HK1242754B - Infused and coated proppant containing chemical treatment agent and methods of using same - Google Patents

Description

Injected and coated proppants containing chemical treatments and methods of using the same

Technical Field

The present invention relates to proppants containing chemical treatments to improve production rates and ultimate recovery from oil or gas wells.

The present invention also relates to methods of using tracer-containing proppants to evaluate the effectiveness and performance of hydraulic fracturing stimulation treatments in oil or gas wells.

Background Art

Oil and natural gas are produced from wells having porous and permeable underground rock formations. The porosity of the rock formation allows it to store oil and gas, while the permeability of the rock formation allows the oil or gas fluid to move through the rock formation. The permeability of the rock formation is necessary to allow the oil and gas to flow to a position where they can be pumped out of the well. Sometimes the gas or oil is retained in a rock formation whose permeability is insufficient to economically recover the oil and gas. In other cases, during the operation of the well, the permeability of the rock formation decreases to a point where further recovery becomes uneconomical. In such cases, the rock formation must be fractured and the fractures propped open with the help of support materials or proppants. Such fractures are usually accomplished by hydraulic pressure, and the support materials or proppants are granular materials, such as sand, glass beads or ceramic particles, which are drawn into the fractures with the help of the fluid.

During the production process, oil and gas wells often exhibit scaling and/or wax deposition that can reduce well production. Many types of chemical treatments have been used to prevent scaling and/or wax deposition. One technique for delivering such chemical treatments downhole includes injecting porous ceramic proppant particles with the chemical treatment. In many cases, the chemical treatment must first be dissolved in an aqueous solvent, an organic solvent, or an inorganic solvent so that the chemical treatment can be injected into the porous ceramic proppant particles. However, if the chemical treatment is too viscous, this may result in the effective amount of the chemical treatment present in the injected proppant being less than the desired amount or causing the overall injection to be uneven or ineffective. Dissolving the chemical treatment in a solvent is also an additional step, which may be expensive and time-consuming.

Tracers have also been used in hydraulic fracturing to provide certain types of diagnostic information about the location and orientation of fractures. Tracers used in hydraulic fracturing have been associated with various carrier materials in the form of particles from which the tracer itself is released after the particles are placed in the hydraulic fracture created. These tracer particles are typically composed of a tracer substance and a carrier, where the carrier is composed of starch or a polymeric material. Carriers such as starch or polymeric materials are weak materials and may adversely affect conductivity if added to proppants in hydraulic fractures. In addition, the density of starch or polymeric carrier materials is not similar to that of proppants typically used in hydraulic fracturing, resulting in density segregation, which can cause uneven distribution of the tracer chemical in the created fracture.

Therefore, what is needed is a method for adding chemical treatments to proppant particles without the need for solvents.What is also needed is a tracer carrier that does not segregate from the proppant and adversely affect conductivity when added to a subterranean environment.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention may best be understood by referring to the following description and accompanying drawings which illustrate embodiments of the invention. In the drawings:

1 is a cross-sectional view of a coated proppant having a chemical treatment disposed between a coating and a proppant particulate, according to several exemplary embodiments described herein.

2 is a cross-sectional view of a coated proppant including a chemical treatment dispersed within a coating according to several exemplary embodiments described herein.

3 is a cross-sectional view of an encapsulated proppant having a degradable, impermeable shell encapsulating a coated proppant comprising a chemical treatment infused into the porous proppant particulate, according to several exemplary embodiments described herein.

4 is a cross-sectional view of an encapsulated proppant having a degradable, impermeable shell encapsulating an uncoated proppant comprising a chemical treatment injected into the porous proppant particulates, according to several exemplary embodiments described herein.

5 is a cross-sectional view of an encapsulated proppant having a degradable, impermeable shell encapsulating a coated proppant comprising a chemical treatment disposed between a resin coating and the proppant particulate, according to several exemplary embodiments described herein.

6 is a graphical representation comparing the proppant permeability of lightweight ceramic proppants, medium density ceramic proppants, and high density ceramic proppants.

7 is a graphical representation of the long term permeability of a standard non-porous lightweight ceramic proppant and a lightweight porous ceramic proppant (25% porosity).

8 depicts a perspective view of an illustrative pre-packed screen assembly including a proppant pack, according to several exemplary embodiments described herein.

FIG. 9 depicts a cross-sectional view of the pre-filled screen taken along line 8 - 8 of FIG. 8 .

10 depicts a cross-sectional side view of the assembly with the canister positioned within the tube.

FIG. 11 depicts a cross-sectional end view of the canister shown in FIG. 10 .

FIG. 12 depicts a perspective view of the canister shown in FIGs. 10 and 11 .

13 is a graph of the elution profiles for Example 1, showing parts per million (ppm) of DTPMP (diethylenetriaminepenta(methylenephosphonic acid)) released as a function of time from a porous ceramic proppant injected with DTPMP and encapsulated with various coatings.

14 is a graph of the elution profile for Example 2, showing the ppm of DTPMP released as a function of time from a porous ceramic proppant infused with DTPMP and encapsulated with various coatings.

15 is a graph of the elution profile for Example 3, showing the ppm of DTPMP released as a function of time from a porous ceramic proppant infused with DTPMP and encapsulated with various coatings.

FIG. 16 is a graph of the elution curves of Example 4, showing the ppm of DTPMP released as a function of time from porous ceramics infused with DTPMP and encapsulated with degradable shells of varying thicknesses and without encapsulation with degradable shells of varying thicknesses.

Detailed Description of the Invention

In the following description, numerous specific details are set forth. However, it should be understood that embodiments of the present invention can be practiced without these specific details. In other instances, well-known structures and techniques are not shown or described in detail to avoid obscuring the understanding of this specification. Furthermore, when used herein, the term "exemplary" is intended to mean illustrative or exemplary and is not intended to indicate a preferred approach.

As used herein, the term "apparent specific gravity" is the weight of a particle per unit volume (g/cm3), including internal porosity. The apparent specific gravity values given herein were determined by the Archimedean method of liquid (water) displacement according to API RP60, a method well known to those skilled in the art. For the purposes of this disclosure, the method for testing proppant properties with respect to apparent specific gravity is the standard API test routinely performed on proppant samples. Furthermore, as used herein, the term "exemplary" is intended to mean illustrative or exemplary and is not intended to indicate a preferred approach.

As used herein, the term "conductivity" is defined as the product of the width of the created fracture and the permeability of the proppant retained in the fracture.

As used herein, the term "high-density proppant" means a proppant having an apparent specific gravity greater than 3.4 g/ ^cm3 .

As used herein, the term "medium density proppant" means a proppant having an apparent specific gravity of about 3.1 to 3.4 g/ ^cm3 .

As used herein, the term "internal interconnected porosity" is defined as the percentage of pore volume or void volume space relative to the total volume of the porous ceramic particle.

As used herein, the term "lightweight proppant" means a proppant having an apparent specific gravity of less than 3.0 g/ ^cm3 .

As used herein, the term "degradable" means that the chemical or coating is capable of reacting to dissolve or break down into smaller components under one or more downhole conditions.

As used herein, the term "infusion" refers to causing a material to be infused, attached, introduced, or otherwise contained within a porous substrate (eg, a porous ceramic).

As used herein, the term "ceramic" refers to any non-metallic, inorganic solid material.

As used herein, the term "ceramic proppant" refers to any man-made or synthetic ceramic particulate.

As used herein, the term "proppant" refers to a material comprising one or more (eg, tens, hundreds, thousands, millions, or more) individual proppant particles or elements.

Disclosed are proppant particles containing one or more chemical treatment agents for hydraulic fracturing. The one or more chemical treatment agents can be disposed, attached, coated, injected, combined, or otherwise contained on or in the proppant particles to produce proppants containing one or more chemical treatment agents, also referred to as chemical treatment agent-containing proppant particles. The proppant particles can be or include ceramic particles. The ceramic particles can include sand, porous ceramic proppants, and non-porous ceramic proppants. The chemical treatment agent-containing proppant particles can be coated with a resin material. The chemical treatment agent-containing proppant particles can also be uncoated.

Also disclosed herein are encapsulated proppant particles containing one or more chemical treatment agents for hydraulic fracturing. In one or more exemplary embodiments, the encapsulated proppant particles can include proppant particles containing a chemical treatment agent coated or encapsulated with a degradable outer coating, layer, or shell. This degradable outer shell or degradable shell can temporarily separate the chemical treatment agent proppant particle from the surrounding liquid (e.g., fracturing fluid) to prevent premature release of the chemical treatment agent into, for example, the fracturing fluid.

Also disclosed is a composite proppant composition for hydraulic fracturing. The composite ceramic proppant may comprise a coated particulate portion and an uncoated particulate portion, wherein the coated particulate portion comprises a chemical treatment agent. In one or more exemplary embodiments, the composite proppant composition has a permeability and conductivity that is at least equal to the permeability and conductivity of the coated particulate portion alone. Furthermore, in one or more exemplary embodiments, the permeability and conductivity of the coated particulate portion alone are at least equal to the permeability and conductivity of the composite proppant composition. The composite ceramic proppant may also comprise an encapsulated proppant particulate portion and a proppant particulate portion that does not contain a chemical treatment agent, wherein the encapsulated proppant particulate portion comprises a chemical treatment agent. In one or more exemplary embodiments, the composite proppant composition has a permeability and conductivity that is at least equal to the permeability and conductivity of the encapsulated proppant particulate portion alone. Furthermore, in one or more exemplary embodiments, the permeability and conductivity of the encapsulated proppant particulate portion alone are at least equal to the permeability and conductivity of the composite proppant composition.

In one or more exemplary embodiments, another composite ceramic proppant composition for hydraulic fracturing is disclosed. In one or more exemplary embodiments, the composite ceramic proppant comprises a non-porous particulate portion and a porous ceramic particulate portion, wherein the porous ceramic particulates are infused with or otherwise contain a chemical treatment agent. Furthermore, in one or more exemplary embodiments, the composite ceramic proppant composition exhibits a permeability and conductivity at least equal to the permeability and conductivity of the non-porous particulate portion alone.

The microparticle portion or proppant microparticles can be ceramic proppant, sand, resin-coated sand, plastic beads, glass beads or other ceramic or resin-coated proppant. Such proppant microparticles can be manufactured according to any suitable method, including but not limited to continuous spray atomization, spray fluidization, drip casting, spray drying or compression. Suitable proppant microparticles and manufacturing methods are disclosed in U.S. Patent Nos. 4,068,718, 4,427,068, 4,440,866, 5,188,175, 7,036,591, 8,865,631 and 8,883,693, U.S. Application Publication No. 2012/0227968 and U.S. Patent Application Nos. 14/502,483 and 14/802,761, the complete disclosures of which are incorporated herein by reference.

FIG1 is a cross-sectional view of a coated proppant 100 including a chemical treatment 102 disposed between a coating 104 and a proppant particle 106, according to one or more embodiments. A layer 108 of chemical treatment 102 can be formed between coating 104 and proppant particle 106. For example, layer 108 of chemical treatment 102 surrounds and/or is deposited on outer surface 107 of proppant particle 106. Layer 108 of chemical treatment 102 can coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface area of proppant particle 106. For example, layer 108 of chemical treatment 102 can coat or cover about 100% of the entire outer surface area of proppant particle 106. The coating 104 can coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface area of the layer 108 of the chemical treatment 102 disposed on the proppant particulate 106. For example, the coating 104 can coat or cover about 100% of the entire outer surface area of the proppant particulate 106 covered or coated by the layer 108 of the chemical treatment 102, such that the layer 108 is disposed between the particulate 106 and the coating 104. The coating 104 can include any suitable resin material and/or epoxy material, as disclosed herein. The coating 104 can be degradable or non-degradable.

According to several exemplary embodiments, chemical treatment 102 is present on proppant particulate 106 in any suitable amount. According to several exemplary embodiments, coated proppant 100 comprises at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of chemical treatment 102, based on the total weight of coated proppant 100. According to several exemplary embodiments, coating 104 is present on proppant particulate 106 in any suitable amount. According to several exemplary embodiments, coated proppant 100 comprises about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, about 3.5 wt%, or about 5 wt% to about 8 wt%, about 15 wt%, about 30 wt%, about 50 wt%, or about 80 wt% of resin material, based on the total weight of coated proppant 100.

The layer 108 of the chemical treatment 102 can have any suitable thickness. The layer 108 can have a thickness of at least about 0.1 nm, at least about 0.5 nm, at least about 1 nm, at least about 2 nm, at least about 4 nm, at least about 8 nm, at least about 20 nm, at least about 60 nm, at least about 100 nm, or at least about 200 nm. For example, the layer 108 can have a thickness of from about 1 nm, about 5 nm, about 10 nm, about 25 nm, about 50 nm, about 100 nm, or about 150 nm to about 200 nm, about 300 nm, about 500 nm, or about 1,000 nm or more.

FIG2 is a cross-sectional view of a coated proppant 200 including a chemical treatment 102 dispersed within a coating 204, according to one or more embodiments. The chemical treatment 102 can be uniformly or substantially uniformly dispersed throughout the coating 204. The coating 204 can include the chemical treatment 102 in any suitable amount. For example, the coating 204 can have a concentration of chemical treatment 102 of at least about 0.01% by weight, at least about 0.1% by weight, at least about 0.5% by weight, at least about 1% by weight, at least about 2% by weight, at least about 4% by weight, at least about 6% by weight, or at least about 10% by weight, based on the weight of the coating 104. The coating 204 can include any suitable resin material and/or epoxy material disclosed herein. The coating 204 can be degradable or non-degradable.

In one or more exemplary embodiments, layer 108 of chemical treatment 102 can be formed between coating 204 and proppant particles 106. For example, layer 108 of chemical treatment 102 can surround and/or be deposited on outer surface 107 of proppant particles 106 in any suitable manner, as disclosed above with reference to FIG. Coated proppant 200 can include chemical treatment 102 in any suitable amount. According to several exemplary embodiments, coated proppant 200 includes at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of chemical treatment 102, based on the total weight of coated proppant 200. Coated proppant 200 can include resin material in any suitable amount. According to several exemplary embodiments, coated proppant 200 comprises about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, about 3.5 wt%, or about 5 wt% to about 8 wt%, about 15 wt%, about 30 wt%, about 50 wt%, or about 80 wt% of the resin material, based on the total weight of coated proppant 200.

FIG3 is a cross-sectional view of an encapsulated proppant 300 having a degradable, impermeable shell 302 encapsulating a coated proppant comprising a chemical treatment 102 infused into a porous proppant particle 106 and surrounded by a resin coating 104. The resin coating 104 may be applied to the porous proppant particle 106. The degradable shell 302 may be applied directly or indirectly to an outer surface 308 of the resin coating 104. The degradable shell 302 may coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface area of the coated proppant. For example, the degradable shell 302 may coat or cover about 100% of the entire outer surface area of the coated proppant. The degradable shell 302 can coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface 308 of the resin coating 104. For example, the coating can coat or cover about 100% of the entire outer surface area of the coated proppant such that the resin coating 104 is disposed between the porous proppant particulate 106 and the degradable shell 302.

Encapsulated proppant 300 may include any suitable amount of chemical treatment agent 102. According to several exemplary embodiments, encapsulated proppant 300 includes at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of chemical treatment agent 102, based on the total weight of encapsulated proppant 300. Encapsulated proppant 300 may include any suitable amount of resin coating 104. According to several exemplary embodiments, encapsulated proppant 300 includes from about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, about 3.5 wt%, or about 5 wt% to about 8 wt%, about 15 wt%, about 30 wt%, about 50 wt%, or about 80 wt% of resin material, based on the total weight of encapsulated proppant 300.

The degradable shell 302 can also encapsulate any suitable configuration of proppant particles. For example, FIG4 is a cross-sectional view of an encapsulated proppant 400 having a degradable, impermeable shell 302 encapsulating an uncoated proppant 404 comprising a chemical treatment 102 injected into a porous proppant particle 106. The degradable shell 302 can be applied directly or indirectly to the outer surface 107 of the porous proppant particle 106. The degradable shell 302 can coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface area of the porous proppant particle 106. For example, the degradable shell 302 can coat or cover about 100% of the entire outer surface area of the uncoated proppant 404. Encapsulated proppant 400 may include any suitable amount of chemical treatment 102. According to several exemplary embodiments, encapsulated proppant 400 includes at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of chemical treatment 102, based on the total weight of encapsulated proppant 400.

FIG5 is a cross-sectional view of an encapsulated proppant 500 having a degradable, impermeable shell 302 for encapsulating the coated proppant 100 discussed above. For example, the degradable shell 302 can be applied directly or indirectly to the outer surface of the resin coating 104 of the coated proppant 100. The degradable shell 302 can coat or cover at least about 10%, at least about 30%, at least about 50%, at least about 70%, at least about 90%, at least about 95%, or at least about 99% of the entire outer surface area of the resin coating 104 of the coated proppant 100. For example, the degradable shell 302 can coat or cover about 100% of the entire outer surface area of the resin coating 104. The degradable shell 302 can also cover, surround, and/or encapsulate the coated proppant 200.

According to several exemplary embodiments, the degradable shell 302 is present in any suitable amount in the encapsulated proppant 300, 400, 500. According to several exemplary embodiments, the encapsulated proppant 300, 400, 500 comprises at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of the degradable shell 302, based on the total weight of the encapsulated proppant 300, 400, 500. According to several exemplary embodiments, the encapsulated proppant 300, 400, 500 comprises about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, about 3.5 wt%, or about 5 wt% to about 8 wt%, about 15 wt%, about 30 wt%, about 50 wt%, or about 80 wt% of the degradable shell 302, based on the total weight of the encapsulated proppant 300, 400, 500.

According to several exemplary embodiments, the chemical treatment 102 is present in any suitable amount in the encapsulated proppant 300, 400, 500. According to several exemplary embodiments, the encapsulated proppant 300, 400, 500 includes at least about 0.01 wt%, at least about 0.1 wt%, at least about 0.5 wt%, at least about 1 wt%, at least about 2 wt%, at least about 4 wt%, at least about 6 wt%, or at least about 10 wt% of the chemical treatment 102, based on the total weight of the encapsulated proppant 300, 400, 500. According to several exemplary embodiments, the encapsulated proppant 300, 400, 500 includes from about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, or about 3.5 wt% to about 5 wt%, about 8 wt%, about 12 wt%, or about 20 wt% of the chemical treatment 102, based on the total weight of the coated proppant 300, 400, 500.

The degradable shell 302 of the encapsulated proppant 300, 400, 500 can have any suitable thickness. The degradable shell 302 can have a thickness of at least about 0.1 nm, at least about 0.5 nm, at least about 1 nm, at least about 4 nm, at least about 8 nm, at least about 15 nm, at least about 30 nm, at least about 60 nm, at least about 100 nm, at least about 200 nm, or at least about 500 nm. For example, the degradable shell 302 can have a thickness of from about 1 nm, about 10 nm, about 20 nm, about 50 nm, about 100 nm, about 150 nm, or about 200 nm to about 300 nm, about 500 nm, about 750 nm, or about 1,000 nm or more.

In one or more exemplary embodiments, the proppant particles 106 may be or include natural sand. In one or more exemplary embodiments, the proppant particles 106 may be or include ceramic proppants. The ceramic proppants may be or include porous ceramic proppants and non-porous ceramic proppants.

The proppant particles 106 can be or include any suitable amount of silica and/or alumina. According to several exemplary embodiments, the proppant particles 106 include less than 80 wt%, less than 60 wt%, less than 40 wt%, less than 30 wt%, less than 20 wt%, less than 10 wt%, or less than 5 wt% silica, based on the total weight of the proppant particles 106, 206. According to several exemplary embodiments, the proppant particles 106 include from about 0.1 wt% to about 70 wt% silica, from about 1 wt% to about 60 wt% silica, from about 2.5 wt% to about 50 wt% silica, from about 5 wt% to about 40 wt% silica, or from about 10 wt% to about 30 wt% silica. According to several exemplary embodiments, the proppant particles 106 comprise at least about 30 wt%, at least about 50 wt%, at least about 60 wt%, at least about 70 wt%, at least about 80 wt%, at least about 90 wt%, or at least about 95 wt% alumina, based on the total weight of the proppant particles 106. According to several exemplary embodiments, the proppant particles comprise from about 30 wt% to about 99.9 wt% alumina, from about 40 wt% to about 99 wt% alumina, from about 50 wt% to about 97 wt% alumina, from about 60 wt% to about 95 wt% alumina, or from about 70 wt% to about 90 wt% alumina.

According to several exemplary embodiments, the proppant compositions disclosed herein include proppant particles 106 that are substantially spherical and have a size range between about 6 and 270 mesh (U.S. Mesh). For example, the size of the particles 106 can be expressed as a grain fineness number (GFN) in the range of about 15 to about 300, or about 30 to about 110, or about 40 to about 70. According to such examples, the GFN can be determined in the laboratory by sieving a sample of sintered particles through a size, such as a median size between 20, 30, 40, 50, 70, 100, 140, 200, and 270 mesh. The correlation between sieve size and GFN can be determined according to Procedure 106-87-S of the American Foundry Society Mold and Core Test Handbook, which is known to those skilled in the art.

The proppant compositions disclosed herein include proppant particles having any suitable size. For example, the proppant particles 106 can have a mesh size of at least about 6 mesh, at least about 10 mesh, at least about 16 mesh, at least about 20 mesh, at least about 25 mesh, at least about 30 mesh, at least about 35 mesh, or at least about 40 mesh. According to several exemplary embodiments, the proppant particles 106 have a mesh size ranging from about 6 mesh, about 10 mesh, about 16 mesh, or about 20 mesh to about 25 mesh, about 30 mesh, about 35 mesh, about 40 mesh, about 45 mesh, about 50 mesh, about 70 mesh, or about 100 mesh. According to several exemplary embodiments, the proppant particles 106 have a mesh size of about 4 mesh to about 120 mesh, about 10 mesh to about 60 mesh, about 16 mesh to about 20 mesh, about 20 mesh to about 40 mesh, or about 25 mesh to about 35 mesh.

According to several exemplary embodiments, the proppant compositions disclosed herein include porous and/or non-porous proppant particles having any suitable permeability and conductivity expressed in Darcy units, or Darcy (D), according to ISO 13503-5, "Procedures for Measuring the Long-term Conductivity of Proppants." A pack having proppant particles 106 in a 20/40 mesh size range can have a long-term permeability at 7,500 psi of at least about 1D, at least about 2D, at least about 5D, at least about 10D, at least about 20D, at least about 40D, at least about 80D, at least about 120D, at least about 150D, at least about 200D, or at least about 250D. A pack having proppant particles 106 in a 20/40 mesh size range can have a long-term permeability at 12,000 psi of at least about 1 D, at least about 2D, at least about 3D, at least about 4D, at least about 5D, at least about 10D, at least about 25D, at least about 50D, at least about 100D, at least about 150D, or at least about 200D. A pack having proppant particles 106 in a 20/40 mesh size range can have a long-term permeability at 15,000 psi of at least about 1 D, at least about 2D, at least about 3D, at least about 4D, at least about 5D, at least about 10D, at least about 25D, at least about 50D, at least about 75D, at least about 100D, or at least about 150D. A pack having proppant particles 106 in the 20/40 mesh size range can have a long-term permeability at 20,000 psi of at least about 1D, at least about 2D, at least about 3D, at least about 4D, at least about 5D, at least about 10D, at least about 25D, at least about 50D, at least about 75D, or at least about 100D.

