Coke proppant particles coated with antifriction agent, method of making such particles and hydraulic fracturing method utilizing such particles

Abstract

The antifriction agent coated coke proppant particle comprises an antifriction agent coating deposited on and / or over an outer surface of the coke proppant particle, wherein the antifriction agent coating has a thickness of 1 [mu] m to 50 [mu] m. Fracturing fluids include, among other potential components, a carrying fluid and such antifriction agent coated coke proppant particles. A method of making such antifriction agent coated coke proppant particles comprises depositing an antifriction agent on and / or over an outer surface of the coke proppant particles wherein the weight percentage of the antifriction agent used during the deposition process is from 0.1% to 2.3% by weight, based on the total weight of the antifriction agent and the coke proppant particles.

Description

Technical Field

[0001] This disclosure generally relates to the fields of hydraulic fracturing operations and the fracturing fluids and proppant particles used therein. More specifically, this disclosure relates to coke proppant particles coated with a friction reducer, methods for preparing such friction reducer-coated coke proppant particles, and hydraulic fracturing methods using such friction reducer-coated coke proppant particles. Background Technology

[0002] This section aims to introduce various aspects of the areas that may relate to the aspects and implementations of this disclosure. Such discussion is intended to provide a framework for a better understanding of specific aspects and implementations of this disclosure. Therefore, it should be understood that this section should be read for this purpose and not necessarily as an affirmation of the prior art.

[0003] Wellbores can be drilled into underground formations to facilitate the extraction (or production) of resources such as hydrocarbon fluids, coal, minerals, water, etc. In many cases, it is necessary to stimulate the underground formation in some way to facilitate resource extraction. Stimulation can include any operation performed on the matrix of the underground formation to improve the conductivity of fluids passing through it, including hydraulic fracturing, which is commonly used for unconventional reservoirs.

[0004] Hydraulic fracturing typically involves pumping a large volume of fracturing fluid under high hydraulic pressure into a subsurface formation (e.g., a low-permeability formation) to promote the formation of one or more fractures within the formation matrix and create highly conductive flow paths. During fracturing operations, primary fractures extend from the wellbore, and in some cases, secondary fractures extend from the primary fractures. These fractures can be vertical, horizontal, or a combination of directions forming tortuous paths.

[0005] Proppant particles are typically contained within fracturing fluid. Once the fracturing fluid has been pumped into the subsurface formation, it is expected that these proppant particles will be transported into the fractures and settle therein. During pressure release, the proppant particles retained in the fractures keep the fractures open by preventing fracture collapse, thereby facilitating the flow of desired resources from the fracturing formation through the propped fractures into the wellbore, thanks to their improved permeability and conductivity compared to unconventional formation matrices. The performance of the proppant can significantly influence the expected recovery of resources.

[0006] Due to its shape, mechanical properties, and ease of availability with limited processing, sand has traditionally been used as a proppant in hydraulic fracturing to produce hydrocarbon fluids from unconventional formations. Various other types of proppants have been proposed and can be used to replace sand, such as ceramics and polymers. Nevertheless, all these existing proppants have one or more drawbacks, such as high cost and limited hydrocarbon recovery. Therefore, there is a real industrial need for high-performance proppants, hydraulic fracturing fluids, and hydraulic fracturing methods. This disclosure addresses this need, as well as other requirements. Summary of the Invention Invention Overview

[0007] One aspect of this disclosure provides coke proppant particles coated with a friction-reducing agent. The coke proppant particles may include a friction-reducing agent coating deposited on and / or above the outer surface of the coke proppant particles, wherein the friction-reducing agent coating may be present in thicknesses from 1 μm to 50 μm.

[0008] Another aspect of this disclosure provides a fracturing fluid. The fracturing fluid may include (among other potential components) a carrier fluid and coke proppant particles coated with a friction modifier.

[0009] Another aspect of this disclosure provides a method for preparing coke proppant particles coated with a friction-reducing agent. The method may include depositing a friction-reducing agent on and / or above the outer surface of the coke proppant particles to obtain friction-reducing agent-coated coke proppant particles; wherein the weight percentage of the friction-reducing agent used during the deposition process may be from 0.1% to 2.3% by weight, based on the total weight of the friction-reducing agent and the coke proppant particles, and wherein the thickness of the resulting friction-reducing agent coating may be from 1 micrometer (μm) to 50 μm.

[0010] Another aspect of this disclosure provides a method for preparing fracturing fluid. The method may include: providing coke proppant particles coated with a friction modifier and mixing the friction modifier-coated coke proppant particles with a carrier fluid and optional additives.

[0011] Another aspect of this disclosure provides a method for hydraulic fracturing underground formations. The method may include introducing the aforementioned fracturing fluid into the underground formation.

[0012] These and other features and attributes of the disclosed aspects and embodiments of this disclosure, as well as their advantageous applications and / or uses, will become apparent from the following detailed description. Attached Figure Description

[0013] To assist those skilled in the art in creating and using the subject matter described herein, please refer to the accompanying drawings, in which:

[0014] Figure 1 This is a graph comparing the apparent density of petroleum coke particles in a petroleum coke sample with the apparent density of sand particles in a sand sample.

[0015] Figure 2 It is a graph showing the cumulative density function of fluid coke particles in two fluid coke samples;

[0016] Figure 3 It is a diagram showing the particle size distribution of fluid coke particles in two fluid coke samples;

[0017] Figure 4 It is a bar graph showing the terminal settling velocities of sand particles in a 40 / 70 mesh sand sample, sand particles in a 100 mesh sand sample, and fluid coke particles in a 100 mesh fluid coke sample in recirculated water.

[0018] Figure 5 This is a bar graph comparing the crushing strength of sand particles in a regional sand sample with the crushing strength of fluid coke particles in a fluid coke sample.

[0019] Figure 6 It is a graph showing the settling velocity as a function of particle size for several different mesh sizes of sand and petroleum coke;

[0020] Figure 7 It is a diagram showing the particle size distribution of four unsieved fluid coke samples;

[0021] Figure 8 It is a bar graph comparing the crushing strength of different types of proppant;

[0022] Figure 9 This is a process flow diagram of an exemplary method for preparing coke proppant particles with a friction-reducing agent coating; and

[0023] Figure 10 This is a process flow diagram of an exemplary hydraulic fracturing method using coke proppant particles coated with a friction-reducing agent.

[0024] It should be noted that the accompanying drawings are merely examples of this disclosure and are not intended to limit the scope of this disclosure. Furthermore, the drawings are generally not drawn to scale but are provided for convenience and clarity to illustrate various aspects of this disclosure. Invention Details

[0025] In the following detailed description, specific examples of this disclosure are described in conjunction with preferred aspects and embodiments. However, the extent to which the following description is specific to one or more aspects or embodiments of this disclosure is intended for illustrative purposes only and to simply provide an explanation of such aspects(one or more) or embodiments(one or more). Therefore, this disclosure is not limited to the specific aspects and embodiments described below, but includes all alternatives, modifications, and equivalents that fall within the true spirit and scope of the appended claims.

