductive materials may be included in the fracturing fluid 29 at the beginning, middle and/or the end of a clean pulse 26. In such embodiments, the magnetic and/or conductive materials may be in the form of flakes, i.e., not in the form of or functioning as proppants. It is also envisioned that both the clean pulse and dirty pulse may contain magnetic and/or conductive materials, for example, in differing concentrations, materials, etc. to differentiate between the two at the end of the fracturing job.

[0030] In such embodiments, at the end of the fracturing job, the location of the pillars may be determined using EM tools, or a combination of EM and seismic tools. Incorporation of magnetic and/or conductive materials in the clean pulses may allow for an operator to determine the distribution of the clean pulses (and formation of pillars) and/or determine when the clean pulses are flowing past the formed pillars and collecting in a given location. In such a case, the job design may be redesigned to obtain better distribution of the pillars through the fracture. Specifically, parameters such as viscosity, density, pumping rate of the fracturing fluid, concentration and size of the proppants may be selected and varied by the operator based on how much of the surface area of the fracture is desired to be supported by proppant pillars, and how much of the fracture area has open channels through which formation fluids are free to flow, as well as the desired distribution of the pillars through the fracture. The various combinations of fluids and magnetic and/or conductive materials may be designed based on the individual well conditions to obtain the optimum well production.

[0031] In any of the above embodiments, after the fracturing job is completed (or whenever mapping is desired, which does not have to be at the end of a fracturing job, but may be in the middle of the job), a source and a detector tool are placed in the fractured well. As it will be described later, it is also envisioned that the detector tool may be placed in an observation well which is spaced apart from the fractured well. As noted above, the tools that have shown utility in the hydraulic fracture mapping methods of the present disclosure are electromagnetic (EM) tools or a combination of seismic and EM tools. The EM and/or EM/seismic tools are responsive to the magnetic and/or conductive materials and help to characterize the formation and the fractions formed. For example, the detector tool detects the signals sent by the source tool which have been modified by their interaction with the magnetic and/or conductive material. Therefore, the intensity of the detected signals is determined by the concentration, type and shape of the magnetic and/or conductive materials. The EM and/or EM/seismic tools or devices may be positioned along various heights of the reservoir and can be oriented such that a series of strata can be measured to create a 3D image of the fracture. For example, physical properties of the migrated magnetic and/or conductive materials, such as resistivity, may be measured at the end of the fracturing treatment to determine the fracture complexity, as well as to detect how far the fracture extended.

[0032] Referring now to FIG. 5, a fractured well 1 is depicted. After the fracturing job is completed, a source 50 and a detector 51 EM tools are both placed in the fractured well 1. The EM source tool 50 sends signals that may be detected by the detector 51. For example, the dotted lines 52-54 seen in FIG. 5 show the intensity of the electromagnetic field emitted by the source 50. The electromagnetic field may interact with the magnetic and/or conductive materials present in the formed fracture and a distortion of a physical property, such as a difference of resistivity images before and after the fracturing treatment, may be visualized. Similarly, the resistivity may also be distorted before and after different proppant stages with different proppant concentrations.

[0033] It is also envisioned that the source 50 and the detector 51 are placed into two separate wells. Referring now to FIG. 6, a fractured well 1 and an observation well 3 are depicted. As seen in FIG. 6, the two wells 1 and 3, respectively, are spaced apart. After the fracturing job is done, a source 50 and a detector 51 EM tools are placed in the fractured well 1, and respectively the observation well 3. The EM source tool 50 may send signals that are detected by the detector 51. Similar to the embodiment described in FIG. 5, the lines 55-57 show the intensity of the electromagnetic field emitted by the source 50. The electromagnetic field may interact with the magnetic and/or conductive materials present in the fracture created, and a difference of resistivity images before and after the fracturing treatment may be visualized. Similarly, the resistivity may also be distorted before and after different proppant stages with different proppant concentrations.

[0034] Hydraulic fracturing fluids of the present disclosure may be aqueous solutions containing a thickener, such as a soluble polysaccharide, to provide sufficient viscosity to transport the proppant. Typical thickeners are polymers, such as guar (phytogeneous polysaccharide), and guar derivatives (hydropropyl guar, carboxymethylhydropropyl guar). Other polymers and other materials, such as xanthan, scleroglucan, cellulose derivatives, polyacrylamide and polyacrylate polymers and copolymers, viscoelastic surfactants, and the like, can be used also as thickeners. For example, water with guar represents a linear gel with a viscosity that increases with polymer concentration. Cross- linking agents are used which provide engagement between polymer chains to form sufficiently strong couplings that increase the gel viscosity and create visco-elasticity. Common crosslinking agents for guar include boron-, titanium-, zirconium-, and aluminum-laden chemical compounds.