The pack of proppant particles 106 can have a long-term permeability at 7,500 psi of at least about 100 millidarcy-feet (mD-ft), at least about 200 mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, at least about 1,000 mD-ft, at least about 1,500 mD-ft, at least about 2,000 mD-ft, or at least about 2,500 mD-ft. For example, the pack of proppant particles 106 can have a long-term conductivity at 12,000 psi of at least about 50 mD-ft, at least about 100 mD-ft, at least about 200 mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, at least about 1,000 mD-ft, or at least about 1,500 mD-ft.

The proppant compositions disclosed herein include proppant particles 106 having any suitable shape. The proppant particles 106 can be substantially circular, cylindrical, square, rectangular, elliptical, oval, egg-shaped, or pellet-shaped. As shown, the proppant particles 106 can be substantially spherical. According to several exemplary embodiments, the proppant particles 106 of the proppant compositions disclosed herein have an apparent specific gravity of less than 3.1 g/cm ³ , less than 3.0 g/cm ³ , less than 2.8 g/cm ³ , or less than 2.5 g/cm ^3. According to several exemplary embodiments, the proppant particles 106 have an apparent specific gravity of from about 3.1 to 3.4 g/cm ³ , from about 1.5 to about 2.2 g/cm ³ , from about 1.9 to about 2.5 g/cm ³ , or from about 2.6 to about 3.2 g/cm ³ . According to several exemplary embodiments, proppant particulates 106 have an apparent specific gravity greater than 3.4 g/cm ³ , greater than 3.6 g/cm ³ , greater than 4.0 g/cm ³ , or greater than 4.5 g/cm ³ .

The proppant particles 106 can have any suitable specific gravity. The proppant particles 106 can have a specific gravity of at least about 2.5, at least about 2.7, at least about 3, at least about 3.3, or at least about 3.5. For example, the proppant particles 106 can have a specific gravity of about 2.5 to about 4.0, about 2.7 to about 3.8, about 3.5 to about 4.2, about 3.8 to about 4.4, or about 3.0 to about 3.5. In one or more exemplary embodiments, the proppant particles 106 can have a specific gravity of less than 4 g/cc, less than 3.5 g/cc, less than 3 g/cc, less than 2.75 g/cc, less than 2.5 g/cc, less than 2.25 g/cc, less than 2 g/cc, less than 1.75 g/cc, or less than 1.5 g/cc. For example, the proppant particles 106 may have a specific gravity of about 1.3 g/cc to about 3.5 g/cc, about 1.5 g/cc to about 3.2 g/cc, about 1.7 g/cc to about 2.7 g/cc, about 1.8 g/cc to about 2.4 g/cc, or about 2.0 g/cc to about 2.3 g/cc.

The proppant particles 106 can have any suitable bulk density. In one or more exemplary embodiments, the proppant particles 106 have a bulk density of less than 3 g/cc, less than 2.5 g/cc, less than 2.2 g/cc, less than 2 g/cc, less than 1.8 g/cc, less than 1.6 g/cc, or less than 1.5 g/cc. The proppant particles 106 can have a bulk density of about 1 g/cc, about 1.15 g/cc, about 1.25 g/cc, about 1.35 g/cc, or about 1.45 g/cc to about 1.5 g/cc, about 1.6 g/cc, about 1.75 g/cc, about 1.9 g/cc, or about 2.1 g/cc or more. For example, the proppant particles 106 can have a bulk density of about 1.3 g/cc to about 1.8 g/cc, about 1.35 g/cc to about 1.65 g/cc, or about 1.5 g/cc to about 1.9 g/cc.

The proppant particles 106 can have any suitable surface roughness. The proppant particles 106 can have a surface roughness of less than 5 μm, less than 4 μm, less than 3 μm, less than 2.5 μm, less than 2 μm, less than 1.5 μm, or less than 1 μm. For example, the proppant particles 106 can have a surface roughness of about 0.1 μm to about 4.5 μm, about 0.4 μm to about 3.5 μm, or about 0.8 μm to about 2.8 μm.

The proppant particles 106 can have any suitable pore size distribution. For example, the proppant particles 106 can have a pore size standard deviation of less than 6 μm, less than 4 μm, less than 3 μm, less than 2.5 μm, less than 2 μm, less than 1.5 μm, or less than 1 μm. The proppant particles 106 can have any suitable average maximum pore size. For example, the proppant particles 106 can have an average maximum pore size of less than about 25 μm, less than about 20 μm, less than about 18 μm, less than about 16 μm, less than about 14 μm, or less than about 12 μm. The proppant particles 106 can have any suitable pore concentration. For example, the proppant particles 106 can have less than 5,000, less than 4,500, less than 4,000, less than 3,500, less than 3,000, less than 2,500, or less than 2,200 visible pores per square millimeter of the proppant particles 106 at 500x magnification.

The proppant particles 106 can have any suitable porosity. According to several exemplary embodiments, the proppant particles 106 can be or include porous ceramic proppants having any suitable porosity. The porous ceramic proppant can have an internally interconnected porosity of from about 1%, about 2%, about 4%, about 6%, about 8%, about 10%, about 12%, or about 14% to about 18%, about 20%, about 22%, about 24%, about 26%, about 28%, about 30%, about 34%, about 38%, about 45%, about 55%, about 65%, or about 75%, or more. In several exemplary embodiments, the internally interconnected porosity of the porous ceramic proppant is from about 5% to about 75%, from about 5% to about 15%, from about 10% to about 30%, from about 15% to about 35%, from about 25% to about 45%, from about 30% to about 55%, or from about 35% to about 70%. According to several exemplary embodiments, the porous ceramic proppant can have any suitable average pore size. For example, the porous ceramic proppant can have an average pore size of from about 2 nm, about 10 nm, about 15 nm, about 55 nm, about 110 nm, about 520 nm, or about 1100 to about 2200 nm, about 5500 nm, about 11000 nm, about 17000 nm, or about 25000 nm or more in its largest dimension. For example, the porous ceramic proppant can have an average pore size of from about 3 nm to about 30000 nm, from about 30 nm to about 18000 nm, from about 200 nm to about 9000 nm, from about 350 nm to about 4500 nm, or from about 850 nm to about 1800 nm in its largest dimension.

As discussed herein, the proppant particles 106 can contain the chemical treatment 102 in any suitable manner. In one or more exemplary embodiments, the proppant particles 106 are infused, coated, and/or encapsulated with one or more chemical treatments 102. Suitable chemical treatments 102 can be or include any one or more of the following: tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin or wax inhibitors, including ethylene vinyl acetate copolymers, asphaltene inhibitors, organic deposition inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants, combinations thereof, or any other oilfield chemicals that may aid in the hydraulic fracturing process. In one or more exemplary embodiments, the scale inhibitors can inhibit scales of calcium salts, barium salts, magnesium salts, and the like, including barium sulfate, calcium sulfate, and calcium carbonate scales. Composite materials can also have applicability in the treatment of other inorganic scales (such as zinc sulfide, iron sulfide, etc.). In one or more exemplary embodiments, the scale inhibitor is an anionic scale inhibitor. The scale inhibitor can include strong acids such as phosphonic acid, phosphoric acid, phosphorous acid, phosphate esters, phosphonic acid esters/phosphonic acid, amino polycarboxylic acids, chelating agents and polymer inhibitors and their salts. The scale inhibitor can also include organic phosphonates/salts, organic phosphates and phosphates and their corresponding acids and salts. The scale inhibitor can also include polymer scale inhibitors, such as polyacrylamide, acrylamide-propane sulfonic acid methyl ester/acrylic acid copolymer (AMPS/AA), phosphorylated maleic acid copolymers (PHOS/MA) or the sodium salt of polymaleic acid/acrylic acid/acrylamide-propane sulfonic acid methyl ester terpolymer (PMA/AMPS). In one or more exemplary embodiments, the scale inhibitor may include DTPA (also known as diethylenetriaminepentaacetic acid; diethylenetriamine-N,N,N′,N′,N″-pentacetic acid; pentetic acid; N,N-bis(2-(bis-(carboxymethyl)amino)ethyl)-glycine; diethylenetriaminepentaacetic acid, [[(carboxymethyl)imino]bis(ethylenenitrilo)]-tetraacetic acid); EDTA (also known as edetic acid, ethylenedinitrilotetraacetic acid; EDTA free base; EDTA free acid; ethylenediamine-N,N,N′,N′-tetraacetic acid; hampene; vildecene acid; N,N′-1,2-ethanediylbis-(N-(carboxymethyl)glycine); ethylenediaminetetraacetic acid); NTA (also known as N,N-bis(carboxymethyl)glycine; nitrilotriacetic acid; trilone A; α,α′,α″-trimethylaminotricarboxylic acid; tris(carboxymethyl)amine; aminotriacetic acid; Hampshire NTA acid; nitrilo-2,2',2"-triacetic acid; titriplex i; nitrilotriacetic acid); APCA (aminopolycarboxylic acid); phosphonic acid; EDTMP (ethylenediaminetetramethylenephosphonic acid); DTPMP (diethylenetriaminepentamethylenephosphonic acid); NTMP (nitrilotrimethylenephosphonic acid); polycarboxylic acids, gluconate esters/salts, citrate esters/salts, polyacrylates/salts and polyaspartates/salts, or any combination thereof. The antiscalant may also include any of the ACCENT ^™ antiscalants available from Dow Chemical Company. The antiscalant may also include a potassium salt of a maleic acid copolymer. In one or more exemplary embodiments, the chemical treatment agent 102 is DTPMP.

In one or more exemplary embodiments, the chemical treatment 102 can be or include any one or more salt inhibitors. In one or more exemplary embodiments, the salt inhibitor can include any suitable salt inhibitor, including but not limited to, and WFT 9725 (each available from Weatherford International Ltd.), Desalt Liquid salt inhibitor available from JACAM Chemicals, LLC, and potassium ferricyanide, and any combination thereof.

In one or more exemplary embodiments, chemical treatment agent 102 may be or include any one or more demulsifiers. Demulsifiers may include, but are not limited to, polycondensates of alkylene oxides and glycols, such as ethylene oxide and propylene oxide polycondensates of trimethylolpropane and dipropylene glycol; and alkyl-substituted phenol-formaldehyde resins, bisphenyl diepoxides, and their esters and diesters. Demulsifiers may also include alkoxylated phenol-formaldehyde resins, alkoxylated amines and polyamines, diepoxidized alkoxylated polyethers, polytriethanolamine methyl chloride quaternary ammonium salts, melamine acid colloids, and aminomethylated polyacrylamides.

In one or more exemplary embodiments, the chemical treatment agent 102 may be or include any one or more corrosion inhibitors. Suitable corrosion inhibitors may include, but are not limited to, fatty imidazolines, alkyl pyridines, quaternary ammonium salts of alkyl pyridines, quaternary ammonium salts of fatty amines, and phosphates of fatty imidazolines. In one or more exemplary embodiments, the chemical treatment agent 102 may be or include any one or more suitable foaming agents. Suitable foaming agents may include, but are not limited to, alkoxylated sulfates or ethoxylated alcohol sulfates, or mixtures thereof. In one or more exemplary embodiments, the chemical treatment agent 102 may be or include any one or more suitable oxygen scavengers. Suitable oxygen scavengers may include triazines, maleimides, formaldehyde, amines, carboxamides, alkylcarboxyazo compounds, isopropylbenzene-peroxide compounds, morpholino derivatives and amino derivatives, morpholine and piperazine derivatives, amine oxides, alkanolamines, aliphatic polyamines, and aromatic polyamines.

In one or more exemplary embodiments, the chemical treatment 102 may be or include any one or more paraffin inhibitors. Suitable paraffin inhibitors may include, but are not limited to, ethylene/vinyl acetate copolymers, acrylic acid esters (e.g., methacrylates and polyacrylates of fatty alcohols), and olefin/maleic acid esters. In one or more exemplary embodiments, the chemical treatment 102 may be or include any one or more asphaltene inhibitors. Suitable asphaltene inhibitors may include, but are not limited to, asphaltene treatment chemicals, including, but not limited to, fatty ester homopolymers and copolymers (e.g., fatty esters of polymers and copolymers of acrylic acid and methacrylic acid), and sorbitan monooleate.

In one or more exemplary embodiments, the chemical treatment 102 may be or include a thermal neutron absorbing material. In one or more exemplary embodiments, the thermal neutron absorbing material is boron, cadmium, gadolinium, iridium, samarium, or mixtures thereof. The thermal neutron absorbing material may leach, elute, diffuse, seep, drain, desorb, dissolve, leak, seep, and leak from any of the proppants 100, 200, 300, 400, 500 and into fractures, formations, and/or wellbores. Downhole tools emitting thermal neutrons can detect the presence of the thermal neutron absorbing material to detect proppant placement, producing and non-producing zones, and fracture size, shape, and location.

In one or more exemplary embodiments, the chemical treatment 102 can be or include any suitable radioactive material. In one or more exemplary embodiments, the radioactive material can include radioactive or gamma-ray emitting isotopes of gold, iodine, iridium, scandium, antimony, silver, hafnium, zirconium, rubidium, chromium, iron, strontium, cobalt, zinc, or mixtures thereof. The radioactive material can leach, elute, diffuse, seep, drain, desorb, dissolve, vent, seep, and leak from any of the proppants 100, 200, 300, 400, 500 and into fractures, formations, and/or wellbores. Downhole tools can detect the presence of the radioactive material to detect proppant placement, producing and non-producing zones, and fracture size, shape, and location.

In one or more exemplary embodiments, the chemical treatment agent 102 can be or include any one or more suitable surfactants. One or more suitable surfactants can be selected based on the necessary adjustments in the wetting characteristics of the proppant for the desired production enhancement. For example, suitable surfactants can be found in U.S. Patent Application Publication No. 2005/0244641, which is incorporated herein by reference in its entirety. The surfactant can also be selected from any number of surfactants known to those of ordinary skill in the art, including, for example, anionic, cationic, nonionic, and amphoteric surfactants, or combinations thereof. According to several exemplary embodiments, suitable surfactants include, but are not limited to, saturated or unsaturated long-chain fatty acids or acid salts, long-chain alcohols, polyols, dimethylpolysiloxanes, and polyethylhydrogensiloxanes. According to several exemplary embodiments, suitable surfactants include but are not limited to linear and branched carboxylic acids and acid salts with about 4 to about 30 carbon atoms, linear and branched alkyl sulfonic acids and acid salts with about 4 to about 30 carbon atoms, wherein the linear alkyl chain includes linear alkylbenzene sulfonates with about 4 to about 30 carbon atoms, sulfosuccinates, phosphates, phosphonates, phospholipids, ethoxylated compounds, carboxylates, sulfonates and sulfates, polyethylene glycol ethers, amines, salts of acrylic acid, pyrophosphates, and mixtures thereof. Cationic surfactants can include those containing quaternary ammonium moieties (e.g., linear quaternary amines, benzyl quaternary ammoniums or halogenated quaternary ammoniums), quaternary sulfonium moieties or quaternary phosphonium moieties or mixtures thereof. Suitable surfactants containing quaternary groups can include quaternary ammonium halides or quaternary amines, such as quaternary ammonium chlorides or quaternary ammonium bromides. Amphoteric surfactants can include glycinates, amphoteric acetates, propionates, betaines and mixtures thereof. Anionic surfactants can include sulfonates (e.g., sodium xylene sulfonate and sodium naphthalene sulfonate), phosphonates, ethoxy sulfates and mixtures thereof. According to several exemplary embodiments, suitable surfactants include, but are not limited to, sodium stearate, octadecanoic acid, hexadecyl sulfonate, dodecyl sulfate, sodium oleate, ethoxylated nonylphenol, sodium dodecyl sulfate, sodium dodecylbenzenesulfonate, lauramine hydrochloride, trimethyldodecyl ammonium chloride, hexadecyltrimethyl ammonium chloride, polyoxyethylene alcohol, alkylphenol ethoxylates, polysorbate 80, propylene oxide-modified polydimethylsiloxane, dodecyl betaine, lauramidopropyl betaine, cocamido-2-hydroxypropyl sulfobetaine, alkylaryl sulfonates, fluorosurfactants and perfluoropolymers and terpolymers, castor bean adducts, and combinations thereof. According to several exemplary embodiments, the surfactant is sodium dodecylbenzenesulfonate or sodium dodecyl sulfate. According to several exemplary embodiments, the surfactant is used at a concentration below the critical micelle concentration (CMC) in aqueous and hydrocarbon carrier fluids. Additionally, surfactants that are production enhancing additives are commercially available from CESI Chemical, Inc. as SG-400N, SG-401N, and LST-36.

In one or more exemplary embodiments, the chemical treatment 102 can be or include any suitable nanoparticle dispersion. The nanoparticle dispersion can be coated onto and/or injected into the proppant particles 106, allowing the proppant particles 106 to serve as carriers for the nanoparticle dispersion during hydraulic fracturing operations. Including the nanoparticle dispersion within and/or beneath the coating 104, 204 of the coated proppant or within the internal pores of the porous ceramic proppant, rather than simply injecting or pumping the nanoparticle dispersion into the well formation as a fluid, not only improves the wetting properties of the formation surface, but also improves the wetting properties of the proppant itself. The nanoparticle dispersion interacts with the proppant surface to alter its wetting properties. Furthermore, as the fluid flows through the proppant pack in the formation, some of the nanoparticle dispersion can be released into the fractures and adhere to the formation surface, improving the wettability or fluid affinity of the formation surface. Thus, the use of nanoparticle dispersions coated on and/or injected into proppants provides benefits similar to those obtained by pumping the nanoparticle dispersion into the formation in fluid form, but with the added benefit of improved wettability of the proppant due to increased interaction of the nanoparticle dispersion with the proppant.

Nanoparticle dispersions can include many different nanoparticle materials known to those of ordinary skill in the art, including polymers, silica, metals, metal oxides, and other inorganic materials, suspended in an aqueous or non-aqueous solvent fluid. According to several exemplary embodiments, suitable materials include, but are not limited to, nanoparticles such as silica, zirconium dioxide, antimony dioxide, zinc oxide, titanium dioxide, aluminum dioxide, particles obtained from natural minerals, synthetic particles, and combinations thereof. According to several exemplary embodiments, one or more of silica, zirconium dioxide, and antimony dioxide is added having a diameter of about 65 nanometers or less (in several exemplary embodiments, 1-10 nm) and a polydispersity of less than about 20%.

The selection of a specific nanoparticle dispersion or surfactant to be coated onto and/or injected into the proppant particles 106 depends on the necessary adjustments in the wetting characteristics of the proppant for the desired production enhancement. Suitable nanoparticle dispersions or surfactants can be selected from any number of commercially available products. For example, nanoparticle dispersion products are available as MA-844W, MA-845, FBAM, FBA Plus, and FBA Plus Enviro from CESIChemical, Inc., a subsidiary of Flotek Industries, Inc.

In one or more exemplary embodiments, the chemical treatment agent 102 can be or include any one or more suitable breakers. Breakers can be or include oxidants, such as bleach, hypochlorites, percarbonates, perborates, permanganates, peroxides, and halogens. In one or more exemplary embodiments, the chemical treatment agent 102 can be or include any one or more suitable biocides. Suitable biocides can be or include bronopol, dazomethon, glutaraldehyde, quaternary ammonium salts, and bleach.

In one or more exemplary embodiments, the chemical treatment agent 102 can be or include any suitable tracer, such as one or more metal or non-metal elements, one or more nanoparticles and/or one or more biomarkers. According to several exemplary embodiments, the biomarker is DNA. DNA or deoxyribonucleic acid is sometimes a double-stranded helical molecule that encodes the genetic information of almost all living systems. Due to the specific sequence of nitrogenous bases - adenine ("A"), thymine ("T"), cytosine ("C") and guanine ("G") contained in the molecule, each DNA molecule can be unique. The double helix structure is formed and maintained by pairing the nitrogenous bases on one phosphate/sugar backbone carrier chain with the nitrogenous bases on another phosphate/sugar backbone carrier chain through hydrogen bonds. Specifically, adenine bases pair with thymine bases ("AT" base pairs) and cytosine bases pair with guanine bases ("GC" base pairs). The probability term can be calculated for the frequency of a given base sequence, and as long as a sufficiently large DNA molecule is used, the "uniqueness" of a specific DNA molecule can be known with sufficient certainty. DNA molecules can be naturally occurring DNA or manufactured (synthetic) DNA and can be double-stranded or single-stranded. Synthetic DNA is commercially available and can be ordered through several specialized DNA manufacturers, such as GenScript, Synthetic Genomics, DNA 2.0Genewiz.Inc., Life Technologies, and Cambrian Genomics. In addition, DNA can be "encapsulated" to enhance its survivability under downhole storage conditions and otherwise alter its interaction with formation fluids. In addition, a specific DNA sequence can be selected based on its compatibility with the thermal environment of a particular well.

DNA alone can be used as a biomarker. DNA is generally water-soluble and can be injected into, coated onto, and/or mixed with the coating 104, 204 on the proppant particles 106 without any modification to serve as a water-soluble biomarker. According to several exemplary embodiments, DNA can be formulated in such a way that it is hydrocarbon-soluble and will also separate into hydrocarbon fluids. For example, the water solubility of DNA is due to the negative charge associated with the phosphodiester groups of the DNA. The negative charge of the phosphodiester structure can be removed by methylation. Methylation of this region of the DNA molecule will ensure that this portion of the molecule becomes hydrophobic, i.e., hydrocarbon-soluble, thereby ensuring that the DNA molecule is soluble in the hydrocarbon phase. Other methods for formulating hydrocarbon-soluble DNA can be found in U.S. Patent No. 5,665,538, the entire disclosure of which is incorporated herein by reference.

Although DNA itself can be used as a biomarker, the storage conditions in which the DNA is placed may not be optimal for the long-term viability of the DNA. These conditions include storage temperatures exceeding 200°F, sometimes reaching 400°F, and high-salinity stratum water. However, many DNA encapsulation technologies are well known to those of ordinary skill in the art, and by encapsulating DNA, its viability under adverse conditions is greatly enhanced. The distribution of the DNA (whether to enter the hydrocarbon phase or the aqueous phase) can be adjusted by adjusting the encapsulating material. In addition, the wettability or fluid affinity of the encapsulating material can be adjusted to be conducive to water or hydrocarbons.