[0026] First, for ease of reference, certain terms used in this application and their meanings in the context are explained. Where a term used herein is not defined below, it should be given the broadest definition that has been given to the term by a person skilled in the art, as reflected in at least one printed publication or published patent. Furthermore, this disclosure is not limited to the use of the terms shown below, as all equivalents, synonyms, new developments, and terms or processes serving the same or similar purposes are considered to be within the scope of these claims.

[0027] As used herein, when applied to any of the embodiments described herein, the singular forms "a," "an," and "the" mean one or more. The use of "a," "an," and / or "the" does not limit the meaning to a single feature unless such limitation is specifically stated.

[0028] The terms "about" and "approximately" refer to a relative amount of material or property sufficient to provide the intended effect. The degree of precision deviation allowed in some cases may depend on the specific context, such as ±1%, ±5%, ±10%, ±15%, etc. Those skilled in the art will understand that these terms are intended to allow for the description of certain features described and claimed, without limiting the scope of these features to the precise numerical ranges provided. Therefore, these terms should be interpreted as indicating that non-substantial or insignificant modifications or alterations to the described subject matter are considered within the scope of this disclosure.

[0029] The term "and / or" placed between the first entity and the second entity refers to one of the following: (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed using "and / or" shall be interpreted in the same manner, i.e., "one or more" of the entities thus combined. Other entities may optionally exist in addition to those specifically identified by the "and / or" clause, whether related to or unrelated to those specifically identified. Thus, as a non-limiting example, when used in conjunction with open-ended language such as "including," a reference to "A and / or B" may, in one embodiment, refer only to A (optionally including entities other than B); in another embodiment, refer only to B (optionally including entities other than A); and in yet another embodiment, refer to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, etc.

[0030] As used in this document, the term "any" refers to one, some, or all of the specified entities or groups of entities, regardless of quantity.

[0031] The term "apparent density" used in this article to refer to the density of proppant particles refers to the density of an individual particle itself, which can be expressed in grams per cubic centimeter (g / cm³). 3 The apparent density values ​​provided in this paper are based on the American Petroleum Institute Recommended Practice 19C (hereinafter referred to as "API RP-19C") standard, entitled "Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-packing Operations" (first edition May 2008, reaffirmed June 2016).

[0032] When used with reference to a list of one or more entities (or elements), the phrase "at least one" should be understood to mean at least one entity selected from any one or more entities in the entity list, but not necessarily including at least one of each entity specifically listed in the entity list, and does not exclude any combination of entities in the entity list. This definition also allows for the optional presence of entities other than those specifically identified in the entity list referred to by the phrase "at least one," whether related to or not related to those specifically identified entities. Thus, as a non-limiting example, "at least one of A and B" (or equivalently, "at least one of A or B", or equivalently, "at least one of A and / or B") in one embodiment may refer to at least one A, optionally including more than one A, with no B (and optionally including entities other than B); in another embodiment, it refers to at least one B, optionally including more than one B, with no A (and optionally including entities other than A); and in yet another embodiment, it refers to at least one (optionally including more than one) A and at least one (optionally including more than one) B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and / or" are open-ended expressions that are both connected and separate in operation. For example, each of the expressions "at least one of A, B, and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C," and "A, B, and / or C" can mean a single A, a single B, a single C, A and B together, A and C together, B and C together, A, B, and C together, and optionally any of the above combined with at least one other entity.

[0033] As used in this article, "blast furnace coke" refers to any coal-derived coke applicable to blast furnaces used in the manufacture of steel.

[0034] When used with reference to proppant particles, the term "crushing strength" as used herein refers to the uniaxial stress (compressive) load that the proppant particles can withstand before crushing (e.g., fracturing or cracking). The crushing strength values ​​in this disclosure are based on API RP-19C.

[0035] When reference is made to one or more components, features, structures, or methods according to this disclosure, the terms "example," "exemplary," and "implementation" as used herein are intended to express illustrative, non-unique instances of the described components, features, structures, or methods according to this disclosure. Therefore, the described components, features, structures, or methods are not intended to be limiting, essential, or exclusive / exhaustive; and other components, features, structures, or methods, including those that are structurally and / or functionally similar and / or equivalent, are also within the scope of this disclosure.

[0036] The term "flexicoke" as used in this article refers to flexicoke produced via FLEXICOKING. TM Solid concentrated carbon materials produced by process, FLEXICOKING TM The process is a thermal cracking process that utilizes fluidized solids and gasification to convert heavy, low-grade hydrocarbon feedstocks into lighter hydrocarbon products (e.g., upgraded, more valuable hydrocarbons). In short, FLEXICOKING TM The process integrates a cracking reactor, heater, and gasifier into a commonly used fluidized solids (coke) recirculation system. The feed stream (containing residue) is fed into the fluidized bed along with a stream of hot recirculated material to the reactor. The coke-containing stream is circulated from the reactor to the heating vessel, where it is heated. The hot coke stream is then fed from the heater to the gasifier, where it reacts with air and steam. The gasifier product gas (called coke gas), containing entrained coke particles, is returned to the heater and cooled by cold coke from the reactor to provide a portion of the reactor's heat requirements, typically in the range of about 496°C to about 538°C. The coke return stream from the gasifier to the heater provides the remaining heat requirements. The coke that meets the heat requirements is then recycled back to the reactor, and the feed stream is thermally cracked to produce a light hydrocarbon liquid, which is removed from the reactor and recovered using conventional fractionation equipment. The fluid coke is formed by the thermal cracking process and settles (deposits) onto the "seed" fluidized bed coke already present in the reactor. The resulting coke, at least partially gasified, is flexible coke. In some cases, coke from the thermal cracking process is deposited on top of the seed coke in what appears to be a ring-shaped pattern. In normal FLEXICOKING TM Flexible coke is continuously removed from the system during processing (e.g., from the reactor or after it flows to the heater via a separator) to ensure that the system maintains the coke particles within a fluidizable particle size range. Therefore, flexible coke is FLEXICOKING. TM Easily obtainable byproducts of the process.

[0037] Relatedly, the terms "wet flexible coke particles" and "dry flexible coke particles" refer to FLEXICOKING.TM Two byproducts of the process. These byproducts are collected as particles that were not recovered in the secondary cyclone separator of the heater. More specifically, the particles are first collected as dry, flexible coke fines in a tertiary cyclone separator, and then the smaller particles that passed through the tertiary cyclone separator are recovered as wet, flexible coke fines in a Venturi scrubber.

[0038] As used herein, the term "fluid coke" refers to the solid concentrated carbon material remaining from fluid coking. The term "fluid coking" refers to a thermal cracking process that utilizes fluidized solids to convert heavy, lower-grade hydrocarbon feedstocks into lighter products (e.g., upgraded hydrocarbons), producing fluid coke as a byproduct. Fluid coking methods and FLEXICOKING for producing flexible coke. TM The difference in the process is that the fluid coking method does not include a gasifier.

[0039] The term "crack" (or "hydraulic crack") refers to a fracture or rupture surface within underground strata, which can be caused by applied pressure or stress.