[0035] Proppants according to embodiments of the present disclosure can be sand, ceramic proppants (such as those available from Carbo Ceramics, Norton Proppants, etc.), sintered bauxites and other materials known to the industry. Any of these base propping agents can further be coated with a resin (such as that available from Santrol, a Division of Fairmount Industries, Borden Chemical, etc.) to potentially improve the clustering ability of the proppant. In addition, the proppant can be coated with resin or a proppant flowback control agent such as fibers for instance can be simultaneously pumped. By selecting proppants having a contrast in one of such properties such as density, size and concentrations, different settling rates will be achieved. [0036] Fibers can be used to enhance the ability of the fracturing fluids to transport proppant and to mitigate proppant settling within the hydraulic fracture. For operations in which proppant is pumped in slugs or pulses, fibers can also be used to mitigate the dispersion of the proppant slugs as they travel throughout the well completion and into the fracture.

[0037] Proppant flow back control agents can also be used during the latter stages of the hydraulic fracturing treatment to limit the flow back of proppant placed into the formation. For instance, the proppant may be coated with a curable resin activated under down hole conditions. Different materials, such as bundles of fibers, or fibrous or deformable materials, also have been used to retain proppants in the fracture. Presumably, fibers form a three-dimensional network in the proppant pack that limits its flow back.

[0038] Advantageously, embodiments of the present disclosure provide methods using magnetic and/or conductive materials for hydraulic fracture mapping using EM tools or a combination of seismic and electromagnetic tools that are responsive to the magnetic and/or conductive materials. For example, using methods of the present disclosure, the location of fractures created after a hydraulic fracturing treatment, as well as the extent to which the proppants have penetrated into the fracture may be determined. The magnetic and/or conductive materials may be suspended in fracturing fluids in the absence or the presence of a proppant, or may be incorporated in a proppant composition used for propping a subterranean formation. Another aspect of the present disclosure is that the methods as described herein allow for localizing active perforations clusters, while increasing the conductivity of the fracture. Furthermore, the methods as described herein may provide reduced environmental risk.

[0039] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words 'means for' together with an associated function.

Claims

CLAIMS What is claimed:

1. A method for hydraulic fracture mapping of a subterranean formation, the method comprising:

injecting into a wellbore a first fracturing fluid having a first magnetic and/or conductive material;

injecting into the wellbore a second fracturing fluid having a second magnetic and/or conductive material; and

determining a location of at least one fracture having the first and the second magnetic and/or conductive materials therein using an instrument that is responsive to the first and the second magnetic and/or conductive materials;

wherein the first and the second magnetic and/or conductive materials have different material properties, concentrations, and/or shapes.

2. The method of claim 1, further comprising pumping into the wellbore a diverter slug between injecting the first and the second fracturing fluids to divert the first fracturing fluid to other proppant clusters.

3. The method of claim 2, wherein a concentration of the second magnetic and/or conductive material is higher than a concentration of the first magnetic and/or conductive material.

4. The method of claim 1 , wherein the first and second magnetic and/or conductive materials have a flake or fiber-like shape.

5. The method of claim 4, wherein the second fracturing fluid has the first magnetic and/or conductive material at a higher concentration than the first fracturing fluid.

6. The method of claim 1, wherein determining the location of the at least one fracture further comprises placing a source tool in a fractured well and a detector tool in an observation well of the subterranean formation, wherein the fractured well and the observation well are placed apart from each other.

7. The method of claim 6, wherein the detector tool is an electromagnetic tool or a combination of a seismic and an electromagnetic tool.

8. The method of claim 1 , wherein the first and the second magnetic and/or conductive materials are dispersed in a body of a proppant.

9. The method of claim 1 , wherein the first and the second magnetic and/or conductive materials are coated on a surface of a proppant.

10. The method of claim 1, wherein the first and the second magnetic and/or conductive materials are incorporated in a resin coat of a proppant.

1 1. The method of claim 1 , wherein the first and the second magnetic materials are selected from the group of paramagnetic or ferromagnetic materials.

12. A method for hydraulic fracture mapping of a subterranean formation, the method comprising:

injecting sequentially into a wellbore, alternate stages of at least a clean pulse of fracturing fluid and at least a dirty pulse of a proppant-containing fracturing fluid to fracture the subterranean formation with the formation of at least one fracture, wherein a magnetic and/or conductive material is in at least one of the clean pulse and dirty pulse; and

determining a location of the at least one fracture having the magnetic and/or conductive material therein using an instrument that is responsive to the magnetic and/or conductive material.

13. The method of claim 12, wherein the magnetic and/or conductive material is used in at least one of the dirty pulses.

14. The method of claim 12, wherein the magnetic and/or conductive material is used in at least one of the clean pulses.

15. The method of claim 12, wherein the instrument is an electromagnetic tool or a combination of a seismic and an electromagnetic tool.

16. The method of claim 12, wherein the magnetic and/or conductive material is dispersed in a body of a proppant.

17. The method of claim 12, wherein the magnetic and/or conductive material is coated on a surface of a proppant.

18. The method of claim 12, wherein the magnetic and/or conductive material is incorporated in a resin coat of a proppant.

19. The method of claim 12, wherein the magnetic and/or conductive material is suspended in a fracturing fluid with or without a proppant.

20. The method of claim 19, wherein the magnetic and/or conductive material is selected from flakes, fibers, springs, finely ground particles, and hollow particles.