In addition, based on the improved thermal stability shown by DNA molecules with higher concentrations of certain base pairs, molecules containing specific nucleotide sequences can be selectively used to enhance compatibility with harsh wellbore and formation temperatures and pressures. Specifically, the DNA molecules with the greatest heat resistance are DNA molecules comprising higher levels of GC base pairs and lower levels of AT base pairs. For example, the sequence GCAT (with the corresponding base pair sequence CGTA) shows thermal stability at temperatures of about 186 to 221°F. The sequence GCGC (with the corresponding base pair sequence CGCG) is heat-resistant at temperatures of up to about 269 to 292°F. On the contrary, comprising higher levels of AT base pairs reduces thermal stability. For example, some thymines in the combination reduce stability, making the sequence ATCG (with the corresponding base pair sequence TAGC) only survive at temperatures of up to about 222-250°F, while the sequence TATA (with the corresponding base pair sequence ATAT) is heat-stable at temperatures of up to only about 129-175°F. Furthermore, if a DNA molecule containing the sequence ATCG (with the corresponding base pair sequence TAGC) is manipulated to include a modification known as the G-clamp, thermal stability increases by an additional 32°F, or from a temperature as high as approximately 254 to 282°F. As shown below, the G-clamp modification involves the addition of a three-ring analog of cytosine, which imparts additional hydrogen bonding to the duplex base pairs (G-C).

By increasing the number of hydrogen bonds in the duplex base pairs from 3 to 4, thermal stability increased by an additional 32°F.

DNA can be single-stranded or double-stranded. The natural orientation of double-stranded DNA is Watson-Crick pairing. However, synthetic DNA is not constrained in the same way as natural DNA. Still, an indicator of thermal stability is the thermodynamic reorientation of the chain, and it mainly consists of the chain separating into two single strands. This is called melting and occurs over a narrow temperature range. It has been observed that the DNA of some organisms resists this thermal collapse, an example being certain thermophilic organisms. Analysis of their genomes has revealed a direct correlation between the levels of G-C DNA in the sequence. Thermal stability is directly or indirectly related to the number of hydrogen bonds between the bases in the duplex pairs. However, stacking (pairing in the duplex) is also a factor. It has been determined that the important feature of thermal stability in natural DNA depends primarily on the molar ratio of G-C pairing, as this produces the highest hydrogen bond density. Thermal stability ultimately depends on the so-called melting point, at which the chains of double-stranded DNA separate. However, this does not make sense for single-stranded synthetic DNA, which has already separated. The separation of double-stranded DNA chains that occurs at the melting point is reversible to a certain extent. Once the temperature is sufficiently lowered, the chains can reconnect. Thermal stability depends on the heat resistance of the base pairs or duplex units and the stacking forces of the strands connecting the double-stranded DNA. As mentioned above, thermal stability can also be improved by changing the molecular arrangement within a specific base pair. For example, in addition to the G-G-clamp modification described above, as shown below, the thermal stability of the AT base pair can be improved by modifying the adenine-thymine base pair to include a 2-aminoadenine-T complex, which increases the number of hydrogen bonds in the complex from 2 to 3 and increases its thermal stability by approximately 5°F.

The thermal stability of specific base pairs can be used to generate thermodynamic assessment possibilities. As mentioned above, reasonable chemical modifications can extend this thermal range and retain the basic characteristics of DNA for measurement purposes. The chemical properties of DNA mean that it is easily hydrolyzed, and the hydrolysis rate increases with increasing temperature. Hydrolysis is another way for DNA to decompose besides its melting behavior as described above. In other words, many organisms are known to survive at extreme temperatures, which means that their genetic material must have some inherent thermal stability. This response is directly related to the mole fraction of G-C base pairs, regardless of whether such base pairs exist as single or double strands. However, natural DNA is chromosomal and therefore must be double-stranded.

It has also been shown that the repetition of G-C duplexes appears to confer more stability, as it has a direct impact on the heat resistance of DNA. This shows how various organisms cope with high temperatures by introducing larger G-C mole fractions in their genomes. It appears that the mole fraction of G-C is the key, rather than any weak link, which can be introduced into the sequence. Chain terminators appear to have a very small overall impact on the thermal stability of DNA. Basically, this means that the mole fraction of certain base pairs in a DNA sequence can be varied depending on the desired temperature range. Understanding the details of the destructive reactions of a DNA sequence will depend on the environment that a particular DNA sequence will be subjected to, and exposure to hydrolysis reactions is an area of concern. However, the modifications of the above base pairs that can be introduced while still retaining the inherent characteristics that make DNA an ideal tracer provide a clear way to tailor tracers for use in oil fields.

The selective use of specific DNA molecules as biomarkers based on their thermostability properties allows the use of DNA as a biomarker over a much wider range of conditions than is currently possible. Furthermore, the survival of DNA molecules at higher temperatures allows accurate detection by avoiding degradation of the DNA, even when the DNA levels present in the rock formation are very low. Furthermore, the number of different unique DNA molecules greatly increases the number of unique tracers that can be applied in the oil field, thereby greatly increasing both the range and diversity of oil field operations to which biomarkers can be applied, and greatly improving the knowledge and understanding of increasingly complex wells and their behavioral properties. This knowledge will lead to better completion and stimulation practices, resulting in cost savings and improved well performance.

In several exemplary embodiments, DNA molecules exhibiting specific thermal stability properties can be selectively injected into and/or coated onto proppant particles 106 to be used in well operations according to the methods and embodiments described herein, based on the specific nitrogenous base composition of the DNA that is compatible with the thermal environment of a particular well. For example, for wells that exhibit temperatures as high as approximately 269 to 292° F., a DNA molecule containing the GCGC sequence can be synthesized and injected into and/or coated onto proppant particles 106 to be injected into the well formation. This DNA molecule will better tolerate the thermal conditions in the well, allowing it to be more effectively used as a biomarker that conveys information about the well formation and production.

According to several exemplary embodiments, after the proppant is placed in the hydraulically generated fracture, the chemical treatment 102 (such as a biomarker) is continuously separated from the proppant particles 106 for a period of up to about one year, up to about five years, or up to about ten years. Systems, techniques, and compositions for providing sustained release of DNA are well known to those of ordinary skill in the art. For example, European Patent No. 1,510,224 discloses various methods for enabling sustained release of DNA over a period of time, the complete disclosure of which is incorporated herein by reference. According to several exemplary embodiments, the DNA is encapsulated with a polymer, or the material injected with the DNA is coated with a permeable, non-degradable coating. In several exemplary embodiments, the encapsulating polymer includes one or more of the following: a high melting point acrylate-, methacrylate-, or styrene-based polymer, a block copolymer of polylactic acid-polyglycolic acid, polyglycolic acid, polylactide, polylactic acid, gelatin, a water-soluble polymer, a cross-linkable water-soluble polymer, a lipid, a gel, silica, or other suitable encapsulating material. Additionally, the encapsulating polymer may include an encapsulating material comprising a linear polymer containing a degradable comonomer or a cross-linked polymer containing a degradable cross-linking agent.

In one or more exemplary embodiments, the internal interconnected porosity of the porous ceramic proppant can be injected with a chemical treatment agent 102 (e.g., a biomarker) to enable the porous ceramic proppant to be used as a carrier of the biomarker in a hydraulic fracturing operation. According to several exemplary embodiments, the biomarker is DNA. DNA, or deoxyribonucleic acid, is a double-stranded helical molecule that encodes the genetic information of almost all living systems. Each DNA molecule can be unique due to the specific sequence of nitrogenous bases - adenine ("A"), thymine ("T"), cytosine ("C"), and guanine ("G") - that the molecule contains. The double helix structure is formed and maintained by pairing nitrogenous bases on one phosphate/sugar backbone carrier chain with nitrogenous bases on another phosphate/sugar backbone carrier chain through hydrogen bonds. Specifically, adenine bases pair with thymine bases ("AT" base pairs), and cytosine bases pair with guanine bases ("GC" base pairs). The probability term can be calculated for the frequency of a given base sequence, and as long as a sufficiently large DNA molecule is used, the "uniqueness" of a particular DNA molecule can be known with sufficient certainty. The DNA molecule can be naturally occurring DNA or manufactured (synthetic) DNA, and can be double-stranded or single-stranded. Synthetic DNA is commercially available and can be ordered through several specialized DNA manufacturers, such as GenScript, Synthetic Genomics, DNA 2.0 Genewiz, Inc., Life Technologies, and Cambrian Genomics. In addition, the DNA can be "encapsulated" to enhance its survivability under downhole storage conditions and otherwise alter its interaction with the formation fluid. Additionally, a specific DNA sequence can be selected based on its compatibility with the thermal environment of a particular well.

According to several exemplary embodiments, the coating 104, 204 may be or include a resin material and/or an epoxy resin material. The coating 104, 204 may include any suitable resin material and/or epoxy resin material. According to several exemplary embodiments, the resin material includes any suitable resin. For example, the resin material may include a phenolic resin (e.g., a phenol-formaldehyde resin). According to several exemplary embodiments, the molar ratio of formaldehyde to phenol (F:P) of the phenol-formaldehyde resin ranges from a low of about 0.6:1, about 0.9:1, or about 1.2:1 to a high of about 1.9:1, about 2.1:1, about 2.3:1, or about 2.8:1. For example, the molar ratio of formaldehyde to phenol of the phenol-formaldehyde resin may be about 0.7:1 to about 2.7:1, about 0.8:1 to about 2.5:1, about 1:1 to about 2.4:1, about 1.1:1 to about 2.6:1, or about 1.3:1 to about 2:1. The phenol-formaldehyde resin may also have a molar ratio of formaldehyde to phenol of about 0.8:1 to about 0.9:1, about 0.9:1 to about 1:1, about 1:1 to about 1.1:1, about 1.1:1 to about 1.2:1, about 1.2:1 to about 1.3:1, or about 1.3:1 to about 1.4:1.

According to several exemplary embodiments, the phenol-formaldehyde resin has a molar ratio of less than 1:1, less than 0.9:1, less than 0.8:1, less than 0.7:1, less than 0.6:1, or less than 0.5:1. For example, the phenol-formaldehyde resin can be or include a phenolic novolac resin. Novolac resins are well known to those of ordinary skill in the art, for example, see U.S. Pat. No. 2,675,335 to Rankin, U.S. Pat. No. 4,179,429 to Hanauye, U.S. Pat. No. 5,218,038 to Johnson, and U.S. Pat. No. 8,399,597 to Pullichola, the entire disclosures of which are incorporated herein by reference. Suitable examples of commercially available novolac resins include novolac resins available from Plenco ^™ , resins available from Momentive, and novolac resins available from SI Group.

According to several exemplary embodiments, the weight average molecular weight of the phenol-formaldehyde resin ranges from a low of about 200, about 300, or about 400 to a high of about 1000, about 2000, or about 6000. For example, the weight average molecular weight of the phenol-formaldehyde resin may be about 250 to about 450, about 450 to about 550, about 550 to about 950, about 950 to about 1500, about 1500 to about 3500, or about 3500 to about 6000. The weight average molecular weight of the phenol-formaldehyde resin may also be about 175 to about 800, about 700 to about 3330, about 1100 to about 4200, about 230 to about 550, about 425 to about 875, or about 2750 to about 4500.

According to several exemplary embodiments, the number average molecular weight of the phenol-formaldehyde resin ranges from a low of about 200, about 300, or about 400 to a high of about 1000, about 2000, or about 6000. For example, the number average molecular weight of the phenol-formaldehyde resin can be about 250 to about 450, about 450 to about 550, about 550 to about 950, about 950 to about 1500, about 1500 to about 3500, or about 3500 to about 6000. The number average molecular weight of the phenol-formaldehyde resin can also be about 175 to about 800, about 700 to about 3000, about 1100 to about 2200, about 230 to about 550, about 425 to about 875, or about 2000 to about 2750.

According to several exemplary embodiments, the z-average molecular weight of the phenol-formaldehyde resin ranges from a low of about 200, about 300, or about 400 to a high of about 1000, about 2000, or about 9000. For example, the z-average molecular weight of the phenol-formaldehyde resin can be about 250 to about 450, about 450 to about 550, about 550 to about 950, about 950 to about 1500, about 1500 to about 3500, about 3500 to about 6500, or about 6500 to about 9000. The z-average molecular weight of the phenol-formaldehyde resin can also be about 175 to about 800, about 700 to about 3330, about 1100 to about 4200, about 230 to about 550, about 425 to about 875, or about 4750 to about 8500.

According to several exemplary embodiments, the phenol-formaldehyde resin has any suitable viscosity. The phenol-formaldehyde resin can be solid or liquid at 25° C. For example, at a temperature of about 25° C., the viscosity of the phenol-formaldehyde resin can be from about 1 centipoise (cP), about 100 cP, about 250 cP, about 500 cP, or about 700 cP to about 1000 cP, about 1250 cP, about 1500 cP, about 2000 cP, or about 2200 cP. In another example, the viscosity of the phenol-formaldehyde resin can be from about 1 cP to about 125 cP, from about 125 cP to about 275 cP, from about 275 cP to about 525 cP, from about 525 cP to about 725 cP, from about 725 cP to about 1100 cP, from about 1100 cP to about 1600 cP, from about 1600 cP to about 1900 cP, or from about 1900 cP to about 2200 cP at a temperature of about 25° C. In another example, the viscosity of the phenol-formaldehyde resin can be from about 1 cP to about 45 cP, from about 45 cP to about 125, from about 125 cP to about 550 cP, from about 550 cP to about 825 cP, from about 825 cP to about 1100 cP, from about 1100 cP to about 1600 cP, or from about 1600 cP to about 2200 cP at a temperature of about 25° C. The viscosity of the phenol-formaldehyde resin can also be from about 500 cP, about 1000 cP, about 2500 cP, about 5000 cP, or about 7500 cP to about 10,000 cP, about 15,000 cP, about 20,000 cP, about 30,000 cP, or about 75,000 cP at a temperature of about 150° C. For example, the viscosity of the phenol-formaldehyde resin can be from about 750 cP to about 60,000 cP, from about 1000 cP to about 35,000 cP, from about 4,000 cP to about 25,000 cP, from about 8,000 cP to about 16,000 cP, or from about 10,000 cP to about 12,000 cP at a temperature of about 150° C. The viscosity of the phenol-formaldehyde resin can be determined using a Brookfield viscometer.

According to several exemplary embodiments, the pH of the phenol-formaldehyde resin can range from a low of about 1, about 2, about 3, about 4, about 5, about 6, about 7 to a high of about 8, about 9, about 10, about 11, about 12, or about 13. For example, the pH of the phenol-formaldehyde resin can be from about 1 to about 2.5, from about 2.5 to about 3.5, from about 3.5 to about 4.5, from about 4.5 to about 5.5, from about 5.5 to about 6.5, from about 6.5 to about 7.5, from about 7.5 to about 8.5, from about 8.5 to about 9.5, from about 9.5 to about 10.5, from about 10.5 to about 11.5, from about 11.5 to about 12.5, or from about 12.5 to about 13.

According to several exemplary embodiments of the present invention, the coating 104, 204 applied to the proppant particles 106 is an epoxy resin. According to such embodiments, the coating 104, 204 can be or include any suitable epoxy resin. For example, the epoxy resin can include bisphenol A, bisphenol F, aliphatic or glycidylamine epoxy resins, and any mixtures or combinations thereof. An example of a commercially available epoxy resin is BE188 epoxy resin available from Chang Chun Plastics Co., Ltd.

According to several exemplary embodiments, the epoxy resin can have any suitable viscosity. The epoxy resin can be solid or liquid at 25°C. For example, at a temperature of about 25°C, the viscosity of the epoxy resin can be from about 1 cP, about 100 cP, about 250 cP, about 500 cP, or about 700 cP to about 1000 cP, about 1250 cP, about 1500 cP, about 2000 cP, or about 2200 cP. In another example, at a temperature of about 25°C, the viscosity of the epoxy resin can be from about 1 cP to about 125 cP, about 125 cP to about 275 cP, about 275 cP to about 525 cP, about 525 cP to about 725 cP, about 725 cP to about 1100 cP, about 1100 cP to about 1600 cP, about 1600 cP to about 1900 cP, or about 1900 cP to about 2200 cP. In another example, the viscosity of the epoxy resin can be from about 1 cP to about 45 cP, from about 45 cP to about 125, from about 125 cP to about 550 cP, from about 550 cP to about 825 cP, from about 825 cP to about 1100 cP, from about 1100 cP to about 1600 cP, or from about 1600 cP to about 2200 cP at a temperature of about 25° C. The viscosity of the epoxy resin can also be from about 500 cP, about 1000 cP, about 2500 cP, about 5000 cP, or about 7000 cP to about 10000 cP, about 12500 cP, about 15000 cP, about 17000 cP, or about 20000 cP at a temperature of about 25° C. In another example, the viscosity of the epoxy resin can be from about 1000 cP to about 12000 cP, from about 2000 cP to about 11000 cP, from about 4000 cP to about 10500 cP, or from about 7500 cP to about 9500 cP at a temperature of about 25° C. The viscosity of the epoxy resin can also be from about 500 cP, about 1000 cP, about 2500 cP, about 5000 cP, or about 7500 cP to about 10000 cP, about 15000 cP, about 20000 cP, about 30000 cP, or about 75000 cP at a temperature of about 150° C. For example, at a temperature of about 150° C., the viscosity of the epoxy resin may be about 750 cP to about 60,000 cP, about 1,000 cP to about 35,000 cP, about 4,000 cP to about 25,000 cP, about 8,000 cP to about 16,000 cP, or about 10,000 cP to about 12,000 cP.

According to several exemplary embodiments, the pH of the epoxy resin can range from a low of about 1, about 2, about 3, about 4, about 5, about 6, about 7 to a high of about 8, about 9, about 10, about 11, about 12, or about 13. For example, the pH of the epoxy resin can be from about 1 to about 2.5, from about 2.5 to about 3.5, from about 3.5 to about 4.5, from about 4.5 to about 5.5, from about 5.5 to about 6.5, from about 6.5 to about 7.5, from about 7.5 to about 8.5, from about 8.5 to about 9.5, from about 9.5 to about 10.5, from about 10.5 to about 11.5, from about 11.5 to about 12.5, or from about 12.5 to about 13.

Methods of coating proppant particulates with resins and/or epoxies are well known to those skilled in the art, see, for example, U.S. Patent Nos. 2,378,817 to Wrightsman, 4,873,145 to Okada, and 4,888,240 to Graham, the entire disclosures of which are incorporated herein by reference.

According to one or more exemplary embodiments, the chemical treatment 102 is mixed with or otherwise added to the resin coating 104, 204 prior to coating the proppant particulate 106 with the resin coating 104, 204. For example, the chemical treatment 102 may be uniformly mixed with the coating 104, 204 prior to coating the proppant particulate 106 with the resin coating 104, 204.

According to one or more exemplary embodiments, proppant particles 106 are porous ceramic particles that are infused with one or more chemical treatments 102. Methods for infusing porous ceramic particles with chemical treatments are well known to those skilled in the art, such as those disclosed in U.S. Pat. No. 5,964,291 and U.S. Pat. No. 7,598,209, the entire disclosures of which are incorporated herein by reference. According to several exemplary embodiments, porous ceramic particles 106 are used as carriers for chemical treatments 102 during hydraulic fracturing operations.

According to several exemplary embodiments, the coating 104, 204 can be or include a degradable coating. Specifically, as the coating degrades, the chemical treatment 102 mixed with the coating 104, 204, the chemical treatment 102 disposed between the coating 104, 204 and the proppant particles 106, and/or the chemical treatment 102 injected into the proppant particles 106 can be released into the fracture. The amount and molecular weight of the degradable coating 104, 204 can be varied to provide longer or shorter degradation times and tailored release of the chemical treatment 102.

According to certain embodiments, the degradable coating 104, 204 may include one or more water-soluble polymers and cross-linkable water-soluble polymers. Suitable water-soluble polymers and cross-linkable water-soluble polymers are disclosed in U.S. Patent No. 6,279,656, the entire disclosure of which is incorporated herein by reference. According to several exemplary embodiments in which the degradable coating 104, 204 includes one or more water-soluble polymers and cross-linkable water-soluble polymers, the solubility parameters of these polymers can be controlled to adjust the time for dissolution or degradation of the coating 104, 204. These parameters can include molecular weight, the hydrophilic/lipophilic balance of the polymer, and the degree of cross-linking of the polymer. According to several exemplary embodiments, the degradable coating 104, 204 includes a degradable polymer, such as polylactic acid, cellulose acetate, methyl cellulose, or a combination thereof, which can degrade within the hydraulic fracture, allowing the injected chemical treatment agent 102 to be released at different time intervals.

According to one or more exemplary embodiments, the degradable coating 104, 204 can degrade in any suitable manner. For example, the degradable coating 204 can degrade from the outside-in, such that the outer surface of the coating 204 degrades first, resulting in a controlled release of the chemical treatment agent 102 blended with the coating 204. These degradable coatings can include self-polishing coatings. The self-polishing coating can include a self-polishing copolymer having chemical bonds that are gradually hydrolyzed by water (e.g., production water, seawater, and/or brine). Due to the nature of the coating 204 degrading from its outermost surface toward its innermost surface, the self-polishing coating can gradually release the chemical treatment agent 102 over time, the degradation being caused by the gradual hydrolysis of the coating.

According to several exemplary embodiments, the proppant particles 106 can be coated with a polymeric material that forms a semipermeable polymeric coating 104, 204 that is substantially non-degradable in the presence of well fluids but allows the chemical treatment to leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, seep, and leak through the polymeric coating, thereby releasing the chemical treatment 102 into the fracture or well zone. The content and molecular weight of the semipermeable, substantially non-degradable polymeric coating 104, 204 can be varied to provide a longer or shorter release time to tailor the release of the chemical treatment 102. According to several exemplary embodiments, the proppant particles 106 are coated with a semipermeable, substantially non-degradable polymer, such as phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, or a combination thereof.

The degradable shell 302 can be or include any material suitable for preventing or eliminating the separation or release of the chemical treatment 106 from the encapsulated proppant 300, 400, 500 until the degradable shell 302 degrades or decomposes. For example, the degradable shell 102 can be impermeable or substantially impermeable to the fracturing fluid, storage fluid, or the like until the degradable shell 302 degrades to the extent that it becomes permeable to the surrounding fluid. Once the degradable shell 302 becomes permeable to the surrounding fluid, the chemical treatment 106 can be separated or eluted from the encapsulated proppant 300, 400, 500.