[0040] As used herein, the term "friction reducer" refers to any chemical agent, when added to fracturing fluid without the agent, that reduces turbulence in the resulting fluid and reduces the fluid resistance to contact with solid surfaces and movement along the flow path of the resulting fluid, compared to fracturing fluid without the agent. The term "high viscosity friction reducer (HVFR)" refers to a friction reducer that, when added to fracturing fluid without the agent, also results in a higher viscosity of the resulting fluid compared to fracturing fluid without the agent.

[0041] As used in this paper, "hydraulic conductivity" refers to the ability of fluids within subsurface formations to pass through proppant-containing fractures under various stress (or pressure) levels, based at least in part on the permeability of the proppant deposited within the hydraulic fractures. The hydraulic conductivity values ​​provided in this paper are based on the American Petroleum Institute Recommended Practice 19D (API RP-19D), entitled "Measuring the Long-Term Conductivity of Proppants" (first edition May 2008, reaffirmed May 2015).

[0042] As used in this article, "metallurgical coke" refers to a type of coal-derived coke produced by heating coal, which results in the fusion of fixed carbon into inherent ash and the removal of a large percentage of volatile matter. The resulting metallurgical coke particles comprise a range of different sizes, with the smallest particles being fine powder (sometimes referred to as "coke dust").

[0043] When used herein with reference to a type of particle, the term "particle size (one or more)" refers to the diameter (one or more) of such particles (one or more). When used herein with reference to a type or collection of particles, the term "particle size distribution" refers to the range of diameters of such particles, typically from smallest to largest. The terms "median particle size" and "D50," when used herein with respect to a type of particle or collection, are interchangeable in meaning to the median particle size of the type of particle or collection.

[0044] The term "petroleum coke" refers to the final carbon-rich solid material derived from petroleum refining. More specifically, petroleum coke is the carbonized product of high-boiling hydrocarbon fractions obtained as a result of petroleum processing operations. Petroleum coke is produced within a coking unit via a thermal cracking process, in which long-chain hydrocarbons are broken down into shorter-chain hydrocarbons. As described herein, there are at least three main types of petroleum coke: delayed coke, fluid coke, and flexible coke. Each type of petroleum coke is produced using different coking processes; however, the common goal of all three coking methods is to maximize the yield of distillate products within the refinery by removing the significant amount of carbon from the residue as petroleum coke.

[0045] The term "coal-derived coke" refers to any coke produced from coal through, for example, heat treatment.

[0046] As used herein, the terms "proppane" and "proppane particles" refer to solid materials capable of maintaining induced fracture opening during and after hydraulic fracturing. The term "proppane packing" refers to an assembly of proppane particles.

[0047] The terms "coke proppant" and "coke proppant particles" refer to proppants based on or derived from solid carbonaceous materials produced by processing carbonaceous materials (e.g., oils (e.g., crude oil, vacuum tubular stills, etc.), coal, and hydrocarbons) at high temperatures in an oxygen-deficient environment. The high temperatures can be at least 200, 250, 300, 350; 400, 450, 500, 600, 700, 800, 900, or even 1000°C. The carbonaceous material contains carbon and optional additional elements, including but not limited to hydrogen, sulfur, vanadium, iron, etc. Based on the total weight of all elements in the carbonaceous material, the carbonaceous material preferably contains carbon at a concentration of ≥50% by weight, for example, 50, 55, 60, 65, 70% by weight to 75, 80, 85, 90, 95% by weight to 96, 97, 98, 99% by weight or even 100% by weight. Based on the total weight of all elements in the carbonaceous material, the carbonaceous material preferably contains carbon and hydrogen elements at a total concentration of ≥55% by weight, for example, 55, 60, 65, 70% by weight to 75, 80, 85, 90, 95% by weight to 96, 97, 98, 99% by weight or even 100% by weight.

[0048] The term "non-coke proppant" refers to any proppant that does not contain coke proppant particles. Examples of non-coke proppants include sand, ceramic proppants, glass proppants, and polymer proppants.

[0049] The term "lightweight proppant (LWP)" refers to a proppant with an apparent density of approximately 1.2 g / cm³. 3 Approximately 2.2 g / cm³ 3 Within the range (e.g., approximately 1.2, 1.3, 1.4, 1.5, 1.6 g / cm³). 3 From approximately 1.7, 1.8, 1.9, 2.0, 2.1, 2.2 g / cm³ 3 The term "ultra-lightweight proppant (ULWP)" refers to a proppant with an apparent density of approximately 0.5 g / cm³. 3 Approximately 1.2 g / cm³ 3 Within the range (e.g., approximately 0.5, 0.6, 0.7, 0.8 g / cm³). 3 From approximately 0.9, 1.0, 1.1, and 1.2 g / cm³ 3 The proppant in coke may or may not be an LWP (low-density proppant). The term "non-LWP proppant" refers to a proppant with an apparent density higher than 2.2 g / cm³. 3 (For example, about 2.3, 2.4, 2.5 to about 2.6, 2.8, 3.0 to 3.2, 3.4, 3.5 g / cm³) 3 The proppant is a non-coke proppant. The non-coke proppant may or may not be a non-LWP.

[0050] The term "microproppant coke particles" refers to a collection of coke proppant particles having a particle size of up to 105 μm, but possibly ranging from 0.0001 μm to 105 μm (e.g., about 0.0001, 0.001, 0.01, 0.1 μm to 0.5, 1.0, 2.0, 5.0, 8.0, 10 μm, to 15, 20, 25, 30, 35, 40, 45 μm, to 50, 53, 55, 60, 63, 65 μm, to 74, 75, 80, 85, 88, 90, 95, 100, 105 μm).

[0051] The term "petroleum coke proppant particles" refers to a collection of coke proppant particles derived from petroleum coke source materials. The term "petroleum coke fine particles" refers to a collection of micro-proppant coke particles derived from petroleum source materials.

[0052] As used in this article, "pyrolytic coke" refers to a type of coke produced by the pyrolysis of hydrocarbons at temperatures higher than those used in the coking process for producing petroleum coke.

[0053] When used in reference to the quantity or amount of material or its specific characteristics, the term "substantially" refers to the amount sufficient to provide the effect that the material or characteristic is intended to provide. In some cases, the permissible degree of precision may depend on a specific range.

[0054] When used with reference to the components of a composition, the terms "substantially free of" or "substantially free of" can be used interchangeably to mean that the composition contains ≤10% by weight, ≤5% by weight, ≤3% by weight, ≤1% by weight, or 0% by weight of a component, based on the total weight of the composition.

[0055] As used herein, the term "heat-treated coke" refers to petroleum coke that has been heated to a temperature of approximately 400°C to 1200°C (e.g., approximately 400, 500, 600°C to 700, 800, 900°C to 1000, 1100, 1200°C) and held for a predetermined duration, said predetermined duration being in the range of approximately 1 minute to approximately 24 hours (e.g., 5, 10, 15, 20, 25, 30 minutes to 40, 50, 60 minutes, to 2, 3, 4, 5 hours, to 6, 7, 8, 9, 10 hours, to 11, 12, 13, 14, 15 hours, to 16, 17, 18, 19, 20 hours).