Degradable shell 302 can be or comprise any water-soluble and/or hydrocarbon-soluble material.In one or more exemplary embodiments, degradable shell 302 can be or comprise the encapsulation material and/or sustained-release composition described in any one of U.S. Pre-authorized Publication Nos.2003/0147821, 2005/0002996 and 2005/0129759, and each publication is incorporated herein by reference in its entirety.In one or more exemplary embodiments, degradable shell 302 can be or comprise fatty alcohol, fatty alcohol includes but is not limited to behenyl alcohol, octanol, cetyl alcohol, cetearyl alcohol, decyl alcohol, lauryl alcohol, isocetyl alcohol, myristyl alcohol, oleyl alcohol, stearyl alcohol, tallow, steareth-2, ceteth-1, cetearyl alcohol polyether-3 and laureth-2. The degradable shell 302 may also be or include a _C8 - _C20 fatty acid, including but not limited to stearic acid, _capric acid, behenic acid, caprylic acid, lauric acid, myristic acid, tallow acid, oleic acid, palmitic acid, _and isostearic acid. The degradable shell 302 may also be or include a sorbitan derivative, including but not limited to PEG-10 sorbitan laurate, PEG-20 sorbitan isostearate, PEG-3 sorbitan oleate, polysorbate 40, sorbitan stearate, and sorbitan palmitate. The degradable shell 302 may also be or include one or more waxes, including but not limited to mink wax, brown mud wax, carnauba wax, and candelilla wax, as well as synthetic waxes such as silicone waxes. In one or more exemplary embodiments, the degradable shell 302 can be selected from polyoxymethylene urea (PMU), methoxymethylhydroxymethyl melamine (MMM), polysaccharides, collagen, gelatin, alginate, guar, guar gum, gum arabic and agar, and any combination or mixture thereof. The degradable shell 302 can also be or include any suitable thermoplastic material. In one or more exemplary embodiments, the degradable shell 302 can be selected from polyvinyl alcohol, poly (acrylates and methacrylates), polylactic acid, polyamide, polyethylene, polypropylene, polystyrene, water-soluble polymers and cross-linkable water-soluble polymers, and any combination thereof.

In one or more exemplary embodiments, the degradable shell 302 can be a thermoplastic material that degrades at any suitable time and temperature. For example, the thermoplastic material can degrade at a temperature of at least about 5°C, at least about 10°C, at least about 20°C, at least about 30°C, at least about 50°C, at least about 70°C, or at least about 90°C. The thermoplastic material can also degrade at a temperature of less than 100°C, less than 95°C, less than 90°C, less than 80°C, or less than 70°C. The thermoplastic material can also degrade at a temperature of from about 1°C, about 4°C, about 8°C, about 12°C, about 16°C, about 25°C, about 35°C, about 45°C, or about 55°C to about 75°C, about 85°C, about 95°C, about 105°C, about 120°C, about 150°C, or about 200°C or more. In one or more exemplary embodiments, the thermoplastic material may degrade at a temperature of from about 1°C, about 4°C, about 8°C, about 12°C, about 16°C, about 25°C, about 35°C, about 45°C, or about 55°C to about 75°C, about 85°C, about 95°C, about 105°C, about 120°C, about 150°C, or about 200°C, or more, for a period of time ranging from about 10 seconds, about 30 seconds, about 1 minute, about 2 minutes, about 5 minutes, about 10 minutes, about 30 minutes, about 1 hour, or about 2 hours to about 5 hours, about 10 hours, about 25 hours, about 50 hours, about 100 hours, about 500 hours, or about 1000 hours, or more.

According to one or more exemplary embodiments, the degradable shell 302 can degrade in any suitable manner. For example, the degradable shell 302 can degrade from the outside-in, such that the outer surface of the degradable shell 302 degrades first, resulting in controlled release of the chemical treatment agent 102. The degradable shell 302 can also include a self-polishing coating as described herein.

The degradable shell 302 can prevent the chemical treatment 106 from leaching, eluting, diffusing, seeping, draining, desorbing, dissolving, escaping, seeping, or leaking from the undegraded encapsulated proppant or encapsulated proppant particulate 300, 400, 500. According to one or more exemplary embodiments, after mixing with the hydraulic fracturing fluid, the chemical treatment 106 can leach, elute, diffuse, seep, drain, desorb, dissolve, egress, seep, or leak from the encapsulated proppant particulate 300, 400, 500 at a rate of less than 10 ppm/(g*day), less than 5 ppm/(g*day), less than 2 ppm/(g*day), less than 1 ppm/(g*day), less than 0.5 ppm/(g*day), less than 0.1 ppm/(g*day), or less than 0.05 ppm/(g*day) for at least about 1 hour, at least about 2 hours, at least about 6 hours, at least about 12 hours, at least about 1 day, or at least about 2 days. According to one or more exemplary embodiments, after contacting the subterranean formation, the chemical treatment 106 may leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, seep, or leak from the encapsulated proppant particulates 300, 400, 500 at a rate of less than 10 ppm/(g*day), less than 5 ppm/(g*day), less than 2 ppm/(g*day), less than 1 ppm/(g*day), less than 0.5 ppm/(g*day), less than 0.1 ppm/(g*day), or less than 0.05 ppm/(g*day) for at least about 1 hour, at least about 2 hours, at least about 6 hours, at least about 12 hours, at least about 1 day, or at least about 2 days. For example, the degradable shell 302 can limit the amount of chemical treatment 106 leached, eluted, diffused, seeped, drained, desorbed, dissolved, vented, leaked, or leaked from the encapsulated proppant particulates 1300, 400, 500 to less than 10 ppm/gram, less than 5 ppm/gram, less than 1 ppm/gram, less than 0.5 ppm/gram, less than 0.1 ppm/gram, or less than 10 ppb/gram for about 10 seconds, about 30 seconds, about 1 minute, about 2 minutes, about 5 minutes, about 10 minutes, about 30 minutes, about 1 hour, or about 2 hours to about 5 hours, about 10 hours, about 25 hours, about 50 hours, about 100 hours, about 500 hours, or about 1000 hours, or more, after mixing with the hydraulic fracturing fluid and/or gravel pack fluid. For example, upon contacting a subterranean formation, the degradable shell 302 can limit the amount of chemical treatment 106 leached, eluted, diffused, seeped, drained, desorbed, dissolved, vented, leaked, or leaked from the encapsulated proppant particulate 300, 400, 500 to less than 10 ppm/gram, less than 5 ppm/gram, less than 1 ppm/gram, less than 0.5 ppm/gram, less than 0.1 ppm/gram, or less than 10 ppb/gram for a period of about 10 seconds, about 30 seconds, about 1 minute, about 2 minutes, about 5 minutes, about 10 minutes, about 30 minutes, about 1 hour, or about 2 hours to about 5 hours, about 10 hours, about 25 hours, about 50 hours, about 100 hours, about 500 hours, or about 1000 hours, or more. In one or more exemplary embodiments, the degradable shell 302 can prevent any leaching, elution, diffusion, seepage, drainage, desorption, dissolution, effluent, seepage, or leakage of the chemical treatment 106 from the encapsulated proppant particles 300, 400, 500 after mixing with the hydraulic fracturing fluid and/or prior to contacting the subterranean formation.

According to several exemplary embodiments, chemical treatment 102 is released from proppant particles 106 for a period of up to about one year, up to about five years, or up to about ten years after proppant particles 106 are placed in a fracture in a subterranean formation.

According to several exemplary embodiments, the proppant particulates 106 may be coated or encapsulated with one or more water-soluble chemical treatments 102 (e.g., scale inhibitors, salt inhibitors, or combinations or mixtures thereof), and then further coated or encapsulated with one or more hydrocarbon-soluble chemical treatments 102 (e.g., paraffin inhibitors or asphaltene inhibitors) to provide coated proppant particulates 100, 200 and/or encapsulated proppant particulates 300, 400, 500. The coating of hydrocarbon-soluble chemical treatment 102 may be mixed with, disposed or layered around, the coating of water-soluble chemical treatment. According to this embodiment, the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 are placed in fractures in a subterranean formation, and once hydrocarbon production begins, the presence of the hydrocarbons causes leaching, elution, diffusion, seepage, expulsion, desorption, dissolution, leakage, seepage, or leakage of the hydrocarbon-soluble chemical treatment 102 from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. After a certain period of time, when water production begins, the water-soluble chemical treatment 102 begins to leach, elute, diffuse, seep, expel, desorb, dissolve, leak, seep, or leak from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500.

According to several exemplary embodiments, proppant particulates 106 are coated or encapsulated with one or more hydrocarbon-soluble chemical treatments 102 (e.g., paraffin inhibitors or asphaltene inhibitors), and then further coated or encapsulated with one or more water-soluble chemical treatments 102 (e.g., scale inhibitors, salt inhibitors, or combinations or mixtures thereof) to provide coated proppant particulates 100, 200 and/or encapsulated proppant particulates 300, 400, 500. The coating of water-soluble chemical treatment 102 may be mixed with, or disposed or layered around, the coating of hydrocarbon-soluble chemical treatment 102. According to this embodiment, the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 are placed in fractures in a subterranean formation, and once water production begins, the presence of water causes the water-soluble chemical treatment 102 to leach, elute, diffuse, seep, drain, desorb, dissolve, bleed, seep, or leak from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. After a certain period of time, when hydrocarbon production begins, the hydrocarbon-soluble chemical treatment 102 begins to leach, elute, diffuse, seep, drain, desorb, dissolve, bleed, seep, or leak from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500.

According to several exemplary embodiments, the proppant particles 106 are porous ceramic proppant particles that can be injected with one or more water-soluble chemical treatments 102 (e.g., scale inhibitors, salt inhibitors, or combinations or mixtures thereof) and then coated or encapsulated with one or more hydrocarbon-soluble chemical treatments 102 (e.g., paraffin inhibitors or asphaltene inhibitors, or combinations or mixtures thereof) to provide coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. According to this embodiment, the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 are placed in fractures in a subterranean formation, and once hydrocarbon production begins, the presence of the hydrocarbons causes leaching, elution, diffusion, seepage, expulsion, desorption, dissolution, leakage, seepage, or leakage of the hydrocarbon-soluble chemical treatment 102 from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. After a certain period of time, when water production begins, the water-soluble chemical treatment 102 begins to leach, elute, diffuse, seep, expel, desorb, dissolve, leak, seep, or leak from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500.

According to several exemplary embodiments, the proppant particles 106 are porous ceramic proppant particles that can be injected with one or more hydrocarbon-soluble chemical treatments 102 (e.g., paraffin inhibitors or asphaltene inhibitors) and then coated or encapsulated with one or more water-soluble chemical treatments 102 (e.g., scale inhibitors, salt inhibitors, or combinations or mixtures thereof) to provide coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. According to such embodiments, the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 are placed in fractures in a subterranean formation, and upon initiation of water production, the presence of the water causes leaching, elution, diffusion, seepage, drainage, desorption, dissolution, effusion, seepage, or leakage of the water-soluble chemical treatment 102 from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500. After a certain period of time, when hydrocarbon production begins, the hydrocarbon-soluble chemical treatment 102 begins to leach, elute, diffuse, seep, drain, desorb, dissolve, bleed, seep, or leak from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500.

The chemical treatment 102 may leach, elute, diffuse, seep, drain, desorb, dissolve, leak, seep, or leak at any suitable rate from the coated proppant particulate 100, 200. The chemical treatment 102 may also leach, elute, diffuse, seep, drain, desorb, dissolve, leak, seep, or leak at any suitable rate from the encapsulated proppant particulate 300, 400, 500 once the degradable shell 302 becomes permeable to the fluid. For example, the chemical treatment 102 can leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, leak, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at a rate of at least about 0.1 ppm/(g*day), at least about 0.3 ppm/(g*day), at least about 0.7 ppm/(g*day), at least about 1.25 ppm/(g*day), at least about 2 ppm/(g*day), at least about 3 ppm/(g*day), at least about 5 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 40 ppm/(g*day), at least about 75 ppm/(g*day), or at least about 100 ppm/(g*day) for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years. For example, the chemical treatment agent can be used at a concentration of from about 0.01 ppm/(g*day), about 0.05 ppm/(g*day), about 0.1 ppm/(g*day), about 0.5 ppm/(g*day), about 1 ppm/(g*day), about 1.5 ppm/(g*day), about 2 ppm/(g*day), or about 3 ppm/(g*day) to about 4 ppm/(g*day), about 4.5 ppm/(g*day), about 5 ppm/(g*day), about 6 ppm/(g*day), about 7 ppm/(g*day), about 8 ppm/(g*day), about 10 ppm/(g*day), about 15 ppm/(g*day), about 30 ppm/(g*day), about 75 ppm/(g*day), or about 150 ppm/(g*day) elutes from the coated proppant particulate 100, 200 and/or the encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years.

According to one or more exemplary embodiments, the scale inhibitor can leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, leak, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at a rate of at least about 0.1 ppm/(g*day), at least about 0.3 ppm/(g*day), at least about 0.7 ppm/(g*day), at least about 1.25 ppm/(g*day), at least about 2 ppm/(g*day), at least about 3 ppm/(g*day), at least about 5 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 40 ppm/(g*day), at least about 75 ppm/(g*day), or at least about 100 ppm/(g*day) for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years. For example, the scale inhibitor may be present in an amount ranging from about 0.01 ppm/(g*day), about 0.05 ppm/(g*day), about 0.1 ppm/(g*day), about 0.5 ppm/(g*day), about 1 ppm/(g*day), about 1.5 ppm/(g*day), about 2 ppm/(g*day), or about 3 ppm/(g*day) to about 4 ppm/(g*day), about 4.5 ppm/(g*day), about 5 ppm/(g*day), about 6 ppm/(g*day), about 7 ppm/(g*day), or about 8 ppm/(g*day). ppm/(g*day), about 8 ppm/(g*day), about 10 ppm/(g*day), about 15 ppm/(g*day), about 30 ppm/(g*day), about 75 ppm/(g*day), or about 150 ppm/(g*day) is eluted from the coated proppant particulate 100, 200 and/or the encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years.

According to one or more exemplary embodiments, the paraffin inhibitor can leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, seep, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at a rate of at least about 0.1 ppm/(g*day), at least about 0.3 ppm/(g*day), at least about 0.7 ppm/(g*day), at least about 1.25 ppm/(g*day), at least about 2 ppm/(g*day), at least about 3 ppm/(g*day), at least about 5 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 40 ppm/(g*day), at least about 75 ppm/(g*day), or at least about 100 ppm/(g*day) for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years. For example, the paraffin inhibitor may be present in an amount of from about 0.01 ppm/(g*day), about 0.05 ppm/(g*day), about 0.1 ppm/(g*day), about 0.5 ppm/(g*day), about 1 ppm/(g*day), about 1.5 ppm/(g*day), about 2 ppm/(g*day), or about 3 ppm/(g*day) to about 4 ppm/(g*day), about 4.5 ppm/(g*day), about 5 ppm/(g*day), about 6 ppm/(g*day), about 7 ppm/(g*day), about 8 ppm/(g*day), about 9 ppm/(g*day), about 10 ppm/(g*day), about 11 ppm/(g*day), about 12 ppm/(g*day), about 13 ppm/(g*day), about 14 ppm/(g*day), about 15 ppm/(g*day), about 16 ppm/(g*day), about 17 ppm/(g*day), about 18 ppm/(g*day), about 19 ppm/(g*day), about 20 ppm/(g*day), about 21 ppm/(g*day), about 22 ppm/(g*day), about 23 ppm/(g*day), about 24 ppm/(g*day), about 25 ppm/(g*day), about 26 ppm/(g*day), about 27 ppm/(g*day), about 28 ppm/(g*day), about 29 ppm/(g*day), about 30 ppm/(g*day), about 31 ppm/(g*day), about 32 ppm/(g*day), about 33 ppm/(g*day), about 34 ppm/(g*day), about 35 ppm/(g*day), about 3 ppm/(g*day), about 8 ppm/(g*day), about 10 ppm/(g*day), about 15 ppm/(g*day), about 30 ppm/(g*day), about 75 ppm/(g*day), or about 150 ppm/(g*day) elutes from the coated proppant particulate 100, 200 and/or the encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years.

The coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 can also be coated and/or injected with the surfactants and/or nanoparticle dispersions described herein, so that the proppant particles 106 can serve as carriers for the surfactants and/or nanoparticle dispersions during hydraulic fracturing operations. As described above, the use of surfactants and/or nanoparticle dispersions coated on the proppant itself, rather than simply pumped into the formation, provides improved wetting properties. The selection of a specific nanoparticle dispersion or surfactant to be coated on and/or injected into the proppant particles 106 depends on the desired adjustment of the wetting properties of the proppant for the desired production enhancement. According to several exemplary embodiments, the nanoparticle dispersion or surfactant can be released from the coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 when the degradable coating 104 and/or degradable shell 302 dissolves in an aqueous or hydrocarbon fluid. According to this embodiment, as the coating 104 and/or shell 302 degrades, some of the nanoparticle dispersion or surfactant is released upon exposure to the passing fluid, thereby improving the wettability of the formation surface. The portion of the nanoparticle dispersion or surfactant that remains in the proppant will improve the wettability of the proppant itself.

Changing the wettability of the proppant can also reduce the conductivity loss caused by the fracturing fluid, control the relative permeability of the stream of fluids that may be encountered in storage, "lubricate" the proppant, allowing more efficient proppant arrangement when the fracture closes, and reduce the ultimate scaling on the proppant. Changing the wettability of the proppant can also provide significant flow effects under multiphase flow, as demonstrated by trapped gas saturation, changed surface tension/contact angle, and electrostatic charge on the proppant. Proppant particles 106 that are modified to have an "oil-wet" surface may be ideal in gas wells that produce water, while proppant particles 106 with different wettabilities can preferentially flow to the oil and reduce the water cut.

The surfactant and/or nanoparticle dispersion can also leach, elute, diffuse, seep, drain, desorb, dissolve, effluent, seep, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at any suitable rate. According to one or more exemplary embodiments, the surfactant and/or nanoparticle dispersion can be present at a rate of at least about 0.1 ppm/(g*day), at least about 0.3 ppm/(g*day), at least about 0.7 ppm/(g*day), at least about 1.25 ppm/(g*day), at least about 2 ppm/(g*day), at least about 3 ppm/(g*day), at least about 5 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 3 ppm/(g*day), at least about 5 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 30 ppm/(g*day), at least about 5 ppm/(g*day), at least about 15 ppm/(g*day), at least about 10 ppm/(g*day), at least about 20 ppm/(g*day), at least about 3 ... ppm/(g*day), at least about 40 ppm/(g*day), at least about 75 ppm/(g*day), or at least about 100 ppm/(g*day) from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years. For example, the surfactant and/or nanoparticle dispersion can be present in an amount of from about 0.01 ppm/(g*day), about 0.05 ppm/(g*day), about 0.1 ppm/(g*day), about 0.5 ppm/(g*day), about 1 ppm/(g*day), about 1.5 ppm/(g*day), about 2 ppm/(g*day), or about 3 ppm/(g*day) to about 4 ppm/(g*day), about 4.5 ppm/(g*day), about 5 ppm/(g*day), about 6 ppm/(g*day), or about 8 ppm/(g*day). ppm/(g*day), about 8 ppm/(g*day), about 10 ppm/(g*day), about 15 ppm/(g*day), about 30 ppm/(g*day), about 75 ppm/(g*day), or about 150 ppm/(g*day) is eluted from the coated proppant particulate 100, 200 and/or the encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years.

In one exemplary method of fracturing a subterranean formation, a hydraulic fluid is injected into the subterranean formation at a rate and pressure sufficient to open a fracture in the subterranean formation, and the fluid comprises a proppant composition comprising one or more coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500 as described herein containing one or more chemical treatments 102 and having one or more properties described herein, the fluid being injected into the fracture to prop the fracture in an open condition.

According to several exemplary embodiments, a method for diagnostic evaluation of a hydraulic fracturing operation is provided, the method comprising: 1) injecting a hydraulic fluid into a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; 2) injecting a proppant composition into the subterranean formation, wherein the proppant composition comprises coated proppant particles 100, 200 and/or encapsulated proppant particles 300, 400, 500, 3) wherein a chemical treatment 102 is separated from the proppant particles 106 over an extended period of time, 4) wherein the chemical treatment 102 is returned to the surface with the produced fluid, and 5) wherein the chemical treatment 102 is recovered and identified. According to several exemplary embodiments, the chemical treatment 102 is a biomarker or biotag.

According to several exemplary embodiments, in order to add porous chemically injected ceramic proppants to standard non-porous ceramic proppants in a hydraulic fracturing process in a manner that does not compromise the permeability or conductivity of the standard non-porous ceramic proppant alone, it is desirable to use a combination of different types of ceramic proppants comprising the standard non-porous and porous portions of the total ceramic proppant mass used in the fracturing operation. For example, according to several exemplary embodiments of the present invention, if the standard non-porous particulate selected is a lightweight ceramic proppant, the porous ceramic particulate can be a medium density ceramic proppant or a high density ceramic proppant. Furthermore, according to several exemplary embodiments of the present invention, if the standard non-porous particulate selected is a medium density proppant, the porous ceramic particulate can be a high density ceramic proppant.

For example, the fraction of medium-density porous ceramic proppant to be added to a standard non-porous lightweight ceramic proppant will determine the maximum porosity that the medium-density porous ceramic can have without affecting permeability. In this example, if a 10% fraction of medium-density porous proppant is added to a standard lightweight ceramic proppant, the maximum porosity of the medium-density porous proppant can be 12% in order not to reduce the permeability of the proppant compared to the permeability of the standard lightweight ceramic proppant alone, while adding a 10% fraction of medium-density porous proppant having a porosity of 20% may be detrimental to proppant permeability.

Figure 6 is a graph comparing the proppant permeability of lightweight ceramic proppants, medium density ceramic proppants, and high density ceramic proppants. As shown in Figure 6, the high density ceramic proppants have a higher permeability than the medium density ceramic proppants, which in turn have a higher permeability than the lightweight ceramic proppants. This variation is caused by differences in crystal structure due to differences in the composition of the starting materials. Figure 7 is a graph of the long-term permeability of a standard non-porous lightweight ceramic proppant and a lightweight porous ceramic proppant (at 25% porosity). Standard ceramic proppants are typically manufactured to eliminate as much porosity as possible in each particle, thereby maximizing the inherent strength of the particles. This is consistent with the properties of ceramic bodies, in which they tend to fail as a function of the maximum internal defect size and in this case the internal open pores are defects. Therefore, in general, the lower the internal porosity with smaller pore size, the stronger the ceramic body. Conversely, in general, the greater the internal porosity and the total amount of ceramic particles with larger pore size, the weaker its inherent strength. Thus, a lightweight ceramic proppant having 10% porosity in the particles will have a lower conductivity than a lightweight ceramic proppant having 5% porosity, which in turn will have a lower conductivity than a non-porous lightweight ceramic proppant.

Furthermore, the comparison of non-porous ceramic microparticles shown in Figure 6 can be replicated for porous ceramic microparticles. Specifically, a high-density porous ceramic proppant having a microparticle porosity of 12% will have a higher permeability than a medium-density ceramic proppant having a microparticle porosity of 12%, which in turn will have a higher permeability than a lightweight ceramic proppant having a microparticle porosity of 12%.

According to several exemplary embodiments, porous chemically injected porous ceramic proppants can have similar alumina content as standard non-porous ceramic proppants and can be added to standard non-porous ceramic proppants in hydraulic fractures in a manner that does not compromise the permeability or conductivity of the standard non-porous ceramic proppants alone. According to several exemplary embodiments, porous chemically injected porous ceramic proppants can have higher alumina concentrations than standard non-porous ceramic proppants and can be added to standard non-porous ceramic proppants in hydraulic fractures in a manner that does not compromise the permeability or conductivity of the standard non-porous ceramic proppants alone. According to such embodiments, the porous and non-porous proppants can be treated in different ways so that the mechanical properties of the chemically injected porous ceramic proppants are approximately the same as or better than the mechanical properties of the standard non-porous ceramic proppants.

The ceramic proppant composition comprising a mixture of porous ceramic proppants and non-porous ceramic proppants can have a conductivity of at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 95%, or at least about 99% of the conductivity of the non-porous ceramic proppant. For example, the ceramic proppant composition comprising a mixture of porous ceramic proppants and non-porous ceramic proppants can have a conductivity of about 25% to about 125%, about 55% to about 115%, about 65% to about 112%, about 75% to about 108%, about 85% to about 105%, about 95% to about 105%, or about 99.99% to about 102% of the conductivity of the non-porous ceramic proppant.

As described above, ceramic proppants can be manufactured to a range of apparent specific gravities, and this range of specific gravities reflects the range of internal porosity present in the ceramic particles. The internal porosity of commercial ceramic proppants is generally low (generally less than 5%, and such internal pores are not interconnected). However, as disclosed in U.S. Patent No. 7,036,591, the processing of ceramic proppants can be modified to produce porosity exceeding 30% within each ceramic particle. When the particle porosity exceeds about 5%, the pores of the particles are interconnected. According to several exemplary embodiments, the internally interconnected pores in the porous ceramic proppant can be injected with a chemical treatment agent. Methods for injecting porous ceramic proppants are well known to those of ordinary skill in the art, for example, see U.S. Patent No. 5,964,291 and U.S. Patent No. 7,598,209 and similar methods. For example, according to several exemplary embodiments of the present invention, strip mixing, microwave mixing, vacuum infusion, hot infusion, capillary action or blender processing at room temperature or elevated temperature can be used to inject the chemical treatment agent into the porous ceramic proppant.

As described above, the internal pores of the porous ceramic proppant particles 106 can be infused with a chemical treatment 102, such as a tracer material, such that the porous ceramic particles 106 serve as carriers for the tracer during hydraulic fracturing operations. By adjusting the type of porous ceramic particles 106 used as carriers, any potential impact on proppant conductivity caused by the use of the porous ceramic particles 106 can be avoided, according to the methods discussed above. According to certain embodiments of the present invention, the tracer material comprises metallic or non-metallic nanoparticles, while in other embodiments, the tracer material comprises a chemical tracer.

In one or more exemplary embodiments, the chemical treatment 102 includes one or more radio frequency identification (RFID) tags. The RFID tags can be incorporated into and/or onto any proppant particle 106 in any manner disclosed herein. The RFID tags can be coated onto and/or injected into the pores of the proppant (e.g., porous ceramic proppant particle 106). The RFID tags can have any suitable size. For example, the RFID tags can have a size suitable for injecting the RFID tags into one or more pores of the porous ceramic proppant particle 106. In one or more exemplary embodiments, the RFID tags can have a size ranging from about 10 nm to about 2 mm measured at their largest dimension. In one or more exemplary embodiments, the injected RFID tags can be eluted from the porous ceramic proppant particle 106 located in a subsurface environment and reliably supported on the surface by produced fluids. The produced fluids can be water or hydrocarbons, and the RFID tracer can be injected with a water-soluble or hydrocarbon-soluble resin material disclosed herein to allow the RFID tags to elute in the presence of produced water or produced hydrocarbons. The RFID tag can be a passive RFID tag or an active RFID tag. For example, a passive RFID tag can be eluted from the proppant particles disclosed above and activated by a power source located on or near the surface to transmit information from the RFID tag. Once activated, the RFID tag can emit a signal that can be recorded, decoded, and/or analyzed at or near the surface to determine which area is producing and whether water or hydrocarbons are being produced from the corresponding area.

According to several exemplary embodiments, the chemical treatment agent 102 may be or include a chemical tracer material, such as a biotag, various dyes, fluorescent materials, and biomarkers (e.g., DNA) as described in International Patent Publication No. WO2007/132137. Other chemical tracers may include fluorine-substituted compounds. According to several exemplary embodiments, to ensure that the tracer is reliably carried on surfaces in the produced fluid, the tracer may be soluble in the produced fluid. The produced fluid may be water or hydrocarbons, and there are tracers available that are soluble only in water, only in liquid hydrocarbons, or only in hydrocarbon gases. This variable solubility allows for more precise diagnostic capabilities. For example, hydraulic fracturing is typically performed in stages. That is, the entire hydrocarbon-bearing interval to be hydraulically fractured is not stimulated at the same time, but rather in stages. In the case of a horizontal well, up to 40 separate hydraulic fracturing operations or stages may be performed in the horizontal section. Because each stage of hydraulic fracturing carries additional costs, it is necessary to determine how many stages are contributing to production from the well, and further determine which contributing stages are producing hydrocarbons and which contributing stages are producing water. This goal can be achieved using unique tracer materials. For example, if a well is hydraulically fractured in five stages and determining which stages are producing liquid hydrocarbons and which stages are producing water is diagnostically important, a portion containing a unique liquid hydrocarbon-soluble tracer, 1H, can be introduced into the proppant of the first stage. Additionally, a portion containing a unique water-soluble tracer, 1W, can be added to this stage. For the second stage of the hydraulic fracturing operation, a portion containing a unique liquid hydrocarbon-soluble tracer, 2H, can be introduced into the proppant of the second stage. Additionally, a portion containing a unique water-soluble tracer, 2W, can be added to this stage. This method of adding uniquely distinguishable hydrocarbon-soluble and water-soluble tracers contained within and/or on the proppant particles can be continued for all or a portion of the subsequent stages. Then, after the hydraulic fracturing operation is completed and the well is in production, samples of the produced water and hydrocarbons can be captured at various time points after production begins and analyzed for the presence of the unique tracer material. By determining the presence and relative concentration of each tracer material, a diagnostic determination of the effectiveness of the stimulation and the hydrocarbon content of the stimulated formation can be made. This diagnostic information can then be used to optimize subsequent hydraulic fracturing operations in nearby wells.

Coating the biomarkers onto and/or injecting the biomarkers into the proppant particles 106, rather than adding the biomarkers directly to the fracturing fluid, allows for long-term diagnostic capabilities that would otherwise be unavailable. When the markers are added directly to the fracturing fluid, they immediately flow back with the fluid when the well is in production because there is no mechanism to retain the markers in the well. Therefore, the diagnostic benefit of adding the markers directly to the fracturing fluid is limited. In contrast, when the biomarkers are coated onto and/or injected into the proppant particles 106, the elution of the markers is slow and can be controlled by one or both of the following properties: the porosity of the proppant particles, or the addition of a permeable coating to the proppant particles 106 to delay the release of the biomarkers.

In order for the biomarkers to be reliably carried on the surface of the produced fluid, the biomarkers must be able to elute from the proppant particles 106 and distribute into the produced fluid, which can be a water-based fluid or a hydrocarbon-based fluid. According to several exemplary embodiments, the biomarkers can be encapsulated to preferentially distribute into one or both of the water phase and the hydrocarbon phase, depending on the diagnostic goal. This variable distribution allows for more precise diagnostic capabilities. For example, as mentioned above, hydraulic fracturing is typically performed in stages. That is, the entire hydrocarbon-bearing layer to be hydraulically fractured is not stimulated at the same time but is stimulated in stages. In the case of a horizontal well, up to 40 independent hydraulic fracturing operations can be performed in the horizontal well. Because each stage of hydraulic fracturing requires additional cost, it is necessary to determine how many stages are contributing to production from the well, and further determine which contributing stages are producing hydrocarbons and which are producing water.

According to several exemplary embodiments, the biomarkers disclosed herein can be used to achieve this goal. For example, according to several exemplary embodiments, if a well is hydraulically fractured in five stages and determining which stages are producing hydrocarbons and which stages are producing water is diagnostically important, the proppant particles 106 can contain a unique hydrocarbon-partitioning biomarker for the first stage, such as encapsulated synthetic DNA with a known sequence. Furthermore, one or more proppant particles 106 containing a unique water-partitioning biomarker can be added to the first stage. For the second stage of the hydraulic fracturing operation, the proppant particles 106 can contain a different unique hydrocarbon-partitioning biomarker. Furthermore, one or more proppant particles 106 that can contain a different unique water-partitioning biomarker can be added to the second stage. According to several exemplary embodiments, the use of different, uniquely distinguishable hydrocarbon-partitioning and water-partitioning biomarkers contained on and/or in the proppant particles 106 can be continued for all or a portion of the subsequent stages. In addition to determining which stages of a hydraulically fractured well are producing hydrocarbons and/or water, it may also be desirable to determine the fraction of the resulting fractures that contribute to fluid flow. The length and height of the generated fractures can be assessed by various means known to those skilled in the art. Fracture lengths of several hundred feet and heights of 50 feet or more are common. Furthermore, it has been determined that the entire length and height of the generated fractures may not contribute to well production. This lack of contribution can be determined by a number of methods known to those skilled in the art. To the extent that the entire fracture does not contribute to flow, the cost of generating the non-contributing portion is wasted, or conversely, the failure of a portion of the fracture to contribute may result in reduced hydrocarbon production from the well. Therefore, it is valuable to assess the fraction of the generated fractures that contribute to flow. This knowledge can lead to optimization of the design of subsequent hydraulic fracturing operations. This can be achieved by introducing one or more proppant particles 106 containing unique water and/or hydrocarbon distributing biomarkers into a segment of proppant pumped in a particular stage, and then introducing one or more proppant particles 106 containing different unique water and/or hydrocarbon distributing biomarkers into a second segment of proppant pumped in the same stage. This method can be replicated for multiple segments of the stage one desires to interrogate. In the case of a 40-stage hydraulic fracturing operation where the contribution of both hydrocarbons and water from each stage and the contribution of hydrocarbons and water from 5 segments in each stage need to be determined, 400 unique biomarkers are required.

According to several exemplary embodiments, when the well is in production after a hydraulic fracturing operation is completed, the biomarkers will elute from the proppant particles 106 and partition into one or both of the produced hydrocarbons and water. Samples of the produced water and hydrocarbons are then captured at different time points and analyzed for the presence of unique biomarkers. By determining the presence and relative concentration of each biomarker, a diagnostic determination of the effectiveness of the stimulation and the hydrocarbon or water production capacity of the stimulated formation can be made. This diagnostic information can then be used to optimize subsequent hydraulic fracturing operations in nearby wells.

To accomplish this, and in accordance with several exemplary embodiments, the biomarker is separated from the proppant particles 106 after the proppant particles are injected into the fracture. In several exemplary embodiments, the separation of the biomarker from the proppant particles 106 can be achieved by leaching, eluting, diffusing, seeping, draining, desorbing, dissolving, escaping, seeping, or leaking the biomarker from the proppant, or any combination thereof. Furthermore, such leaching, eluting, diffusing, seeping, draining, desorbing, dissolving, escaping, seeping, or leaking the biomarker from the proppant, or any combination thereof, can be further controlled by the permeable coating 104.

As previously mentioned, by adjusting the encapsulating material, the distribution of the biomarker (i.e., partitioning into the hydrocarbon phase or the water phase) can be adjusted based on the needs of the fracturing operation. For example, if diagnostic information regarding the hydrocarbon-producing portion of the well is desired, the proppant particles 106 can be injected and/or coated with encapsulated hydrocarbon-distributing biomarkers, which will then separate from the proppant into the surrounding hydrocarbon fluid. Conversely, if diagnostic information regarding the water-producing portion of the well is desired, the proppant particles can be injected and/or coated with encapsulated water-distributing biomarkers, which will then separate from the proppant into the water.

The biomarker 102 may leach, elute, diffuse, seep, drain, desorb, dissolve, exude, seep, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at any suitable rate. According to one or more exemplary embodiments, the biomarker can leach, elute, diffuse, seep, drain, desorb, dissolve, exude, seep, or leak from the coated proppant particulate 100, 200 and/or encapsulated proppant particulate 300, 400, 500 at a rate of at least about 0.1 ppm/(gram*day), at least about 0.3 ppm/(gram*day), at least about 0.7 ppm/(gram*day), at least about 1.25 ppm/(gram*day), at least about 2 ppm/(gram*day), at least about 3 ppm/(gram*day), at least about 4 ppm/(gram*day), at least about 6 ppm/(gram*day), or at least about 8 ppm/(gram*day) for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years. For example, the biomarker 102 can be present at a concentration of from about 0.01 ppm/(gram*day), about 0.05 ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.5 ppm/(gram*day), about 1 ppm/(gram*day), about 1.5 ppm/(gram*day), about 2 ppm/(gram*day), or about 3 ppm/(gram*day) to about 4 ppm/(gram*day), about 4.5 ppm/(gram*day), about 5 ppm/(gram*day), about 6 ppm/(gram*day), or about 8 ppm/(gram*day). ppm/(g*day), about 7 ppm/(g*day), about 8 ppm/(g*day), about 10 ppm/(g*day), about 15 ppm/(g*day), about 30 ppm/(g*day), or about 75 ppm/(g*day)/(g*day) elutes from the coated proppant particulate 100, 200 and/or the encapsulated proppant particulate 300, 400, 500 for at least about 2 weeks, at least about 1 month, at least about 2 months, at least about 6 months, at least about 9 months, at least about 1 year, or at least about 2 years.

According to several exemplary embodiments, after the chemical treatment 102 (e.g., biomarker) is separated from the proppant and dispensed into the production fluid, the production fluid then transports the biomarker to the surface. Once the production fluid reaches the surface, the fluid can be analyzed for the presence of the biomarker.

According to several exemplary embodiments, the chemical treatment 102 contains one or more biomarkers with unique identifiers, and the unique identifiers of the one or more biomarkers are recorded before the one or more markers are injected into the fracture. In several exemplary embodiments, when multiple biomarkers are used in one or all stages of the fracturing, this recording enables the well operator to match the biomarkers in the production fluid with the fracture segment that produced the biomarkers. For example, if three unique DNA markers are injected in stages 1, 2, and 3 of the hydraulic fracturing stimulation operation, the unique identifying base sequence of each DNA marker injected in stages 1, 2, and 3 will be recorded. If DNA is detected on the surface of the production fluid, the sequence of the returned DNA can be compared with the recorded sequence to determine which stage produced the DNA. The relative amount of each marker can be used to quantitatively assess the relative volume of fluid produced from each stage. Identifying and detecting DNA sequences is well known in the art, and many companies manufacture "off-the-shelf" identification and detection assays. For example, DNA detection and identification assays and kits are commercially available from Molecular Devices, LLC and Illumina, Inc. In addition, DNA replication methods are well known to those of ordinary skill in the art. This allows very low levels of DNA present in the generated fluid (which may be below the detection limit) to be identified by first using a replication procedure to increase the concentration of the DNA to above the detection limit. Because the replication method proportionally increases all the DNA present, the relative amounts of the individual DNA markers present do not change.

According to several exemplary embodiments, once the biomarkers are recovered and identified from the production fluid, a comparative analysis of the amount of biomarkers from each stage or stage segment in the sample can be correlated with the amount of hydrocarbons or water produced from that segment. For example, based on the amount of biomarkers recovered, the relative hydrocarbon or water volume contribution of one or more stages of the formation can be assessed, i.e., the more hydrocarbons or water produced from that stage, the more biodetections from that stage are. In addition, based on the amount of biomarkers recovered from the segments of that stage, the relative hydrocarbon or water volume contribution of the segments or stages can be assessed. Based on this analysis, a diagnostic record can be developed across multiple stages of the fractured formation, providing the well operator with detailed knowledge of the production volume (or lack thereof) of the entire fractured formation. This analysis can also be repeated periodically over longer periods of time to establish production performance trends for the well, thereby providing diagnostic information that is currently unavailable with the prior art.

According to several exemplary embodiments, the coated proppant particles 100, 200 are prepared according to a two-step process. In the first step, the chemical treatment 102 is infused into the porous ceramic proppant particles 106. In the second step, the infused porous ceramic proppant particles 106 are coated with a semi-permeable, substantially non-degradable polymer coating 104, 204. In several exemplary embodiments, the chemical treatment 102 is infused into the porous ceramic proppant particles 106 by vacuum infusion. In other exemplary embodiments, the chemical treatment 102 is infused into the porous ceramic proppant particles 106 using a thermal infusion process, in which the porous ceramic proppant particles 106 are heated and wetted with a solution containing the chemical treatment 102. As the porous ceramic proppant particles 106 cool, capillary action causes the chemical treatment 102 to be infused into the porous ceramic proppant particles 106. In one or more exemplary embodiments, the chemical treatment 102 can be infused into the porous ceramic proppant particles 106 using a microwave infusion process. A suitable microwave infusion process is disclosed in US Patent Application No. 14/813,452, which is incorporated herein by reference in its entirety.

According to several exemplary embodiments, chemically infused coated porous ceramic proppants are prepared according to a one-step process. According to the one-step process, porous ceramic proppant particles 106 are infused with a chemical treatment 102 using the hot infusion process described above and coated with a semi-permeable, substantially non-degradable polymer coating 104, 204 before the heat from the hot infusion process is dissipated.

According to several exemplary embodiments, the coated proppant particles 100, 200 can be prepared according to any suitable method. For example, the chemical treatment agent 102 can be applied to and/or contacted with the proppant particles 106 to produce proppant particles containing the chemical treatment agent. The proppant particles containing the chemical treatment agent can be coated with the semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104, 204. In several exemplary embodiments, additional chemical treatment agent 102 can be mixed with the semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104, 204 before, during, or after coating the proppant particles 106. In other exemplary embodiments, the chemical treatment agent 102 is injected into any porous space of the proppant particles 106 disclosed herein before coating with the chemical treatment agent 102, semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104, 204. As described herein, the coated proppant particles 100, 200 can be prepared without the use of solvents.

According to several exemplary embodiments, encapsulated proppant particles 300, 400, and 500 are prepared according to a three-step process. In the first step, a chemical treatment 102 is infused into porous ceramic proppant particles 106. In the second step, the infused porous ceramic proppant particles 106 are coated with a semi-permeable, substantially non-degradable polymer coating 104 to provide coated proppant particles. In several exemplary embodiments, the chemical treatment 102 is infused into the porous ceramic proppant particles 106 by vacuum infusion. In other exemplary embodiments, the chemical treatment 102 is infused into the porous ceramic proppant particles 106 using a thermal infusion process, in which the porous ceramic proppant particles 106 are heated and wetted with a solution containing the chemical treatment 102. As the porous ceramic proppant particles 106 cool, capillary action causes the chemical treatment 102 to be infused into the porous ceramic proppant particles 106. In one or more exemplary embodiments, the chemical treatment 102 can be infused into the porous ceramic proppant particles 106 using a microwave infusion process. Suitable microwave infusion processes are disclosed in U.S. Patent Application No. 14/813,452, which is incorporated herein by reference in its entirety. In a third step, a degradable shell 302 can be applied to the proppant particles 106 containing the chemical treatment 102 to provide encapsulated proppants 300, 400, 500.

According to several exemplary embodiments, encapsulated proppants 300, 400, 500 are prepared according to a two-step process. In a first step, porous ceramic proppant particles 106 are infused with a chemical treatment agent 102 using the hot infusion process or microwave infusion process described above and coated with a semi-permeable, substantially non-degradable polymer coating 104, 204 before the heat from the hot infusion process or microwave infusion process is dissipated. In a second step, proppant particles 106 containing the chemical treatment agent 102 can be coated on the degradable shell 302 to provide encapsulated proppants 300, 400, 500.

According to several exemplary embodiments, the encapsulated proppant particles 300, 400, 500 can be prepared according to any suitable method. For example, the chemical treatment agent 102 can be applied to and/or contacted with the proppant particles 106 to produce the proppant particles containing the chemical treatment agent. When producing the encapsulated proppant particles 300, 400, 500, the proppant particles containing the chemical treatment agent can be coated with the semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104. In several exemplary embodiments, additional chemical treatment agent 102 can be mixed with the semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104 before, during, or after coating the proppant particles 106. In other exemplary embodiments, the chemical treatment agent 102 is injected into any porous space of the proppant particles 106 disclosed herein before coating with the chemical treatment agent 102, semi-permeable substantially non-degradable polymer, degradable polymer, and/or self-polishing polymer 104. In one or more exemplary embodiments (not shown), the chemical treatment 102 may be mixed with the degradable shell 302 before, during, or after the degradable shell 302 is applied directly or indirectly to the proppant particulate 106. As described herein, the chemical treatment 102 may be introduced into the encapsulated proppants 300, 400, 500 in any manner without the use of a solvent.

According to several exemplary embodiments, a composite ceramic proppant composition is produced for use in hydraulic fracturing. According to several exemplary embodiments, a composite ceramic proppant composition is produced for use in a frac-pack. According to several exemplary embodiments, a composite ceramic proppant composition is produced for use in a gravel-pack. According to several exemplary embodiments, the composite ceramic proppant composition comprises porous ceramic proppant particles 106 that have been injected with a chemical treatment 102 without the use of a solvent. In addition, according to several exemplary embodiments, the injected porous ceramic proppant particles 106 are coated with a semi-permeable, substantially non-degradable polymer coating 104, 204. According to several other exemplary embodiments, the injected porous ceramic proppant particles 106 are coated with a degradable polymer 104, 204. According to several other exemplary embodiments, the injected porous ceramic proppant particles 106 are coated with a self-polishing polymer 104, 204.

According to several exemplary embodiments, another composite ceramic proppant composition for use in hydraulic fracturing is produced. According to several exemplary embodiments, the composite ceramic proppant composition includes uncoated sand and sand coated and/or attached with a chemical treatment without the use of a solvent. Furthermore, according to several exemplary embodiments, the sand containing the chemical treatment is coated with a semi-permeable, substantially non-degradable polymer 104, 204. According to several other exemplary embodiments, the sand containing the chemical treatment is coated with a degradable polymer 104, 204. According to several other exemplary embodiments, the sand containing the chemical treatment is coated with a self-polishing polymer 104, 204.

According to several exemplary embodiments, the chemical treatment 102 is injected into the porous ceramic proppant particles 106 without the use of a solvent by melting, thawing, heating, softening, or warming the chemical treatment 102 to a sufficiently low viscosity to allow injection into the porous ceramic proppant particles 106. In several exemplary embodiments, the sufficiently low viscosity to allow injection into the porous ceramic proppant particles 106 is about 1,000-10,000 centipoise (cps), about 1,000-5,000 cps, or about 1,000-2,500 cps.

According to several exemplary embodiments, after the chemical treatment 102 is melted to a sufficiently low viscosity to allow injection into the porous ceramic proppant particles 106 , the molten chemical treatment 102 is injected into the porous ceramic proppant particles 106 using the infusion method described above.