[0056] The term "wellbore" refers to a borehole drilled into underground formations. A borehole may include vertical, skew, highly skewed, and / or lateral sections. The term "wellbore" also includes downhole equipment associated with the borehole, such as casing, production piping, gas lift valves, and other underground equipment. Relatedly, the term "hydrocarbon well" (or simply "well") includes the wellbore in addition to the wellhead and other associated surface equipment.

[0057] Certain implementations and features are described herein using a set of upper and lower limits for numerical values. It goes without saying that a range from any lower to any upper limit should be considered unless otherwise stated. All values ​​are indicated as “about,” “approximately,” or “approximately,” and experimental errors and biases expected by those skilled in the art are taken into account.

[0058] During the drilling of a hydrocarbon well, a drill bit is used to form a wellbore within the subsurface formation. The drill bit can advance from the lower end of the drill string until it reaches a predetermined position underground. The drill string and drill bit can then be removed, and the wellbore can be lined with steel tubing, commonly referred to as a casing string. This creates an annulus between the casing string and the surrounding subsurface formation. Cementing operations can be performed to fill the annulus with a cement column. The combination of the casing string and cement reinforces the wellbore and isolates or impedes fluid flow and pressure transmission along the annulus.

[0059] Typically, several casing strings with gradually decreasing outer diameters are placed into the wellbore. The first casing string can be called the "surface casing string." The surface casing string is used to isolate and protect shallow, freshwater-bearing aquifers from contamination by any other wellbore fluids. Therefore, this casing string can be completely bonded back to the surface.

[0060] The process of drilling and then gluing progressively smaller casing strings below the surface casing string can be repeated several times until the hydrocarbon well reaches its total depth. The final casing string, called the "production casing string," can extend through the hydrocarbon-bearing section of the subsurface formation (called the "reservoir"). In some cases, the production casing string is a production liner, i.e., a casing string that is not tied back to the surface. The production casing string can also be glued into place. In some completions, the production casing string has expandable packers or plugs spaced apart over selected production sections. This creates compartments between the packers to isolate stages and specific stimulus treatments. In this case, the annulus can simply be filled with sand.

[0061] As part of the well completion process, sections of the wellbore (referred to as "stages") can be isolated via packers or plugs. The production casing string can then be perforated at one or more desired upholes in the plugs, meaning a perforation cluster is created by using a perforating gun to penetrate the production casing string and the cement column surrounding it. In operation, the perforating gun can form a perforation cluster by firing multiple closely spaced perforations (e.g., 12 to 18 perforations) at once within a 1-foot (0.3-meter) to 3-foot (3-meter) area; for example, each perforation might be approximately 0.3 inches (0.8 centimeters) to 0.5 inches (1.3 centimeters) in diameter. The perforating gun can then be moved uphole, for example, approximately 10 ft (3-meter) to 100 ft (30-meter), and a second perforating gun can be used to create a second perforation cluster. This process of forming perforation clusters can be repeated to create additional perforation clusters within each stage of the hydrocarbon well. The resulting perforated clusters can allow hydrocarbon fluids from the surrounding subsurface formation to flow into the hydrocarbon well. However, it should be noted that in some cases, a production casing string is provided instead of a sliding sleeve tubular or other type of casing string with pre-formed perforated clusters. In this case, the pre-formed perforations may initially close, but can be opened via various forms of action to control the flow of fluid through the perforations.

[0062] After the drilling process is complete, hydraulic fracturing can be performed at each stage of the wellbore to increase the productivity of the subsurface formation. Hydraulic fracturing involves injecting a certain volume of fracturing fluid from the perforated area into the surrounding subsurface formation at such high pressure and rate that the subsurface rock near the perforation fractures and opens, and the resulting hydraulic fractures extend outward into the subsurface formation in proportion to the volume of injected fluid. Ideally, individual hydraulic fractures emanate outward from each perforation cluster, forming a set of hydraulic fractures, often referred to as a "fracture network." Ideally, this fracture network comprises a series of parallel fracture planes, thereby generating as much fracturing of the subsurface rock as possible. Near the wellbore, the complex topology of hydraulic fractures may sometimes arise from the failure of perforations within each perforation cluster, but it is generally assumed that these hydraulic fractures eventually connect to form a single dominant fracture plane hydraulically connected to the wellbore. In operation, to generate hydraulic fractures, the injection pressure of the fracturing fluid must exceed the hydraulic pressure in the subsurface formation plus the strength of the rock, and often even exceeds the lithostatic pressure in the subsurface formation.

[0063] Hydraulic fracturing is most widely used to improve the productivity of "unconventional" (or "tight") subsurface formations, which are subsurface formations with very low permeability that are typically not economically productive without hydraulic fracturing. Examples of unconventional subsurface formations include tight sandstone formations, tight carbonate formations, shale gas formations, coalbed methane formations, and tight oil formations. During hydraulic fracturing of such subsurface formations, the pumping rate (or injection rate) of the fracturing fluid can be increased until it reaches a maximum pumping rate of approximately 20 barrels per minute (bbl / min) to approximately 150 bbl / min (e.g., 20, 60, 90 bbl / min to 120, 150 bbl / min). In operation, for example, approximately 5,000 to approximately 15,000 barrels (e.g., 5,000, 6,000, 7,000, 8,000 to 9,000, 10,000, 11,000, 12,000 to 13,000, 14,000, 15,000 barrels) of fracturing fluid can be injected into each stage of the hydrocarbon well.

[0064] During the operation, a small portion of the fracturing fluid (e.g., typically about 5% to about 10%) can be pumped into the wellbore during the pad phase of each stage of hydraulic fracturing. The pad phase is designed to initiate and allow hydraulic fractures to grow to a size and volume suitable for the injection of proppant, such as sand, crushed granite, ceramic beads, polymer microparticles, or other particulate materials (which are generally referred to herein as "non-coke proppant"). The remaining portion of the fracturing fluid can then be mixed with the proppant and pumped into the wellbore and through perforations into the stimulated reservoir volume (SRV). The proppant is used to keep the hydraulic fracture open after the hydraulic pressure is released. Ideally, the resulting hydraulic fractures grow radially from the wellbore into the subsurface formation by hundreds of feet. In the case of unconventional subsurface formations, the combination of hydraulic fractures and injected proppant significantly increases the flow capacity of the treated formation.

[0065] Hydraulic fracturing is a routine part of oil industry operations, such as when applied to individual subsurface formations. These subsurface formations can represent a total vertical thickness of hundreds of feet. Recently, hydrocarbon wells are being completed laterally through formations, where the lateral section typically extends at least 5,000 feet (1,524 meters). In this case, the hydrocarbon well can be referred to as an "extended lateral well," or in some cases, at least 15,000 feet (4,572 meters). In this case, the hydrocarbon well can be referred to as an "ultra-extended lateral well."

[0066] When there are multi-layered or very thick formations to be hydraulically fractured, or when completing extended or super-extended lateral wells, more sophisticated treatment techniques can be used to treat the entire target area. Therefore, the operating company can isolate the individual stages (as described above) to ensure that each independent stage is not only perforated but also fully fractured and treated. In this way, the operator can ensure that fracturing fluid is being injected through each perforated cluster and into each valuable stage to effectively increase the flow capacity at each desired depth and lateral location.

[0067] Treatment of a valuable stage can involve separating that stage from all other stages that have been treated. This may involve using a so-called diversion method, where the injected fracturing fluid is directed to a selected valuable stage while being diverted from the others. In many cases, fracture plugs are placed between stages and to prevent injected fluid from entering stages that have already been fractured and propped.

[0068] This hydraulic fracturing process can be repeated for each stage in a hydrocarbon well. In wells that include lateral sections, the first stage is typically located near the end (or "toe") of the lateral section, and the final stage is typically located near the beginning (or "heel") of the lateral section. For example, for an extended lateral well, there may be approximately 20 to approximately 50 independent stages. For example, for an ultra-extended lateral well, there may be more than 100 stages.

[0069] After the hydraulic fracturing process is completed, fracture plugs (and / or other diversion materials) can be drilled from the hydrocarbon well. The hydrocarbon well can then be made productive, meaning it can be used to recover hydrocarbon fluids from the subsurface formation. During operation, the pressure difference between the formation and the hydrocarbon well can be used to force hydrocarbon fluids through the hydraulic fractures within the formation and into the production casing string via corresponding perforated clusters. The hydrocarbon fluids then flow upwards along the hydrocarbon well to the surface.

[0070] In operation, the success of the hydraulic fracturing process has a direct impact on the final production performance of the hydrocarbon well. Specifically, corresponding to the perforation clusters within each stage of the hydrocarbon well, the number, size, flexibility, and location of the hydraulic fractures directly affect the amount of hydrocarbon fluid that can move and flow into the well. However, the success of the hydraulic fracturing process is limited by the ability of the fracturing fluid to penetrate deeply into the formation, thus allowing proppant to be deposited within the extended area of ​​the hydraulic fractures.

[0071] According to conventional techniques, sand is typically used as a proppant within fracturing fluids. However, sand tends to settle out of the fracturing fluid relatively quickly, limiting the effectiveness of hydraulic fracturing operations. To mitigate the low transport capacity of sand, high-viscosity carrier fluids are often used in conjunction with it, allowing the sand to remain suspended within the fracturing fluid for a longer period and thus penetrate deeper into the formation. Slickwater includes added friction modifiers, such as high molecular weight polyacrylamide, designed to reduce turbulent friction in the wellbore and through fractures, allowing for higher injection rates at lower pumping pressures. However, even with such friction modifiers, sand still tends to settle out of the fracturing fluid relatively quickly.

[0072] Therefore, this disclosure alleviates the aforementioned difficulties and also provides related advantages. Specifically, this disclosure provides coke proppant particles coated with a friction modifier, which exhibit improved transport and suspension properties compared to non-coke proppants such as sand. This disclosure also provides methods for preparing such friction modifier-coated coke proppant particles, and methods for utilizing such friction modifier-coated coke proppant particles during hydraulic fracturing operations.

[0073] More specifically, according to this disclosure, low-density coke proppant particles, which already possess improved transport properties compared to higher-density sand particles, are coated with a friction reducer that further enhances the transport properties of the coke proppant particles. Any suitable type (one or more) of friction reducer can be used alone or in any suitable combination. The friction reducer can form a continuous or discontinuous layer on or over the outer surface of a given substrate coke proppant particle, with or without any intermediate material layer, such as a binder, between the outer surface of the substrate coke proppant particle and the friction reducer coating. In various embodiments, the friction reducer coating comprises a polymer, such as a polymer (preferably a high molecular weight polymer) comprising structural units derived from acrylamide ("acrylamide structural units"), which may have a density close to that of the surrounding carrier fluid. The polymer can be a copolymer comprising structural units derived from acrylamide and additional structural units derived from acrylic acid ("acrylic acid structural units"). In a preferred embodiment, the polymer is a copolymer comprising structural units derived from acrylamide, acrylic acid, and structural units derived from acrylamido-2-methylpropanesulfonic acid ("AMPS structural units") ("AMPS structural units"). In another preferred embodiment, the polymer is a copolymer comprising structural units derived from acrylamide, acrylic acid, and a structural unit derived from trimethylaminoethyl acrylate ("TMAEA structural unit") ("TMAEA structural unit"). Exemplary acrylamide structural unit, acrylic acid structural unit, AMPS structural unit, and TMAEA structural unit are shown in the following formulas F-1, F-2, F-3, and F-4:

[0074] In various embodiments, a binder is applied as a first layer of the friction-reducing agent coating, directly contacting the outer surface of the coke proppant particles. Such binders may include, but are not limited to, one or more proteins, one or more amino acids, one or more sugars, and / or one or more polysaccharides. A friction-reducing agent layer may then be applied over the binder layer. In other embodiments, the binder may be mixed with the friction-reducing agent, and the mixture forms at least a portion of the coating on or over the outer surface of the coke proppant particles. In some embodiments, the binder layer may cover various portions of the outer surface of the coke proppant particles, and the friction-reducing agent may directly contact and cover certain portions of the outer surface of the coke proppant particles and part or all of the binder layer.

[0075] In some embodiments, the deposition (or coating) method includes spraying a liquid binder onto coke proppant particles to obtain pre-coated coke proppant particles, and subsequently mixing the pre-coated coke proppant particles with a friction-reducing agent in the form of a dry powder. In other embodiments, the deposition (or coating) method includes forming an aqueous solution or slurry containing the friction-reducing agent, mixing the coke proppant particles with the aqueous solution or slurry to obtain wet coke proppant particles, and subsequently drying the wet coke proppant particles. Furthermore, any other suitable type of deposition method may be used additionally or alternatively to apply a friction-reducing agent coating to the coke proppant particles.

[0076] Compared to uncoated coke proppant particles, the friction-modified coke proppant particles described herein offer several advantages in fracturing fluids. Although some of the friction-modified coating may be lost during transport of the proppant particles in fracturing fluids flowing through fractures in subsurface formations, some coating remains on the outer surface of the particles, resulting in lower friction between the friction-modified proppant particles and the fracture contact surface, as well as lower friction between proppant particles when they come into contact with each other. The thinner residual friction-modified coating adds almost no increase to the overall size of the coated coke proppant particles. Furthermore, the friction-modified coating reduces the overall apparent density of the coke proppant particles compared to those without a coating, and improves buoyancy compared to uncoated coke proppant particles in fracturing fluids. Due to lower friction, coke proppant particles coated with friction modifiers can travel farther than uncoated coke proppant particles, especially in tortuous secondary cracks, thus supporting longer cracks than methods using only uncoated coke proppant particles. Additionally, due to higher buoyancy, friction modifier-coated coke proppant particles can be carried by the carrier fluid for a longer period than uncoated coke proppant particles. Consequently, in cases where friction modifier-coated coke proppant particles are used, the amount of friction modifier added as an additive to the carrier fluid can be reduced (or the friction modifier can potentially be excluded as part of the carrier fluid and / or as an additive).