According to several exemplary embodiments, a composite proppant composition is produced for hydraulic fracturing. According to several exemplary embodiments, the composite proppant composition comprises one or more of the following: the coated proppant 100, 200 and/or the encapsulated proppant 300, 400, 500 described herein. The composite proppant composition can comprise the coated proppant 100, 200 and/or the encapsulated proppant 300, 400, 500 in any suitable amount. In one or more exemplary embodiments, the composite proppant composition can include at least about 1 weight percent, at least about 2 weight percent, at least about 5 weight percent, at least about 10 weight percent, at least about 20 weight percent, at least about 30 weight percent, at least about 40 weight percent, at least about 50 weight percent, at least about 60 weight percent, at least about 70 weight percent, at least about 80 weight percent, at least about 90 weight percent, at least about 95 weight percent, at least about 99 weight percent, or 100 weight percent of the coated proppant 100, 200 and/or the encapsulated proppant 300, 400, 500, based on the total weight of the composite proppant composition. In one or more exemplary embodiments, the composite ceramic proppant composition can have a coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500 concentration of about 1 wt%, about 2 wt%, about 5 wt%, about 10 wt%, about 20 wt%, or about 30 wt% to about 40 wt%, about 50 wt%, about 60 wt%, about 70 wt%, about 80 wt%, about 90 wt%, about 95 wt%, or about 99 wt%, or more.

According to several exemplary embodiments, a method of fracturing a subterranean formation includes injecting a hydraulic fluid into the subterranean formation at a rate and pressure sufficient to open a fracture in the subterranean formation, and injecting a fluid comprising a proppant composition into the fracture to prop the fracture in an open condition, the proppant composition comprising one or more of the coated proppants 100, 200 and/or the encapsulated proppants 300, 400, 500 disclosed herein.

According to several exemplary embodiments, the coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 may be included in a frac pack or gravel pack. During a frac pack or gravel pack operation, the coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 are placed in the annular space between the well casing and the internal screen or liner in a cased-hole frac or gravel pack, and/or in the annular space within the wellbore outside the screen or liner during open-hole fracturing, frac packing, or gravel packing operations. The pack material is primarily used to filter solids produced with formation fluids during oil and gas well production operations. This filtration helps prevent these sand or other particles from being introduced into the borehole and reaching the surface along with the desired fluid. Otherwise, due to the corrosive nature of such particles, such undesirable particles could damage the wellbore and surface tubing as the well fluid flows and complicate the fluid separation process.

The frac pack and/or gravel pack may include any suitable amount of the coated proppant 100, 200 and/or the encapsulated proppant 300, 400, 500. In one or more exemplary embodiments, the frac pack and/or gravel pack may include at least about 1 wt%, at least about 2 wt%, at least about 5 wt%, at least about 10 wt%, at least about 20 wt%, at least about 30 wt%, at least about 40 wt%, at least about 50 wt%, at least about 60 wt%, at least about 70 wt%, at least about 80 wt%, at least about 90 wt%, at least about 95 wt%, at least about 99 wt%, or 100 wt% of the coated proppant 100, 200 and/or the encapsulated proppant 300, 400, 500.

8 depicts a perspective view of an illustrative pre-packed screen assembly including a proppant pack 810 comprising coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500. Proppant pack 810 may include coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 in any suitable amount. In one or more exemplary embodiments, the proppant pack 810 may comprise at least about 1 weight percent, at least about 2 weight percent, at least about 5 weight percent, at least about 10 weight percent, at least about 20 weight percent, at least about 30 weight percent, at least about 40 weight percent, at least about 50 weight percent, at least about 60 weight percent, at least about 70 weight percent, at least about 80 weight percent, at least about 90 weight percent, at least about 95 weight percent, at least about 99 weight percent, or 100 weight percent coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500.

As shown in FIG8 , a pre-packed screen assembly 800 can include a pipe 802 having a perforated section 804. At least a portion of the perforated section 804 can be at least partially surrounded by a screen 806. For example, the screen 806 can be circumferentially arranged around the perforated section 804 and axially aligned with the pipe 802. An annulus 808 can be formed between the pipe 802 and the screen 806. A proppant pack 810 can be arranged between the pipe 802 and the screen 806 in the annulus 808. A plurality of longitudinally arranged rods 812 can be arranged around the proppant pack 810 such that the screen 806 is at least partially offset from the proppant pack 810. The rods 812 can be spaced apart from each other and aligned coaxially with the pipe 802. The screen 806 can be wrapped around the rods 812 and welded to the pipe 802 via welds 814. Tube 802 may include a threaded portion 816 on at least one end thereof, for example, for connecting pre-packed screen assembly 800 to production tubing (not shown). FIG9 depicts a cross-sectional view of the pre-packed screen taken along line 8-8 of FIG8. Examples of pre-packed screen assemblies can be found in U.S. Patent Nos. 4,487,259 and 5,293,935, the entire disclosures of which are incorporated herein by reference.

The proppant pack 810 is fused together and/or consolidated. The proppant pack 810 can be consolidated before, during, or after the proppant particles are contained in the annulus 808. For example, loose, unconsolidated resin-coated proppant particles can be introduced into the annulus 808 of the prepacked screen assembly 800. After the coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500 are introduced into the annulus 808, the reactive crosslinking agent can contact the proppant 100, 200 and/or encapsulated proppant 300, 400, 500 to consolidate the proppant pack 810. After the prepacked screen assembly 800 is completed at the surface, the prepacked assembly 800 can be lowered downhole to the desired depth.

According to several exemplary embodiments, the coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 disclosed herein can be placed in any production tubing, such as a riser, to deliver the chemical treatment 102 to any downstream tubing and/or equipment. According to several exemplary embodiments, the coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 can be placed in any pipeline or process equipment, such as a heat exchanger, to deliver the chemical treatment 102 to the pipeline or any downstream process tubing and/or equipment. The coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 can be placed in the production tubing, pipeline, and/or process tubing in any suitable manner. In one or more exemplary embodiments, the coated proppants 100, 200 and/or encapsulated proppants 300, 400, 500 may be placed or contained in a removable canister, which may then be placed in a production tubing, pipeline, and/or process tubing, e.g., upstream and proximate to a pump or compressor.

FIG10 depicts a cross-sectional side view of an assembly 1000 having a tank 1002 positioned within a tube 1112. Tank 1002 may include a proppant pack 1004 comprising coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500. Tank 1002 may have any suitable size and shape. For example, tank 1002 may have a size and shape corresponding to that of tube 1112. Tube 1112 may be a component that is attached to or otherwise in fluid communication with a heat exchanger, tubular reactor, subsea riser, pipeline, pump, or any other suitable process equipment. As shown in FIG10 , tank 1002 may have a cylindrical body 1006 having an open first end 1008 and an open second end 1010 to allow fluid to flow from the first end to the second end. At least a portion of the cylindrical body 1006 can be attached to the inner wall or surface of the tube 1112 in any suitable manner for securing the canister 1002 to the tube 1112. For example, the body 1006 can include a threaded section (not shown) that can mate with a corresponding threaded section (not shown) located on or within the tube 1112.

FIG11 depicts a cross-sectional end view of tank 1002. Proppant pack 1004 can fill the entire cross-section of body 1006 and/or the interior volume of tank 1002. In one or more exemplary embodiments, proppant pack 1004 at least partially fills the interior volume of body 1006 of tank 1002. Proppant pack 1004 can fill at least 10% by volume, at least 25% by volume, at least 50% by volume, at least 75% by volume, at least 90% by volume, at least 95% by volume, or at least 99% by volume, or approximately 100% by volume of the interior volume of body 1006. In one or more exemplary embodiments, proppant pack 1004 can occupy from about 10% to about 90% by volume, from about 20% to about 80% by volume, or from about 30% to about 70% by volume of the interior volume of body 1006. 10. The proppant pack 1004 can have any suitable density of coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500. For example, the amount of coated proppant 100, 200 and/or encapsulated proppant 300, 400, 500 in the proppant pack 1004 can be selected to allow any desired fluid flow rate from the first end 1008 to the second end 1010. FIG12 depicts a perspective view of the tank 1002 with a cutaway section 1200 showing the proppant pack 1004. The proppant pack can be at least partially contained within the body 1006 by fluid permeable screens 1202, with a first screen 1202 located near the first end 1008 and a second screen (not shown) located near the second end 1010. Screen 1202 may have any configuration or design suitable for allowing fluid to flow into and out of tank 1002 and preventing proppant flow from tank 1002 .

The following examples are illustrative of the compositions and methods discussed above.

Example

The following examples were conducted using exemplary materials to determine the elution rate of DTPMP (diethylenetriaminepenta(methylenephosphonic acid), a corrosion inhibitor and scale inhibitor) from porous proppants coated with various polymers and infused with DTPMP, compared to uncoated porous proppants infused with DTPMP. These examples are intended to illustrate exemplary embodiments of the present invention and are not intended to be exhaustive.

Example 1

Four 500 gram batches of 20/40 CARBO UltraLite, an ultra-lightweight ceramic proppant having an ASG of 2.71 and a porosity of 20-25%, commercially available from CARBO Ceramics, Inc., were each injected with a 41% solids solution of diethylenetriaminepenta(methylenephosphonic acid) ("DTPMP"), commercially available from Riteks, Inc., and then coated with a semi-permeable, substantially non-degradable polymer in a two-step process described below.

Each batch of proppant was heated in an oven set at 482°F (250°C) for approximately 1 hour. The heated batches of proppant were then removed from the oven and cooled until they reached a temperature between 430-440°F as monitored by a thermocouple. Once the proppant batches reached the desired temperature, 64.2 grams of DTPMP solution was added to each batch and allowed to infuse into the proppant particles for approximately 3 minutes, such that the DTPMP comprised 5% by weight of the injected proppant. After the proppant particles were infused with DTPMP, each batch was coated with a semi-permeable, substantially non-degradable polymer.

The Batch 1 proppant was coated with a phenol-formaldehyde standard reactive resin, available from Plastics Engineering Company under the trade name Plenco 14870, according to the following procedure. Compared to the other phenol-formaldehyde resins discussed below, Plenco 14870 resin has a relatively low viscosity of approximately 1100 cps at 150° C. After the coating process, the Batch 1 proppant contained 2 wt.% of the polymer coating.

The Batch 1 proppant was placed in a heated mixing bowl and monitored with a thermocouple until the proppant reached a temperature between 410-420°F. When the proppant reached the desired temperature, 8.08 grams of phenol formaldehyde resin was added to the proppant, melted, and spread over the proppant for approximately 45 seconds. Next, 2.63 grams of a 40% hexamethylenetetramine (also known as "hexamine") solution commercially available from The Chemical Company was added to crosslink and cure the phenol formaldehyde resin and allowed to mix for 1 minute and 25 seconds. Finally, 1.2 grams of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade name "Chembetaine ^™ CAS" was added and mixed for 1 minute.

The Batch 2 proppants were coated with a phenol formaldehyde highly reactive, high viscosity polymer resin, commercially available from Plastics Engineering Company under the trade name Plenco 14750, according to the following procedure. Compared to the other phenol formaldehyde resins discussed above and below, Plenco 14750 resin has a relatively high viscosity of approximately 34,900 cps at 150° C. After the coating process, the Batch 2 proppants contained 2% by weight of the polymer coating.

The Batch 2 proppant was placed in a heated mixing bowl and monitored with a thermocouple until the proppant reached a temperature between 410-420°F. When the proppant reached the desired temperature, 8.08 grams of phenol-formaldehyde resin was added to the proppant, allowed to melt, and spread over the proppant for approximately 45 seconds. Next, 2.63 grams of a 40% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol-formaldehyde resin and allowed to mix for 1 minute and 25 seconds. Finally, 1.2 grams of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade designation "Chembetaine ^™ CAS" was added and mixed for 1 minute.

The Batch 3 proppants were coated with the above-mentioned phenol formaldehyde highly reactive, high viscosity polymer resin, commercially available from Plastics Engineering Company under the trade name Plenco 14750, according to the following procedure. As discussed above, Plenco 14750 resin has a relatively high viscosity of approximately 34,900 cps at 150° C. After the coating process, the Batch 3 proppants contained 4 wt.% of the polymer coating.

The Batch 3 proppant was placed in a heated mixing bowl and monitored with a thermocouple until the proppant reached a temperature between 410-420°F. When the proppant reached the desired temperature, 17.61 grams of phenol-formaldehyde resin was added to the proppant, allowed to melt, and spread over the proppant for approximately 45 seconds. Next, 5.72 grams of a 40% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol-formaldehyde resin and allowed to mix for 1 minute and 25 seconds. Finally, 1.2 grams of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade designation "Chembetaine ^™ CAS" was added and mixed for 1 minute.

The Batch 4 proppants were coated with a polyurethane polymer according to the following procedure. The polyurethane polymer was prepared by reacting a polyisocyanate resin with a curing agent, both of which are commercially available from Air Products, Inc. under the trade names ISO HDiT and IC221, respectively. After the coating process, the Batch 4 proppants contained 4 weight percent of the polyurethane polymer coating.

Batch 4 proppant was placed in a mixing bowl maintained at room temperature. At room temperature, 13.5 grams of IC221 curing agent was added to the proppant batch and mixed for 1 minute. After 1 minute, 7.2 grams of ISO HDiT polyisocyanate resin was added to the proppant batch and mixed with the proppant for approximately 5 minutes.

A fifth proppant batch was then prepared, comprising 1000 grams of 20/40 CARBO UltraLite ceramic proppant. The Batch 5 proppant was injected with DTPMP and coated with a phenol-formaldehyde, highly reactive, low-viscosity polymer resin commercially available from Plastics Engineering Company under the trade name Plenco 14862 in a one-step hot infusion process. Compared to the other phenol-formaldehyde resins discussed above and below, Plenco 14862 resin has a relatively low viscosity of approximately 1080 cps at 150°C. After the one-step hot infusion process, the Batch 5 proppant comprised 2 wt% of the polymer coating.

Batch 5 ceramic proppants were heated in an oven set at 482°F (250°C) for approximately one hour. The heated batch of proppants was then removed from the oven and allowed to cool until it reached a temperature between 430-440°F as monitored by a thermocouple. Once the proppant batch reached the desired temperature, 128.4 grams of a DTPMP solution was added to the batch and allowed to infuse into the proppant particles for approximately 5 seconds, such that the DTPMP comprised 5% by weight of the injected proppant. After 5 seconds, 17.35 grams of a phenol formaldehyde highly reactive, low viscosity polymer resin (Plenco 14862) was added to the proppant batch. After another 5 seconds, 5.64 grams of a 40% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol formaldehyde resin, and mixing was allowed for 10 minutes and 15 seconds. Finally, 1.2 grams of 50-60% cocamidopropyl hydroxysultaine surfactant, available from The Lubrizol Corporation under the trade designation "Chembetaine ^™ CAS," was added and allowed to mix for an additional 30 seconds.

Finally, a sixth proppant batch was prepared as a control.Batch 6 (control proppant batch) contained 1000 grams of 20/40 CARBO UltraLite ceramic proppant injected with DTPMP but did not contain a polymer coating.

Batch 6 ceramic proppant was heated in an oven set at 482°F (250°C) for approximately 1 hour. The heated batch of proppant was removed from the oven and cooled until it reached a temperature between 430-440°F as monitored by a thermocouple. Once the proppant batch reached the desired temperature, 241.8 grams of DTPMP solution was added to the batch and allowed to infuse into the proppant particles for approximately 3 minutes, resulting in a DTPMP concentration of 9 weight percent of the injected proppant.

Table 1 below shows the six batches prepared in Example 1

Table 1 - Batches of Example 1

Batch number Injection/polymer coating Batch 1 5 wt% DTPMP, 2 wt% phenol formaldehyde standard reactivity low viscosity (Plenco 14870) Batch 2 5 wt% DTPMP, 2 wt% phenol formaldehyde, high reactivity, high viscosity (Plenco 14750) Batch 3 5 wt% DTPMP, 4 wt% phenol formaldehyde, high reactivity, high viscosity (Plenco 14750) Batch 4 5 wt% DTPMP, 4 wt% polyurethane Batch 5 5 wt% DTPMP, 2 wt% phenol formaldehyde, high reactivity, low viscosity (Plenco 14862) Batch 6 9 wt% DTPMP, uncoated

Proppant batches 1-6 were then placed in a seawater eluent for 1 hour. The seawater eluent was prepared according to the ASTM D1141-98 (2013) procedure and had the composition shown in Table 2 below.

Table 2

After 1 hour, the amount of DTPMP present in the eluate was determined (parts per million, ppm). For each of proppant batches 1-5, the eluate was subsequently tested for the presence of DTPMP at 2, 3, 6, 25, 27.5, 29.5, and 97.5 hours, respectively. For proppant batch 1, the eluate was additionally tested for the presence of DTPMP at 100, 102, 104.5, and 120.5 hours. For batch 6, the eluate was subsequently tested for the presence of DTPMP at 2, 3, 4, 5, 21, 22, 23, 24, 26, 27, 28, 29, 44, 47, 49, 53, 70, and 74 hours.

The amount of DTPMP detected in the eluate in ppm was plotted as a function of time to obtain the elution profile shown in FIG13. In FIG13, a line has been drawn at 6 ppm, which represents the minimum effective concentration of DTPMP as a corrosion inhibitor and scale inhibitor. By plotting the amount of DTPMP detected in the eluate of proppant batches 1-6 versus time and comparing these results to the 6 ppm line, the length of time it takes for a particular proppant batch to elute an effective amount of DTPMP can be determined.

Figure 13 clearly shows that proppant batches 1-5, which included a semipermeable, substantially non-degradable polymer coating, eluted an effective amount of DTPMP over a longer period of time compared to proppant batch 6, which did not include a semipermeable, substantially non-degradable polymer coating. Figure 13 also clearly shows that for the three proppant batches injected with 5 wt% DTPMP and coated with 2 wt% phenol formaldehyde according to the two-step process (i.e., proppant batches 1-3), the lower the viscosity of the resin used to make the phenol formaldehyde polymer coating, the longer the time it took to elute an effective amount of DTPMP. In addition, Figure 13 shows that when a phenol formaldehyde resin having a relatively low viscosity is used to prepare the polymer coating, the proppant coated according to the two-step process (Batch 1) elutes an effective amount of DTPMP over a longer period of time compared to the proppant coated according to the one-step process (Batch 5). Finally, FIG. 13 shows that for the three proppant batches injected with 5 wt. % DTPMP and coated with either 2 wt. % or 4 wt. % phenol formaldehyde according to the two-step process (i.e., Proppant Batches 1-3), the effective amount of DTPMP eluted over a longer period of time compared to the proppant injected with 5 wt. % DTPMP and coated with 2 wt. % polyurethane according to the two-step process.

Example 2

Three 1000 pound production batches of 20/40 CARBO UltraLite, hereinafter referred to as "Batches 7-9," were impregnated with the DTPMP solution described above in Example 1 and then coated according to the following procedure with a phenol formaldehyde standard reactive resin available from Plastics Engineering Company under the trade designation Plenco 14941. Compared to the other phenolic resins discussed above, Plenco 14941 resin has a relatively moderate viscosity of approximately 1850 cps at 150°C.

Each of Lots 7-9 was injected with 183.6 lbs of DTPMP solution, resulting in DTPMP comprising 7 wt% of the injected proppant. The proppant from Lots 7-9 was then coated with a phenol formaldehyde standard reactive medium viscosity polymer resin (Plenco 14941) in a two-step process. After the two-step process, Lot 7 proppant contained 0.5 wt% of the polymer coating, Lot 8 proppant contained 1.0 wt% of the polymer coating, and Lot 9 proppant contained 2.0 wt% of the polymer coating.

After the proppant particles were injected with 7% DTPMP, each batch was coated with a different amount of the same semi-permeable, substantially non-degradable polymer. Batch 7 proppant was heated to 415°F. When the proppant reached the desired temperature, 6.6 pounds of phenol formaldehyde standard reactive medium viscosity polymer resin (Plenco 14941) was added to the proppant, melted, and spread over the proppant for approximately 45 seconds. Next, 2.8 pounds of a 30% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol formaldehyde resin and allowed to mix for 25 seconds. Finally, 0.5 pounds of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade name "Chembetaine ^™ CAS" was added and allowed to mix.

Batch 8 proppant was heated to 415°F. When the proppant reached the desired temperature, 12.3 pounds of phenol formaldehyde standard reactive medium viscosity polymer resin (Plenco 14941) was added to the proppant, allowed to melt, and spread over the proppant for approximately 45 seconds. Next, 5.2 pounds of a 30% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol formaldehyde resin and allowed to mix for 25 seconds. Finally, 0.5 pounds of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade designation "Chembetaine ^™ CAS" was added and allowed to mix.

The Batch 9 proppant was heated to 415°F. When the proppant reached the desired temperature, 22.7 pounds of phenol formaldehyde standard reactive medium viscosity polymer resin (Plenco 14941) was added to the proppant, allowed to melt, and spread over the proppant for approximately 45 seconds. Next, 9.7 pounds of a 30% hexamethylenetetramine solution commercially available from The Chemical Company was added to crosslink and cure the phenol formaldehyde resin and allowed to mix for 25 seconds. Finally, 0.5 pounds of a 50-60% cocamidopropyl hydroxysultaine surfactant commercially available from The Lubrizol Corporation under the trade designation "Chembetaine ^™ CAS" was added and allowed to mix.

Proppant batches 7-9 of Example 2 were compared to proppant batches 1, 2, and 6 of Example 1, as indicated in Table 3 below.

Table 3 - Example 2 batch

Batch number Injection/polymer coating Batch 1 (from Example 1) 5 wt% DTPMP, 2 wt% phenol formaldehyde standard reactivity low viscosity (Plenco 14870) Batch 2 (from Example 1) 5% DTPMP, 2% phenol formaldehyde (Plenco 14750) Batch 6 (from Example 1) 9 wt% DTPMP, uncoated Batch 7 7 wt% DTPMP, 0.5 wt% phenol formaldehyde Standard reactivity Medium viscosity (Plenco 14941) Batch 8 7 wt% DTPMP, 1.0 wt% phenol formaldehyde Standard reactivity Medium viscosity (Plenco 14941) Batch 9 7 wt% DTPMP, 2.0 wt% phenol formaldehyde Standard reactivity Medium viscosity (Plenco 14941)

Proppant batches 7-9 were then placed in a seawater eluent for 1 hour. The seawater eluent was prepared according to the ASTM D1141-98 (2013) procedure and had the composition shown in Table 2 above. After 1 hour, the amount of DTPMP present in the eluent was determined. The eluent was subsequently tested for the presence of DTPMP at 2, 3, 4, 5, 6, 7, 8, 25, 29, 33, and 48.5 hours. For proppant batch 9, the eluent was additionally tested for the presence of DTPMP at 53.5 and 55.5 hours. For batches 1, 2, and 6, the eluent was subsequently tested for the presence of DTPMP as described in Example 1 above.