[0077] As further described herein, coke proppant particles may comprise any suitable type of coke, such as fluid coke, flexible coke, delayed coke, post-thermal treated coke, pyrolytic coke, and / or coal-derived coke (e.g., blast furnace coke particles and / or metallurgical coke particles). Furthermore, in some embodiments, at least a portion of such coke proppant particles is provided as microproppant coke particles.

[0078] Regarding petroleum coke, numerous properties and characteristics have been specifically discovered that mitigate difficulties commonly encountered during hydraulic fracturing of subsurface formations via hydrocarbon wells. First, the lower density of petroleum coke proppant particles compared to non-coke proppant particles allows for further transport within the wellbore and corresponding hydraulic fractures. Furthermore, it has been found that once the hydraulic fracturing operation is complete and the hydrocarbon well is put into production, petroleum coke proppant particles are less likely to flow back into the wellbore than non-coke proppant particles. Additionally, petroleum coke proppant particles have been found to be less likely to settle around any diversion materials within the wellbore than non-coke proppant particles, thus enabling the effective use of soluble, biodegradable, or self-destructible diversion materials (e.g., soluble plugs) within the wellbore. Moreover, it has been found that the use of petroleum coke proppant particles reduces the likelihood of cluster-level screening compared to the use of non-coke proppant particles. Each of these factors can advantageously reduce or eliminate the need for wellbore cleaning procedures.

[0079] Furthermore, the lower density of petroleum coke particles compared to non-coke proppant particles allows for further delivery within each stage and throughout the perforated cluster. As a result, fracturing fluid containing petroleum coke proppant particles will flow more uniformly and efficiently throughout the stage and into the perforated cluster, thus traveling more effectively to the tip of the formed hydraulic fracture (or at least near said tip).

[0080] As described in this article, petroleum coke possesses sufficient crushing strength to maintain supported fractures during hydraulic pressure removal and retain effective conductivity once wellbore production begins. Furthermore, the lower density of petroleum coke can reduce or eliminate the need for gelling fracturing fluids, thereby avoiding the costs associated with gelling. Additionally, the use of petroleum coke can potentially reduce the required injection pressure, decrease total water consumption, and avoid the need for frequent wellbore cleaning.

[0081] Effective proppant particles are typically associated with a variety of specific properties, including effective proppant particle delivery within the carrying fluid, maintaining sufficient strength of the propped fracture during hydraulic pressure removal, and effective conductivity once production begins in the wellbore. Regarding proppant particle delivery properties, the settling rate of proppant particles in the fracturing fluid at least partially determines their delivery capacity within the hydraulic fracture. The settling rate of proppant particles can be determined using equation (1). In equation (1), v is the deposition rate of the proppant particles, and ρ p -ρ f Proportional to the density difference between the proppant particles and the carrier fluid, where η is the viscosity of the carrier fluid, g is the gravitational constant, and σ is the viscosity of the carrier fluid.2 The ratio is proportional to the square of the proppant particle size. It goes without saying that proppant particles with lower apparent density and / or smaller particle size settle at a slower rate (and therefore have better transport) in the same carrier fluid compared to proppant particles with higher apparent density and / or larger particle size.

[0082] It has been found that coke particles, particularly petroleum coke particles, are particularly suitable as proppants during hydraulic fracturing operations, at least in part due to their lower apparent density compared to non-coke proppants (such as sand). This is because... Figure 1 As shown, Figure 1 This is a diagram (100) comparing the apparent density of petroleum coke particles in a petroleum coke sample with the apparent density of sand particles in a sand sample. Specifically, the apparent densities of the petroleum coke particles (i.e., in this embodiment, fluid coke particles) and sand particles were determined in the laboratory by measuring the mass of each type of particle settling in a brine of a given density. Based on these measurements, the apparent density of the petroleum coke particles ranges from approximately 1.3 g / cm³. 3 Approximately 1.7 g / cm³ 3 As shown in Figure 102, the apparent density of sand particles ranges from approximately 2.6 g / cm³. 3 Approximately 2.7 g / cm³ 3 As shown in Figure 104, the apparent density of petroleum coke is significantly lower than that of sand. Furthermore, the apparent density of a typical fluid carrier (e.g., water) is typically around 1.0 g / cm³. 3 Approximately 1.2 g / cm³ 3 Within the range, as shown in 106. Furthermore, Figure 2 This is a graph 200 showing the cumulative density function of fluid coke particles within two fluid coke samples. As shown, the density of the fluid coke particles ranges from approximately 1.4 g / cm³. 3 Approximately 1.65 g / cm³ 3 .

[0083] The transport properties of coke proppant particles are further enhanced by the varying size distribution of these particles. Specifically, while sand typically ranges in size from about 105 micrometers (μm) to about 850 μm (i.e., about 140 mesh to about 20 mesh), the particle size of petroleum coke can vary, making it approach the size of sand or even smaller. As an example, Figure 3This is a diagram 300 showing the particle size distribution of fluid coke particles within two fluid coke samples. As shown, the particle size of the two fluid coke samples is from about 100 μm to about 210 μm (i.e., from about 140 mesh to about 70 mesh), which covers the lower limit of the typical particle size range for different types of sand. Furthermore, as further described herein, petroleum coke particles with much smaller particle sizes can also be provided by utilizing microproppant coke particles, which may have a maximum size of 105 μm (140 mesh) or, in some cases, a maximum size of 88 μm (170 mesh), but may be in the range of about 0.0001 μm to 105 μm (e.g., about 0.0001, 0.001, 0.01, 0.1 μm to 0.5, 1.0, 2.0, 5.0, 8.0, 10 μm, to 15, 20, 25, 30, 35, 40, 45 μm, to 50, 53, 55, 60, 63, 65 μm, to 74, 75, 80, 85, 88, 90, 95, 100, 105 μm).

[0084] As stated above regarding equation (1), because petroleum coke particles have a lower apparent density and similar or smaller particle size compared to non-coke proppants (e.g., sand), they also exhibit a lower settling velocity within the carrying fluid, thus providing enhanced transport properties compared to sand. This is due to... Figure 4 illustrate, Figure 4 Bar graph 400 shows the terminal settling velocities of sand particles in a 40 / 70 mesh sand sample, a 100 mesh sand sample, and a 100 mesh fluid coke sample in recirculating water. Specifically, the average terminal settling velocity of the sand particles in the 40 / 70 mesh sand sample is 6.9 feet per minute (ft / min) (0.04 meters per second (m / s)), as shown at 402; the average terminal settling velocity of the sand particles in the 100 mesh sand sample is 3.5 ft / min (0.02 m / s), as shown at 404; and the average terminal settling velocity of the fluid coke particles in the 100 mesh fluid coke sample is 0.6 ft / min (0.003 m / s), as shown at 406. Therefore, fluid coke particles (which represent other types of petroleum coke particles) will be transported significantly further into the hydraulic fracture than sand particles. As a result, proppants formed at least partially from petroleum coke can support new and / or existing hydraulic fracture extensions that cannot be effectively supported by non-coke proppants, thereby increasing the overall SRV in the subsurface formation and leading to increased production performance of the corresponding hydrocarbon wells.

[0085] Furthermore, the crushing strength of proppant particles is a measure of their ability to withstand stress within hydraulically fractured surfaces, where effective proppant particles are capable of resisting sustained loads within the hydraulically fractured surfaces throughout the life of the corresponding wellbore, excluding the hydraulic conductivity of such fractures. Consequently, proppant particles with higher crushing strength are advantageous. According to API RP-19C standards, sufficient proppant particles should have a crushing strength indicating the production of less than 10% fine particles under stress of 5,000 psi. In this respect, the crushing strength of petroleum coke is advantageously comparable to that of sand. This is due to… Figure 5 illustrate, Figure 5 Bar graph 500 compares the crushing strength of sand particles in a regional sand sample, as shown in 502, with the crushing strength of fluid coke particles in a fluid coke sample, as shown in 504. This crushing strength is determined according to the API K crushing strength test by applying stress to the corresponding particles in increments of 1,000 psi until 10% fine particles are formed, where the crushing strength of the particles in each sample is the pressure (in psi) required to form 10% fine particles. Figure 5 As shown, the crushing strength of fluid coke (which represents other types of petroleum coke) is comparable to that of regional sand.

[0086] Regarding the abrasive properties of petroleum coke particles compared to sand particles, it should be noted that sand particles have a hardness of approximately 7 on a Mohs hardness tester, while petroleum coke particles have a hardness of less than approximately 6 on the Mohs hardness tester. Therefore, petroleum coke particles are expected to be less abrasive than sand particles and are unlikely to cause considerable wear within the production tubing, particularly including wear on perforated clusters.

[0087] Figure 6 This is a diagram 600 showing the settling velocity as a function of particle size for several different sieve sizes of sand and petroleum coke. Specifically, diagram 600 shows the settling velocities (in feet per minute (ft / min)) as a function of particle size (μm) for 40 / 70 mesh sand (as indicated by the first zone 602), 100 mesh sand (as indicated by the second zone 604), 40 / 70 mesh petroleum coke (as indicated by the third zone 606), and 100 mesh petroleum coke (as indicated by the fourth zone 608), where the settling velocity values ​​are based on a modified Stokes settling velocity. As shown in diagram 600, petroleum coke has a much lower settling rate (or velocity) than sand of comparable particle size. As a result, proppant particles formed from petroleum coke material will perform better than proppant particles formed from sand in terms of transport capacity within fractures created during hydraulic fracturing operations.

[0088] Regarding particle size, fluid coke pellets and flexible coke pellets are available in a wide range of sizes. This is... Figure 7 show, Figure 7 This is a graph 700 showing the particle size distribution of four unscreened fluid coke samples. Particle size was measured using laser particle size analysis (LPSA), a rapid and accurate optical screening technique for particle size analysis based on the principle of measuring the intensity of light scattered as a laser beam passes through a dispersed particulate sample. In this case, particles larger than 3 millimeters (mm) are removed before analysis. Figure 7 As shown, all four unscreened fluid coke samples exhibited a wide range of particle sizes upon exiting the reactor.

[0089] Typically, the crushing strength of petroleum coke particles has been shown to be between approximately 8,000 psi and 12,000 psi. This is partly due to... Figure 8 As shown, Figure 8 This is a bar graph 800 comparing the crushing strength of different types of proppant. Specifically, Figure 8 The crushing strengths of two fluid coke samples, flexible coke samples, delayed coke samples, and sand samples were compared. As shown in bar chart 800, the crushing strengths of fluid coke and flexible coke are close to those of sand.

[0090] Any suitable type (one or more) of petroleum coke and / or other types (one or more) of coke can be used for the coke proppant particles described herein. For example, coke proppant particles may include, but are not limited to, fluid coke particles, flexible coke particles, delayed coke particles, post-thermal treated coke particles, pyrolytic coke particles, coal-derived coke particles (e.g., blast furnace coke particles and / or metallurgical coke particles), microproppant coke particles, or any combination thereof.

[0091] In some embodiments, the coke proppant particles can have a range of different particle sizes, for example, any value from about 74 μm (200 mesh) to about 860 μm (20 mesh) (e.g., 74, 84, 89, 97, 104, 107 μm to 109, 117, 130, 140, 160, 180 μm, to 200, 230, 280, 425, 450, 520 μm, to 700, 860 μm). For some embodiments where improved proppant particle suspension is of primary concern, the coke proppant particles can have a median particle size of about 210 μm (70 mesh) or larger. Furthermore, because the friction modifier coating effectively reduces the settling velocity of coke proppant particles, coke proppant particles with larger particle sizes (e.g., 210 μm to 860 μm) can still be used with sufficient conveying capacity, enabling them to reach remote cracks that are inaccessible to coke proppant particles of the same size without the friction modifier coating.

[0092] In embodiments where flexible coke particles are used as at least a portion of the coke proppant particles described herein, such flexible coke particles are via FLEXICOKING TM Manufacturing process. In short, FLEXICOKING. TM The process integrates a cracking reactor, heater, and gasifier into a commonly used fluidized solids (coke) recirculation system. The feed stream (containing residue) is fed into the fluidized bed along with a stream of hot recirculated material to the reactor. The coke-containing stream is circulated from the reactor to the heating vessel, where it is heated. The hot coke stream is sent from the heater to the gasifier, where it reacts with air and steam. The gasifier product gas (called coke gas), containing entrained coke particles, is returned to the heater and cooled by cold coke from the reactor to provide a portion of the reactor's heat demand. The coke return stream from the gasifier to the heater provides the remaining heat demand. The coke that meets the heat demand is then recycled back to the reactor, and the feed stream is thermally cracked to produce a light hydrocarbon liquid, which is removed from the reactor and recovered using conventional fractionation equipment. Fluid coke is formed by the thermal cracking process and settles (deposits) onto the "seed" fluidized bed coke already present in the reactor. The resulting at least partially gasified coke is flexible coke. In some cases, coke from the thermal cracking process deposits on top of the seed coke in what appears to be a ring-shaped pattern. In normal FLEXICOKING TM Flexible coke is continuously removed from the system during processing (e.g., from the reactor or after it flows to the heater via a separator) to ensure that the system maintains the coke particles within a fluidizable particle size range. Therefore, flexible coke is FLEXICOKING. TM Easily obtainable byproducts of the process.

[0093] FLEXICOKING TM The gasification process results in a significant concentration of metals in the flex coke product and also allows for the operational desulfurization of sulfur from the flex coke. Gasification can be minimized or maximized to affect the sulfur content (minimization = lower sulfur content). Therefore, unlike coke formed by other methods, flex coke has a relatively high metal content and a relatively low sulfur content that can be controlled.