The amount of DTPMP detected in the eluates of batches 7-9, expressed in ppm, was plotted as a function of time along with data from batches 1, 2, and 6 of Example 1 to produce the elution profiles shown in FIG14. In FIG14, a line has been drawn at 6 ppm, which represents the minimum effective concentration of DTPMP as a corrosion inhibitor and scale inhibitor. By plotting the amount of DTPMP detected in the eluates of proppant batches 1-2 and 6-9 versus time and comparing these results to the 6 ppm line, it is possible to determine the length of time it takes for a particular proppant batch to elute an effective amount of DTPMP.

Figure 14 clearly shows that proppant batches 7-9, which included a semipermeable, substantially non-degradable polymer coating, eluted an effective amount of DTPMP over a longer period of time than proppant batch 6, which did not include a semipermeable, substantially non-degradable polymer coating. Furthermore, Figure 14 clearly shows that for the three proppant batches injected with 7 wt % DTPMP and coated with 0.5 wt %, 1.0 wt %, and 2.0 wt % phenol formaldehyde according to the two-step process (i.e., proppant batches 7-9), the higher the weight percentage of the phenol formaldehyde polymer coating, the longer the time to elute an effective amount of DTPMP.

Example 3

A 500-gram batch of 20/40 CARBO UltraLite, hereinafter referred to as "Batch 10," was injected with 64.2 grams of the DTPMP solution described in Example 1 above, such that the DTPMP comprised 5 weight percent of the injected proppant, and then coated with polylactic acid, such that the final product contained a 2 weight percent polylactic acid coating in a two-step thermal process. Polylactic acid is a degradable polymer coating commercially available from Danimer under the trade designation "92938." 500 grams of 20/40 CARBO UltraLite was heated in an oven set at 250°C for 1 hour. 64.2 grams of the DTPMP solution was added to the heated proppant and allowed to mix for 3 minutes. The injected proppant was then heated to 193°C, and 51.0 grams of polylactic acid polymer resin was added to the batch and allowed to mix for approximately 10 minutes.

A 500 gram batch of 20/40 CARBOUltraLite, hereinafter referred to as "Batch 11," was impregnated with DTPMP and coated with a polyurethane coating according to the procedure discussed above, except that 3.6 grams of Ancarez ISO HDiT polyisocyanate polymer resin was used to provide a 2 wt% polyurethane coating.

Proppant Lots 10 and 11 were compared to Proppant Lots 1 and 6 from Example 1 as indicated in Table 4 below.

Table 4 - Example 3 batch

Proppant batches 1, 6, 10, and 11 were then placed in a seawater eluent for one hour. The seawater eluent was prepared according to the ASTM D1141-98 (2013) procedure and had the composition shown in Table 2 above. After one hour, the amount of DTPMP present in the eluent was determined. The eluent was subsequently tested for the presence of DTPMP at 2, 3, 4, 5, 21, 22, 23, 24, 26, 27, 28, 29, 44, 47, 49, 53, 70, and 74 hours. For proppant batch 1, the eluent was additionally tested for the presence of DTPMP at 93, 98, 165, 173, 189.5, 197.5, and 218 hours.

The amount of DTPMP detected in the eluate in ppm was plotted as a function of time to obtain the elution profile shown in FIG15. In FIG15, a line has been drawn at 6 ppm, which represents the minimum effective concentration of DTPMP as a corrosion inhibitor and scale inhibitor. By plotting the amount of DTPMP detected in the eluate of proppant batches 1, 6, 10, and 11 versus time and comparing these results to the 6 ppm line, the length of time it took for a particular proppant batch to elute an effective amount of DTPMP can be determined.

FIG15 clearly shows that proppant batches 10 and 11 injected with 5 wt% DTPMP and coated with 2 wt% phenol formaldehyde according to the two-step process eluted an effective amount of DTPMP over a longer period of time than proppant batches 10 and 11 injected with 5 wt% DTPMP and coated with 2.0 wt% polylactic acid and polyurethane, respectively. Furthermore, FIG15 shows that proppant batches 10 and 11, each containing a degradable and semipermeable substantially nondegradable polymer coating, eluted an effective amount of DTPMP over a longer period of time than proppant batch 6, which did not contain a semipermeable substantially nondegradable polymer coating. FIG15 also shows that substantially similar results were obtained for proppant batch 10 injected with 5 wt% DTPMP and coated with 2.0 wt% polylactic acid (a degradable polymer) and proppant batch 11 injected with 5 wt% DTPMP and coated with 2.0 wt% polyurethane (a semipermeable substantially nondegradable polymer).

The above results indicate that injected proppant particles coated with semipermeable, substantially nondegradable polymers such as phenol formaldehyde and polyurethane release effective amounts of chemical treatment agents such as DTPMP for a longer period of time than typical degradable coatings or proppants without any coating.

Example 4

The following examples were conducted using exemplary materials to determine the elution rate of DTPMP from coated porous proppants injected with DTPMP and further coated with various amounts of a degradable coating, and compared to porous proppants injected with DTPMP but not containing a degradable coating.

Three 500 gram batches of 20/40 CARBO UltraLite, an ultra-lightweight ceramic proppant having an ASG of 2.71 and a porosity of 20-25%, commercially available from CARBO Ceramics, Inc., were each injected with a 41% solids solution of diethylenetriaminepenta(methylenephosphonic acid) ("DTPMP"), commercially available from Riteks, Inc., and then coated with a semi-permeable, substantially non-degradable polymer in a two-step process described below.

Each batch of proppant was heated in an oven set at 482°F (250°C) for approximately 1 hour. The heated batches of proppant were then removed from the oven and cooled until they reached a temperature between 430-440°F as monitored by a thermocouple. Once the proppant batches reached the desired temperature, 64.2 grams of DTPMP solution was added to each batch and allowed to infuse into the proppant particles for approximately 3 minutes, such that the DTPMP comprised 5% by weight of the injected proppant. After the proppant particles were infused with DTPMP, each batch was coated with a semi-permeable, substantially non-degradable polymer.

Each batch of proppant containing 5 wt% DTPMP was then coated with a phenol-formaldehyde, highly reactive, high-viscosity polymer resin, available from Plastics Engineering Company under the trade name Plenco 14750, according to the following procedure. Each batch was placed in a heated mixing bowl and monitored with a thermocouple until the proppant reached a temperature between 410 and 420°F. When the proppant reached the desired temperature, 8.08 grams of the phenol-formaldehyde resin was added to the proppant, melted, and spread over the proppant for approximately 45 seconds. Next, 2.63 grams of a 40% solution made from pure hexamethylenetetramine powder, commercially available from Bossco Industries, Inc., was added to crosslink and cure the phenol-formaldehyde resin and allowed to mix for 1 minute and 25 seconds. After the phenol-formaldehyde coating procedure, each batch of proppant contained a 2 wt% polymer coating.

Only the proppants from batches 1 and 2 containing 2 wt% of the polymer coating were simultaneously coated with a degradable coating and water quenched by applying the hot batches to a degradable shell solution comprising approximately 50% polyolefin and approximately 50% water, available from Danimer Scientific under the trade designation "MHG-00254," at a temperature between 250° F. and 300° F. Batch 1 was subjected to the MHG-00254 solution for 2 minutes, and batch 2 was subjected to the MHG-00254 solution for 2 minutes, until batch 1 had a 2 wt% degradable shell and batch 2 had a 4 wt% degradable shell.

Finally, 1.2 grams of 50-60% cocamidopropyl hydroxysultaine surfactant, available from The Lubrizol Corporation under the trade designation "Chembetaine™ CAS," was added to each batch and allowed to mix for 1 minute.

Table 5 below shows the three batches prepared in Example 4.

Table 5 - Example 4 batch

Proppant batches 1-6 were then placed in a seawater eluent for 1 hour. The seawater eluent was prepared according to the ASTM D1141-98 (2013) procedure and had the composition shown in Table 2 above.

After 1 hour, the amount of DTPMP present in the eluate was determined (parts per million, ppm). For batches 1 and 2, the eluate was subsequently tested for the presence of DTPMP at 20 minutes, 40 minutes, and 60 minutes, respectively. For proppant batch 3, the eluate was additionally tested for the presence of DTPMP at 10 minutes, 30 minutes, and 50 minutes.

The amount of DTPMP detected in the eluate in ppm was plotted as a function of time to obtain the elution profile shown in Figure 16. Figure 16 clearly shows that proppant batches 1 and 2, which contain a degradable shell, reduce the initial elution rate of DTPMP compared to proppant batch 3, which does not contain a degradable shell. Figure 16 also surprisingly shows that doubling the amount of degradable coating (from 2 wt% to 4 wt%) reduces DTPMP elution by a factor of three (from 19% to 54%, respectively).

Exemplary embodiments of the present disclosure may also relate to any one or more of the following paragraphs:

1. A ceramic proppant composition for hydraulic fracturing, the composition comprising: non-porous microparticles having permeability and conductivity; porous ceramic microparticles, wherein the porous ceramic microparticles are injected with a chemical treatment; wherein the permeability of the composition is at least equal to the permeability of the non-porous microparticles; and wherein the conductivity of the composition is at least about 70% of the conductivity of the non-porous microparticles.

2. The composition according to paragraph 1, wherein at least one of the non-porous microparticles and the porous microparticles has an apparent specific gravity of less than 3.1 g/cm ³ .

3. The composition according to paragraph 1, wherein at least one of the non-porous microparticles and the porous ceramic microparticles has an apparent specific gravity of from 3.1 to 3.4 g/cm ³ .

4. The composition according to paragraph 1, wherein at least one of the non-porous microparticles and the porous ceramic microparticles has an apparent specific gravity greater than 3.4 g/cm ³ .

5. A composition according to any of paragraphs 1 to 4, wherein the conductivity of the composition is at least equal to the conductivity of the non-porous microparticles.

6. The composition of any of paragraphs 1 to 5, wherein the non-porous microparticles are selected from the group consisting of lightweight ceramic non-porous proppants, medium density ceramic non-porous proppants, and high density ceramic porous proppants.

7. The composition according to any one of paragraphs 1 to 6, wherein the porous microparticles are selected from the group consisting of: lightweight ceramic porous proppants, medium density ceramic porous proppants and high density ceramic porous proppants.

8. The composition of any of paragraphs 1 to 7, wherein the chemical treatment agent is selected from the group consisting of scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants, and combinations thereof.

9. A composition according to paragraph 8, wherein the tracer material comprises a chemical tracer.

10. The composition according to paragraph 9, wherein the chemical tracer comprises a biomarker.

11. The composition according to paragraph 10, wherein the biomarker comprises DNA.

12. The composition according to paragraph 8, wherein the tracer material comprises at least one of metallic and non-metallic nanoparticles.

13. The composition according to paragraph 8, wherein the nanoparticle dispersion alters the wettability of the ceramic proppant composition in a hydraulic fracturing environment.

14. The composition according to paragraph 8, wherein the surfactant alters the wettability of the ceramic proppant composition in a hydraulic fracturing environment.

15. The composition according to any of paragraphs 1 to 14, wherein the porous ceramic composition further comprises a degradable coating or a non-degradable coating, and wherein the degradable coating degrades within the cracks.

16. The composition according to paragraph 15, wherein the degradable coating is selected from the group consisting of polylactic acid, a water-soluble polymer, and a cross-linkable water-soluble polymer.

17. The composition of paragraph 15 or 16, wherein the chemical treatment agent is selected from the group consisting of scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants, and combinations thereof.

18. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into the subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; and injecting a fluid comprising a proppant composition, wherein the proppant composition comprises non-porous microparticles and porous ceramic microparticles injected with a chemical treatment; wherein the non-porous microparticles are permeable and conductive; wherein the permeability of the proppant composition is at least equal to the permeability of the non-porous microparticles; and wherein the conductivity of the composition is at least about 70% of the conductivity of the non-porous microparticles.

19. The method of paragraph 18, wherein the non-porous microparticles are selected from the group consisting of lightweight ceramic non-porous proppants, medium-density ceramic non-porous proppants, and high-density ceramic porous proppants, and wherein the porous microparticles are selected from the group consisting of lightweight ceramic porous proppants, medium-density ceramic non-porous proppants, and high-density ceramic porous proppants.

20. The method of paragraph 18 or 19, wherein the chemical treatment agent is selected from the group consisting of tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants and other oilfield treatment chemicals.

21. The method according to paragraph 20, wherein the tracer comprises a chemical tracer.

22. The method according to paragraph 21, wherein the chemical tracer comprises a biomarker.

23. The method of paragraph 22, wherein the chemical tracer comprises DNA.

24. The method according to paragraph 20, wherein the tracer is selected from the group consisting of metallic nanoparticles and non-metallic nanoparticles.

25. The method according to paragraph 20, wherein the nanoparticle dispersion alters the wettability of the ceramic proppant composition in a hydraulic fracturing environment.

26. The method according to paragraph 20, wherein the surfactant alters the wettability of the ceramic proppant composition in a hydraulic fracturing environment.

27. The method of any of paragraphs 18 to 26, wherein the porous ceramic microparticles further comprise a degradable coating or a non-degradable coating, and wherein the degradable coating degrades within the cracks.

28. The method according to paragraph 27, wherein the degradable coating is selected from the group consisting of polylactic acid, a water-soluble polymer, and a cross-linkable water-soluble polymer.

29. The method of paragraph 27 or 28, wherein the chemical treatment agent is selected from the group consisting of: scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants, and combinations thereof.

30. The method of any of paragraphs 18 to 29, wherein the conductivity of the composition is at least equal to the conductivity of the non-porous microparticles.

31. A method for diagnostically evaluating hydraulic fracturing stimulation of a subterranean formation, comprising: injecting a hydraulic fluid into at least one stage of a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation, the subterranean formation comprising one or more formation fluids, and the hydraulic fluid comprising a proppant composition, the proppant composition comprising porous microparticles injected with a biomarker; wherein the biomarker is continuously separated from the proppant composition over an extended period of time; wherein the biomarker is returned to the surface with the formation fluid; and wherein the biomarker is recovered and identified.

32. The method according to paragraph 31, wherein the biomarker is DNA.

33. The method according to paragraph 31 or 32, wherein the porous microparticle is a porous ceramic proppant.

34. The method according to any of paragraphs 31 to 33, wherein the biomarker is encapsulated.

35. The method of paragraph 32, wherein the DNA comprises a specific sequence of nitrogenous bases that exhibits thermal stability properties compatible with the thermal properties of the subterranean formation.

36. The method of paragraph 35, wherein the DNA exhibits thermal stability at temperatures up to about 186 to 221°F, up to about 222 to 250°F, or up to about 269 to about 292°F.

37. The method of any of paragraphs 31 to 36, wherein hydraulic fracturing stimulation of the subterranean formation is performed in multiple stages, and the proppant composition injected into each such stage comprises porous microparticles injected with a unique biomarker, such that no two stages of the subterranean formation are injected with a proppant composition comprising porous microparticles injected with the same biomarker.

38. The method of paragraph 36 further comprises injecting a proppant composition comprising porous microparticles infused with uniquely distinguishable biomarkers into different segments of a stage of the subterranean formation such that no two segments of the stage of the subterranean formation are injected with a proppant composition comprising porous microparticles infused with the same biomarker.

39. The method of any of paragraphs 31 to 38, wherein the biomarker is separated from the proppant composition by at least one of leaching, eluting, diffusing, seeping, draining, desorbing, dissolving, effluent, seepage, and leakage from the proppant composition.

40. The method of any of paragraphs 31 to 39, wherein the formation fluid has an aqueous phase, and wherein the biomarker separates into the aqueous phase of the formation fluid when separated from the porous microparticles.

41. The method of any of paragraphs 31 to 40, wherein the formation fluid has a hydrocarbon phase, and wherein the biomarker separates into the hydrocarbon phase of the formation fluid when separated from the porous microparticles.

42. The method according to any of paragraphs 31 to 41, wherein the biomarker is separated from the proppant composition for a period of up to about one year after placement of the proppant composition into the subterranean formation.

43. The method according to any of paragraphs 31 to 42, wherein the biomarker is separated from the proppant composition for a period of up to about five years after placing the proppant composition into the subterranean formation.

44. The method according to any of paragraphs 31 to 43, wherein the biomarker is separated from the proppant composition for a period of up to about ten years after placement of the proppant composition into the subterranean formation.

45. The method of any of paragraphs 31 to 44, wherein a plurality of uniquely distinguishable biomarkers from different phases of the subterranean formation are simultaneously recovered and identified.

46. The method of any of paragraphs 31 to 45, further comprising: evaluating the relative hydrocarbon or water volume contributions of one or more stages of the subsurface formation based on the relative amounts of uniquely distinguishable biomarkers recovered from the one or more stages of the subsurface formation.

47. A method according to any of paragraphs 31 to 46, further comprising: evaluating the relative hydrocarbon or water volume contribution from each segment of the stage of the underground formation based on the amount of uniquely distinguishable biomarkers recovered from each segment of the stage of the underground formation.

48. The method according to paragraph 34, wherein the biomarker is encapsulated by a polymer.

49. The method according to paragraph 48, wherein the polymer is at least one member selected from the group consisting of: a high melting point acrylate-, methacrylate- or styrene-based polymer, a block copolymer of polylactic acid and polyglycolic acid, polyglycolic acid, polylactide, polylactic acid, gelatin, a water-soluble polymer, a cross-linkable water-soluble polymer, a lipid, a gelatin and silica.

50. The method of any of paragraphs 31 to 49, wherein the proppant composition further comprises non-porous microparticles, and wherein the porous microparticles of the proppant composition have an internal interconnected porosity of about 5 to about 15% or about 15 to about 35%.

51. According to any of paragraphs 31 to 50, wherein the porous microparticles of the proppant composition comprise a permeable coating.

52. A proppant composition for hydraulic fracturing, the composition comprising: porous microparticles infused with a biomarker; wherein the porous microparticles have internally interconnected porosity; and wherein after a period of time, the biomarker separates from the porous microparticles.

53. The proppant composition according to paragraph 52, wherein the porous microparticles are selected from the group consisting of lightweight porous ceramic proppants, medium density porous ceramic proppants, and high density porous ceramic proppants.

54. The proppant composition according to paragraph 52 or 53, wherein the biomarker is DNA.

55. The proppant composition according to paragraph 54, wherein the DNA comprises a specific sequence of nitrogenous bases that exhibits thermal stability properties compatible with the thermal properties of the subterranean formation.

56. The proppant composition according to paragraph 54 or 55, wherein the DNA exhibits thermal stability at temperatures up to about 186 to 221°F, up to about 222 to 250°F, or up to about 269 to about 292°F.

57. The proppant composition according to any of paragraphs 52 to 56, wherein the biomarker is polymer encapsulated.

58. The proppant composition of paragraph 57, wherein the polymer is at least one member selected from the group consisting of high melting point acrylate-, methacrylate-, or styrene-based polymers, polylactic-polyglycolic acid block copolymers, polyglycolic acid, polylactide, polylactic acid, gelatin, water-soluble polymers, cross-linkable water-soluble polymers, lipids, gelatin, and silica.

59. The proppant composition of any of paragraphs 52 to 58, wherein the proppant composition further comprises non-porous microparticles, and wherein the porous microparticles have an internal interconnected porosity of about 5-15% or about 15-35%.

60. The proppant composition according to any of paragraphs 52 to 59, wherein the proppant composition is injected into a hydraulically created fracture in a subterranean formation.

61. The proppant composition according to paragraph 60, wherein the biomarker is separated from the porous microparticles for a period of up to about one year after injecting the proppant composition into a hydraulically created fracture in a subterranean formation.

62. The proppant composition according to paragraph 60, wherein the biomarker is separated from the porous microparticles for a period of up to about five years after injecting the proppant composition into a hydraulically created fracture in a subterranean formation.

63. The proppant composition according to paragraph 60, wherein the biomarker is separated from the porous microparticles for a period of up to about ten years after injection of the proppant composition into a hydraulically created fracture in a subterranean formation.

64. A ceramic proppant composition for hydraulic fracturing, the composition comprising: porous ceramic microparticles; a chemical treatment injected into the porous ceramic microparticles; and a semi-permeable, substantially non-degradable polymer coating.

65. The composition according to paragraph 64, wherein the porous microparticles are selected from the group consisting of lightweight ceramic porous proppants, medium density ceramic porous proppants, and high density ceramic porous proppants.

66. The composition of paragraph 64 or 65, wherein the chemical treatment agent is selected from the group consisting of scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

67. The composition according to paragraph 66, wherein the tracer material comprises a chemical tracer selected from the group consisting of a dye, a fluorescent material, a metallic nanoparticle, a non-metallic nanoparticle and a biomarker.

68. The composition of paragraph 67, wherein the chemical tracer comprises DNA.

69. The composition of any of paragraphs 64 to 68, further comprising non-porous ceramic particles.

70. The composition according to paragraph 67, wherein the tracer material comprises at least one of metallic and non-metallic nanoparticles.

71. The composition of any of paragraphs 64 to 70, wherein the semipermeable substantially non-degradable polymer coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

72. A ceramic proppant composition for hydraulic fracturing, the composition comprising: porous ceramic microparticles; and a chemical treatment agent injected into the porous ceramic microparticles, wherein the chemical treatment agent is injected into the porous ceramic microparticles without the use of a solvent.

73. The composition of paragraph 72 further comprising non-porous ceramic microparticles, and wherein the porous ceramic microparticles are selected from the group consisting of lightweight ceramic porous proppants, medium density ceramic porous proppants, and high density ceramic porous proppants.

74. The composition of paragraph 72 or 73, wherein the chemical treatment agent is selected from the group consisting of scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

75. The composition according to paragraph 74, wherein the chemical treatment comprises at least one of a paraffin inhibitor and a wax inhibitor.

76. The composition according to paragraph 75, wherein at least one of the paraffin inhibitor and the wax inhibitor comprises ethylene vinyl acetate copolymer.

77. The composition of any of paragraphs 72 to 75, wherein the porous ceramic microparticles further comprise a semipermeable substantially non-degradable polymer coating.

78. The composition according to paragraph 77, wherein the semipermeable substantially non-degradable polymer coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

79. The composition according to paragraph 73, wherein the porous ceramic microparticles further comprise a degradable polymer coating selected from the group consisting of polylactic acid, cellulose esters, methylcellulose, and combinations thereof.

80. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; injecting porous ceramic particles with a chemical treatment; coating the injected porous ceramic particles with a semi-permeable, substantially non-degradable polymer; and injecting a fluid containing the coated injected porous ceramic particles into the subterranean formation, wherein the injected chemical treatment is released into the subterranean formation for a period of time.

81. The method of paragraph 80, wherein the fluid further comprises non-porous ceramic particles, and wherein the porous ceramic particles are selected from the group consisting of lightweight ceramic porous proppants, medium density ceramic non-porous proppants, and high density ceramic porous proppants.

82. The method of paragraph 80 or 81, wherein the chemical treatment agent is selected from the group consisting of tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposition inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

83. The method according to paragraph 82, wherein the tracer material comprises a chemical tracer selected from the group consisting of a dye, a fluorescent material, a metallic nanoparticle, a non-metallic nanoparticle, and a biomarker.

84. The method of paragraph 83, wherein the chemical tracer comprises DNA.

85. The method of paragraph 83, wherein the tracer material comprises at least one of metallic and non-metallic nanoparticles.

86. The method of any of paragraphs 80 to 85, wherein the porous ceramic particles are impregnated with the chemical treatment agent by at least one of vacuum infusion, thermal infusion, capillary action, ribbon mixing at room temperature or elevated temperature, microwave mixing, and blender mixing.

87. The method of any of paragraphs 80 to 86, wherein the semipermeable substantially non-degradable polymer coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

88. The method of any of paragraphs 80 to 87, wherein the chemical treatment is released into the subsurface formation by at least one of leaching, elution, diffusion, seepage, drainage, desorption, dissolution, effusion, seepage, and leakage from the porous ceramic particles.

89. The method of paragraph 88, wherein the chemical treatment is released from the porous ceramic particles for a period of up to about ten years after the porous ceramic particles are placed into the hydraulically created fracture.

90. The method of paragraph 89, wherein the chemical treatment is released from the porous ceramic particles for a period of up to about five years after placing the porous ceramic particles into the hydraulically created fracture.

91. The method of paragraph 90, wherein the chemical treatment is released from the porous ceramic particles for a period of up to about one year after the porous ceramic particles are placed in the hydraulically created fracture.

92. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; injecting porous ceramic particles with a chemical treatment without the use of a solvent; and injecting a fluid containing the injected porous ceramic particles into the fractures in the subterranean formation, wherein the injected chemical treatment is released into the subterranean formation for a period of time.

93. The method of paragraph 92, wherein the chemical treatment agent is selected from the group consisting of: scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposition inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

94. The method of paragraph 93, wherein the chemical treatment agent is at least one of a paraffin inhibitor and a wax inhibitor.

95. The method according to paragraph 94, wherein at least one of the paraffin inhibitor and the wax inhibitor comprises ethylene vinyl acetate copolymer.

96. The method of paragraph 95, wherein the infused porous ceramic microparticles are coated with a semipermeable, substantially nondegradable polymer selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

97. The method of paragraph 96, wherein the chemical treatment is released into the subsurface formation by at least one of leaching, elution, diffusion, seepage, drainage, desorption, dissolution, effluent, seepage, and leakage from the injected porous ceramic particles.

98. The method of paragraph 97, wherein the chemical treatment is released from the injected porous ceramic particles for a period of up to about ten years after placement of the porous ceramic particles into the hydraulically created fracture.

99. The method of paragraph 98, wherein the chemical treatment is released from the injected porous ceramic particles for a period of up to about five years after placing the porous ceramic particles into the hydraulically created fracture.

100. The method of paragraph 99, wherein the chemical treatment is released from the injected porous ceramic particles for up to about one year after placement of the porous ceramic particles into the hydraulically created fracture.

101. A ceramic proppant composition for hydraulic fracturing, the composition comprising: porous ceramic microparticles; a water-soluble chemical treatment agent injected into the porous ceramic microparticles; and a coating comprising a hydrocarbon-soluble chemical treatment agent.

102. The composition of paragraph 101 further comprising non-porous ceramic microparticles, and wherein the porous microparticles are selected from the group consisting of lightweight ceramic porous proppants, medium density ceramic porous proppants, and high density ceramic porous proppants.

103. The composition according to paragraph 102, wherein the water-soluble chemical treatment comprises a scale inhibitor and the hydrocarbon-soluble chemical treatment comprises a paraffin inhibitor.

104. A proppant composition for hydraulic fracturing, the composition comprising: a plurality of microparticles; and at least one microparticle of the plurality of microparticles comprising a chemical treatment agent, the at least one microparticle having a long-term permeability of at least about 10 Darcy at 7,500 psi as measured according to ISO 13503-5; wherein when positioned within a fracture in a subterranean formation, after a period of time, the at least one chemical treatment agent separates from the at least one microparticle.

105. The composition according to paragraph 104, wherein the plurality of microparticles comprises non-porous microparticles and porous microparticles.

106. The composition of paragraph 105, wherein the plurality of microparticles have a permeability at least equal to the permeability of the non-porous microparticles.

107. The composition according to paragraph 106, wherein the conductivity of the plurality of microparticles is at least about 70% of the conductivity of the non-porous microparticles.

108. The composition according to paragraph 105, wherein the porous microparticles comprise a chemical treatment agent.

109. The composition according to paragraph 105, wherein the non-porous microparticles comprise a chemical treatment agent.

110. The composition according to paragraph 105, wherein at least one of the non-porous microparticles and the porous microparticles has an apparent specific gravity of less than 3.1 g/ ^cm3 .

111. The composition according to paragraph 105, wherein at least one of the non-porous microparticles and the porous microparticles has an apparent specific gravity of from 3.1 to 3.4 g/ ^cm3 .

112. The composition according to paragraph 105, wherein at least one of the non-porous microparticles and the porous microparticles has an apparent specific gravity greater than 3.4 g/ ^cm3 .

113. The composition of paragraph 105, wherein the non-porous microparticles are selected from the group consisting of lightweight ceramic non-porous proppants, medium density ceramic non-porous proppants, and high density porous ceramic proppants.

114. The composition of paragraph 105, wherein the porous microparticles are selected from the group consisting of lightweight porous ceramic proppants, medium density porous ceramic proppants, and high density porous ceramic proppants.

115. The composition of any of paragraphs 104 to 114, wherein the chemical treatment agent is selected from the group consisting of scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants, and combinations thereof.

116. The composition of paragraph 115, wherein the tracer material comprises a chemical tracer.

117. The composition according to paragraph 116, wherein the chemical tracer comprises a biomarker.

118. The composition according to paragraph 117, wherein the biomarker comprises DNA.

119. The composition according to paragraph 115, wherein the tracer material comprises at least one of metallic and non-metallic nanoparticles.

120. The composition according to paragraph 115, wherein the nanoparticle dispersion alters the wettability of the proppant composition in a hydraulic fracturing environment.

121. The composition according to paragraph 115, wherein the surfactant alters the wettability of the proppant composition in a hydraulic fracturing environment.

122. The composition according to any of paragraphs 105 to 121, wherein the proppant composition further comprises a degradable coating or a non-degradable coating, and wherein the degradable coating degrades within the fracture.

123. The composition according to paragraph 122, wherein the degradable coating is selected from the group consisting of polylactic acid, a water-soluble polymer and a cross-linkable water-soluble polymer and any combination thereof.

124. The composition according to paragraph 122, wherein the degradable coating is a self-polishing coating.

125. The composition according to paragraph 122, wherein the non-degradable coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester and epoxy resin, and any combination thereof.

126. The composition of any of paragraphs 122 to 125, wherein the chemical treatment agent is contained in the non-degradable coating or the degradable coating.

127. The composition of any of paragraphs 122 to 126, wherein the chemical treatment agent is disposed between at least one microparticle and the non-degradable coating or the degradable coating.

128. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into the subterranean formation at a rate and pressure sufficient to open a fracture in the subterranean formation; and injecting a fluid comprising a proppant composition into the fracture, the proppant composition comprising: a plurality of microparticles; and at least one microparticle of the plurality of microparticles comprising a chemical treatment agent, and the at least one microparticle having a long-term permeability of at least about 10 Darcy as measured at 7,500 psi in accordance with ISO 13503-5; and eluting the chemical treatment agent from the at least one microparticle located within the fracture for a period of time.

129. The method of paragraph 128, wherein the chemical treatment agent is selected from the group consisting of: tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, nanoparticle dispersions, surfactants and other oilfield treatment chemicals.

130. The method of paragraph 129, wherein the tracer comprises a chemical tracer.

131. The method according to paragraph 130, wherein the chemical tracer comprises a biomarker.

132. The method of paragraph 130, wherein the chemical tracer comprises DNA.

133. The method of any of paragraphs 129 to 132, wherein the nanoparticle dispersion alters the wettability of the proppant composition in a hydraulic fracturing environment.

134. The method of any of paragraphs 129 to 133, wherein the surfactant alters the wettability of the proppant composition in a hydraulic fracturing environment.

135. The method of any of paragraphs 129 to 134, wherein the proppant composition further comprises a degradable coating or a non-degradable coating, and wherein the degradable coating degrades within the fracture.

136. The method of paragraph 135, wherein the degradable coating is selected from the group consisting of polylactic acid, a water-soluble polymer, and a cross-linkable water-soluble polymer.

137. The composition according to paragraph 135, wherein the degradable coating is a self-polishing coating.

138. The composition according to paragraph 135, wherein the non-degradable coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester and epoxy resin, and any combination thereof.

139. The composition of any of paragraphs 135 to 138, wherein the chemical treatment agent is contained in the non-degradable coating or the degradable coating.

140. The composition of any of paragraphs 135 to 139, wherein the chemical treatment agent is disposed between at least one microparticle and the non-degradable coating or the degradable coating.

141. The method of any of paragraphs 128 to 140, wherein the chemical treatment agent elutes from the at least one microparticle at a rate of at least about 0.1 ppm/(gram*day) for at least 6 months.

142. A method for diagnostically evaluating hydraulic fracturing stimulation of a subterranean formation, comprising: injecting a hydraulic fluid into at least one stage of a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation, wherein the subterranean formation comprises one or more formation fluids and a hydraulic fluid comprising a proppant composition, wherein the proppant composition comprises at least one microparticle comprising a biomarker; wherein the biomarker is continuously separated from the at least one microparticle for a period of time; wherein the biomarker is returned to the surface with the formation fluid; and wherein the biomarker is recovered and identified.

143. The method according to paragraph 142, wherein the biomarker is DNA.

144. The method of paragraph 142 or 143, wherein the at least one microparticle is selected from the group consisting of sand, non-porous ceramic proppants and porous ceramic proppants and any mixtures thereof.

145. The method according to any of paragraphs 142 to 144, wherein the biomarker is encapsulated.

146. The method of paragraph 143, wherein the DNA comprises a specific sequence of nitrogenous bases that exhibits thermal stability properties compatible with the thermal properties of the subterranean formation.

147. The method of paragraph 146, wherein the DNA exhibits thermal stability at temperatures up to about 186 to 221°F, up to about 222 to 250°F, or up to about 269 to about 292°F.

148. The method of any of paragraphs 142 to 147, wherein hydraulic fracturing stimulation of the subterranean formation is performed in multiple stages, and the proppant composition injected into each such stage comprises two or more microparticles, each microparticle of the two or more microparticles comprising a unique biomarker, such that no two stages of the subterranean formation are injected with proppant compositions comprising microparticles comprising the same biomarker.

149. The method of paragraph 148 further comprises injecting a proppant composition comprising microparticles containing uniquely distinguishable biomarkers into different segments of a stage of a subterranean formation such that no two segments of a stage of a subterranean formation are injected with a proppant composition comprising microparticles containing the same biomarker.

150. The method of any of paragraphs 142 to 149, wherein the biomarker is separated from the proppant composition by at least one of leaching, eluting, diffusing, seeping, draining, desorbing, dissolving, effluent, seepage, and leakage from the proppant composition.

151. The method of any of paragraphs 142 to 150, wherein the formation fluid has an aqueous phase, and wherein the biomarker separates into the aqueous phase of the formation fluid when separated from the at least one particulate.

152. The method of any of paragraphs 142 to 151, wherein the formation fluid has a hydrocarbon phase, and wherein the biomarker separates into the hydrocarbon phase of the formation fluid when separated from the at least one particulate.

153. The method of any of paragraphs 142 to 152, wherein the biomarker is separated from the proppant composition for up to about one year after placement of the proppant composition into the subterranean formation.

154. The method of any of paragraphs 142 to 153, wherein the biomarker is separated from the proppant composition for a period of up to about five years after placement of the proppant composition into the subterranean formation.

155. The method of any of paragraphs 142 to 154, wherein the biomarker is separated from the proppant composition for a period of up to about ten years after placement of the proppant composition into the subterranean formation.

156. The method of any of paragraphs 142 to 155, wherein a plurality of uniquely distinguishable biomarkers from different phases of the subterranean formation are simultaneously recovered and identified.

157. The method of any of paragraphs 142 to 156, further comprising: evaluating the relative hydrocarbon or water volume contributions of one or more stages of the subsurface formation based on the relative amounts of uniquely distinguishable biomarkers recovered from the one or more stages of the subsurface formation.

158. The method of any of paragraphs 142 to 157, further comprising: evaluating the relative hydrocarbon or water volume contribution from each segment of the stage of the subsurface formation based on the amount of uniquely distinguishable biomarker recovered from each segment of the stage of the subsurface formation.

159. The method according to any of paragraphs 142 to 158, wherein the biomarker is encapsulated by a polymer.

160. The method of paragraph 159, wherein the polymer is at least one member selected from the group consisting of: a high melting point acrylate-, methacrylate- or styrene-based polymer, a block copolymer of polylactic acid and polyglycolic acid, polyglycolic acid, polylactide, polylactic acid, gelatin, a water-soluble polymer, a cross-linkable water-soluble polymer, a lipid, a gelatin and silica.

161. The method of any of paragraphs 142 to 160, wherein the proppant composition comprises porous microparticles and non-porous microparticles, and wherein the porous microparticles of the proppant composition have an internally connected porosity of about 5 to about 15% or about 15 to about 35%.

162. The method according to paragraph 161, wherein the porous microparticles of the proppant composition comprise a biomarker and comprise a permeable coating.

163. A proppant composition for hydraulic fracturing, the composition comprising: microparticles containing a biomarker; wherein the microparticles have a long-term permeability of at least 10 Darcy as measured at 7,500 psi according to ISO 13503-5; and wherein after a period of time, the biomarker separates from the microparticles.

164. The proppant composition of paragraph 163, wherein the microparticles are selected from the group consisting of sand, non-porous ceramic proppant, lightweight porous ceramic proppant, medium density porous ceramic proppant, and high density porous ceramic proppant.

165. The proppant composition according to paragraph 163 or 164, wherein the biomarker is DNA.

166. The proppant composition according to paragraph 165, wherein the DNA comprises a specific sequence of nitrogenous bases that exhibits thermal stability properties compatible with the thermal properties of the subterranean formation.

167. The proppant composition according to paragraph 166, wherein the DNA exhibits thermal stability at temperatures up to about 186 to 221°F, up to about 222 to 250°F, or up to about 269 to about 292°F.

168. The proppant composition according to any of paragraphs 163 to 167, wherein the biomarker is polymer encapsulated.

169. The proppant composition of paragraph 168, wherein the polymer is at least one member selected from the group consisting of: a high melting point acrylate-, methacrylate-, or styrene-based polymer, a block copolymer of polylactic acid and polyglycolic acid, polyglycolic acid, polylactide, polylactic acid, gelatin, a water-soluble polymer, a cross-linkable water-soluble polymer, a lipid, a gelatin, and silica.

170. The proppant composition of any of paragraphs 163 to 169, wherein the proppant composition comprises porous particulates and non-porous particulates, and wherein the porous particulates have an internal interconnected porosity of about 5-15% or about 15-35%.

171. The proppant composition according to any of paragraphs 163 to 170, wherein the proppant composition is injected into a hydraulically created fracture in a subterranean formation.

172. The proppant composition according to paragraph 171, wherein the biomarker is separated from the microparticles for a period of up to about one year after injection of the proppant composition into a hydraulically created fracture in a subterranean formation.

173. The proppant composition according to paragraph 171, wherein the biomarker is separated from the microparticles for a period of up to about five years after injecting the proppant composition into a hydraulically created fracture in a subterranean formation.

174. The proppant composition according to paragraph 171, wherein the biomarker is separated from the microparticles for a period of up to about ten years after injection of the proppant composition into a hydraulically created fracture in a subterranean formation.

175. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into the subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; coating one or more proppant particles with a chemical treatment agent to provide one or more proppant particles containing the chemical treatment agent; coating the proppant particles containing the chemical treatment agent with a semi-permeable, substantially non-degradable polymer to provide one or more coated proppant particles; and injecting a fluid containing the coated proppant particles into the subterranean formation, wherein the chemical treatment agent is released into the subterranean formation for a period of time.

176. The method of paragraph 175, further comprising: injecting the one or more proppant particles with a chemical treatment prior to coating the one or more proppant particles with the chemical treatment.

177. The method of paragraph 175 or 176, wherein the one or more proppant particles are selected from the group consisting of sand, non-porous ceramic particles, lightweight porous ceramic proppants, medium density porous ceramic proppants, and high density porous ceramic proppants.

178. The method of any of paragraphs 175 to 177, wherein the chemical treatment agent is selected from the group consisting of tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

179. The method of paragraph 178, wherein the tracer material comprises a chemical tracer selected from the group consisting of a dye, a fluorescent material, a metallic nanoparticle, a non-metallic nanoparticle, and a biomarker.

180. The method of paragraph 179, wherein the chemical tracer comprises DNA.

181. The method of paragraph 176, wherein the porous ceramic microparticles are impregnated with the chemical treatment agent by at least one of vacuum infusion, thermal infusion, capillary action, ribbon mixing at room temperature or elevated temperature, microwave mixing, and blender mixing.

182. The method of any of paragraphs 175 to 181, wherein the semipermeable substantially non-degradable polymer coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

183. The method of any of paragraphs 175 to 182, wherein the chemical treatment is released into the subsurface formation by at least one of leaching, elution, diffusion, seepage, drainage, desorption, dissolution, effusion, seepage, and leakage from the coated proppant particles.

184. The method of paragraph 183, wherein the chemical treatment is released from the coated proppant particulates for a period of up to about ten years after placement of the coated proppant particulates into the hydraulically created fracture.

185. The method of paragraph 184, wherein the chemical treatment is released from the coated proppant particulates for a period of up to about five years after placing the coated proppant particulates into the hydraulically created fracture.

186. The method of paragraph 185, wherein the chemical treatment is released from the coated proppant particulates for a period of up to about one year after placement of the coated proppant particulates into the hydraulically created fracture.

187. A method for hydraulically fracturing a subterranean formation, comprising: injecting a hydraulic fluid into a subterranean formation at a rate and pressure sufficient to open fractures in the subterranean formation; injecting one or more proppant particles with a first chemical treatment to provide one or more injected proppant particles; coating the injected proppant particles with a second chemical treatment to provide one or more proppant particles comprising the second chemical treatment; coating the proppant particles comprising the second chemical treatment with a semi-permeable, substantially non-degradable polymer to provide one or more coated proppant particles; and injecting a fluid comprising the coated proppant particles into the subterranean formation, wherein the first chemical treatment and the second chemical treatment are released into the subterranean formation for a period of time.

188. The method of paragraph 187, wherein the one or more proppant particles are selected from the group consisting of sand, non-porous ceramic particles, lightweight porous ceramic proppants, medium density porous ceramic proppants, and high density porous ceramic proppants.

189. The method of paragraph 187 or 188, wherein the first chemical treatment agent is selected from the group consisting of tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, defoamers, breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

190. The method of any of paragraphs 187 to 189, wherein the second chemical treatment agent is selected from the group consisting of tracers, scale inhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphaltene inhibitors, organic deposit inhibitors, biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate inhibitors, carboxylate inhibitors, demulsifiers, and combinations thereof.

191. The method of any of paragraphs 187 to 190, wherein the one or more proppant particles are infused with the first chemical treatment by at least one of vacuum infusion, thermal infusion, capillary action, strip mixing at room temperature or elevated temperature, microwave mixing, and blender mixing.

192. The method of any of paragraphs 187 to 191, wherein the semipermeable substantially non-degradable polymer coating is selected from the group consisting of phenol formaldehyde, polyurethane, cellulose ester, polyamide, vinyl ester, epoxy resin, and combinations thereof.

While the invention has been described in terms of several exemplary embodiments, those skilled in the art will recognize that the invention can be practiced with modification within the spirit and scope of the appended claims.

The present disclosure has been described with respect to several exemplary embodiments. Improvements or modifications that would be apparent to one of ordinary skill in the art merely after reading this disclosure are considered to be within the spirit and scope of this application. It should be understood that several modifications, variations, and substitutions are intended to be encompassed by the foregoing disclosure, and in some cases certain features of the present invention will be employed without other corresponding features. Accordingly, it is appropriate that the appended claims be interpreted broadly in a manner consistent with the scope of the present invention.

Claims (13)

1. A proppant composition for hydraulic fracturing, said composition comprising: Multiple particles; Non-degradable coating; and At least one of the plurality of particles comprises a degradable shell and a chemical treatment agent encapsulating at least a portion of the non-degradable coating, and the at least one particle has a long-term permeability of at least 10D as measured at 7,500 psi according to ISO 13503-5. The at least one of the particles is a porous particle; and At least one of the chemical treatment agents separates from the at least one particle after being located inside a crack in the underground rock stratum for a period of time. 2. The composition of claim 1, further comprising a plurality of uncoated microparticles. 3. The composition of claim 1, wherein the chemical treatment agent is selected from the group consisting of: scale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfide scavenging materials, corrosion inhibitors, wax inhibitors, asphaltenes inhibitors, organic deposition inhibitors, biocides, demulsifiers, defoamers, degummers, salt inhibitors, oxygen scavengers, iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes, biological agents, flocculants, naphthenate/ester inhibitors, carboxylate/ester inhibitors, nanoparticle dispersions, surfactants, and combinations thereof. 4. The composition of claim 3, wherein the scale inhibitor comprises diethylenetriaminepenta (methylenephosphonic acid). 5. The composition of claim 3, wherein the scale inhibitor comprises one or more potassium salts of maleic acid copolymers. 6. The composition of claim 1, wherein the non-degradable coating is a phenolic varnish resin. 7. The composition of claim 1, wherein the chemical treatment agent is mixed with the non-degradable coating. 8. The composition of claim 1, wherein the chemical treatment agent is mixed with the biodegradable shell. 9. The composition of claim 1, wherein the degradable shell is selected from the group consisting of: polyvinyl alcohol, polylactic acid, polyamide, polyethylene, polypropylene, polystyrene, water-soluble polymers and crosslinkable water-soluble polymers and any combination thereof. 10. The composition of claim 1, wherein the porous microparticles have an internal interconnected porosity of 5% to 75%. 11. The composition of claim 1, wherein the plurality of particles have a bulk density of 1.0 g/cc to 2.1 g/cc. 12. The composition of claim 9, wherein the water-soluble polymer comprises sodium carboxymethyl cellulose, gum arabic, carrageenan, ebony gum, xanthan gum, carboxymethyl hydroxypropyl guar gum, cationic guar gum, dimethylammonium hydrolyzed collagen, poly(ethylene oxide), poly(propylene oxide), poly(ethylene oxide)-poly(propylene oxide) block copolymer, poly(1,4-oxobutylene) glycol, or poly(alkylene glycol diacrylate). 13. Methods for hydraulically fracturing underground rock formations, including: Hydraulic fluid was injected into the underground rock formation at a rate and pressure sufficient to open cracks in the rock; and The liquid comprising the proppant composition of claim 1 is injected into the crack.