[0094] In various embodiments, flexible coke particles may have a carbon content ranging from about 85 wt% to about 99 wt% (e.g., from about 85, 87, 89, 91 wt% to 93, 95, 97, 99 wt%); a carbon to hydrogen weight ratio ranging from about 80:1 to about 95:1 (e.g., from about 80:1, 85:1 to 90:1, 95:1); and an impurity content (i.e., the weight percentage of all components other than carbon and hydrogen) ranging from about 1 wt% to about 10 wt% (e.g., from about 1, 2, 3, 4, 5 wt% to 6, 7, 8, 9, 10 wt%). Flexible coke also has a higher metal content than other cokes. Specifically, flexible coke particles may have a total vanadium and nickel content of about 3,000 parts per million (ppm) to about 45,000 ppm (e.g., about 3,000, 10,000, 15,000 ppm to 20,000, 25,000, 30,000 ppm, to 35,000, 40,000, 45,000 ppm). Furthermore, flexible coke particles may have a sulfur content of about 0 wt% to about 5 wt% (e.g., 0, 1, 2 wt% to 3, 4, 5 wt%) and a nitrogen content of about 0 wt% to about 3 wt% (e.g., 0, 0.5, 1.0, 1.5 wt% to 2.0, 2.5, 3.0 wt%).

[0095] The apparent density of flexible coke particles can be around 1.0 g / cm³. 3 Approximately 2.0 g / cm³ 3 (For example, approximately 1.0, 1.1, 1.2, 1.3 g / cm³) 3 Up to 1.4, 1.5, 1.6, 1.7 g / cm³ 3 Up to 1.8, 1.9, 2.0 g / cm³ 3 Within the range of ), conventional sand-based proppants typically have at least approximately 2.5 g / cm³. 3 The apparent density of flexible coke particles is significantly lower than that of conventional sand-based proppants, suggesting relatively more efficient transport and lower deposition rates within fractures formed as part of hydraulic fracturing operations.

[0096] In embodiments where fluid coke particles are used as at least a portion of the coke proppant particles described herein, such fluid coke particles are obtained via a fluid coking process. The fluid coking process can be manipulated in various ways to produce fluid coke particles with a number of specific characteristics. For example, the fluid coke particles may have a carbon content of about 75% to about 93% by weight (e.g., about 75, 77, 79, 81, 83% to 85, 87, 91, 93% by weight); a carbon to hydrogen weight ratio in the range of about 30:1 to about 50:1 (e.g., about 30:1, 35:1 to 40:1, 45:1, 50:1); and an impurity content in the range of about 5% to about 25% by weight (e.g., about 5, 10, 15% to 20, 25% by weight). The fluid coke particles may also have a sulfur content in the range of about 3% to about 10% by weight (e.g., about 3, 4, 5, 6% to 7, 8, 9, 10% by weight) and a nitrogen content in the range of about 0.5% to about 3% by weight (0.5, 1.0, 1.5% to 2.0, 2.5, 3.0% by weight). Furthermore, the apparent density of the fluid coke particles may be about 1.4 g / cm³. 3 Approximately 2.0 g / cm³ 3 (For example, approximately 1.4, 1.5, 1.6 g / cm³) 3 Up to 1.7, 1.8, 1.9, 2.0 g / cm³ 3 Within the range of ).

[0097] In embodiments where delayed coke particles are used as at least a portion of the coke proppant particles described herein, these delayed coke particles are produced within a delayed coking unit via a delayed coking method. According to the delayed coking method, a preheated feedstock is introduced into a fractionator, where it undergoes a thermal cracking process, in which long-chain hydrocarbons are broken down into shorter-chain hydrocarbons. The resulting lighter fraction is then removed as a side stream product. The fractionator bottoms, comprising a recycle stream of heavy products, are heated in a furnace, typically having an outlet temperature in the range of about 480°C to about 515°C. The heated feedstock is then introduced into a reactor, referred to as a "coke drum," which typically operates at a temperature in the range of about 415°C to about 450°C. Within the coke drum, the cracking reaction continues. The resulting cracking products then exit the coke drum as an overhead stream, while coke is deposited on the inner surface of the coke drum. Typically, this process lasts for about 16 hours to about 24 hours to allow the coke drum to fill with coke. Furthermore, to allow the delayed coking unit to operate on a batch-continuous (or semi-continuous) basis, two or more coke drums are typically used. While one coke drum is being filled with coke online, the other coke drums can be subjected to steam stripping, cooling, decoking (e.g., by hydraulically cutting the deposited coke), pressure checks, and heating. Additionally, the overhead feed stream exiting the coke drums enters a fractionator, where naphtha and heated oil fractions are recovered. The heavy recycled material is then typically combined with preheated fresh feed and recycled back into the process.

[0098] Delayed coke particles may exhibit the following properties: (1) a carbon content of about 82% to about 90% by weight (e.g., about 82, 83, 84, 85% to 86, 87, 88, 89, 90% by weight); (2) a carbon to hydrogen weight ratio in the range of about 15:1 to about 30:1 (e.g., about 15:1, 20:1 to 25:1, 30:1); and (3) a carbon to hydrogen weight ratio in the range of about 100 ppm to about 3,000 ppm (e.g., about 100, 500, 1,000, 1,500 ppm). (3) Total vanadium and nickel content of about 2,000, 2,500, 3,000 ppm; (4) Sulfur content of about 2 wt% to about 8 wt% (e.g., about 2, 3, 4, 5 wt% to 6, 7, 8 wt%); and / or (5) Nitrogen content of about 1 wt% to about 2 wt% (e.g., about 1.0, 1.2, 1.4 wt% to 1.6, 1.8, 2.0 wt%), wherein these properties are measured on a dry, ash-free basis (or in other words, without calculating residual ash content and removing moisture prior to analysis). Furthermore, the delayed coke particles may have a moisture content of about 6 wt% to about 14 wt% (e.g., about 6, 8, 10 wt% to 12, 14 wt%) and a volatile matter content of about 6 wt% to about 18 wt% (e.g., about 6, 8, 10, 12 wt% to 14, 16, 18 wt%), as measured on an as-is upon receipt. Furthermore, the apparent density of delayed coke particles can be approximately 1.0 g / cm³. 3 Approximately 1.7 g / cm³ 3 (For example, approximately 1.0, 1.1, 1.2, 1.3 g / cm³) 3 Up to 1.4, 1.5, 1.6, 1.7 g / cm³ 3 Within the range of ), the crushing strength of delayed coke particles can be comparable to that of other types of petroleum coke particles.

[0099] For embodiments in which microproppant coke particles are used as at least a portion of the coke proppant particles described herein, such microproppant coke particles may include FLEXICOKING TMThe process byproducts include wet flexible coke particles and / or dry flexible coke particles. Alternatively or additionally, the micropropped coke particles may comprise screened fluid coke, screened flexible coke, screened delayed coke, screened post-thermal treated coke, screened pyrolytic coke, and / or screened coal-derived coke (e.g., screened blast furnace coke and / or screened metallurgical coke). Alternatively or additionally, in some embodiments, the micropropped coke particles may comprise milled fluid coke, milled flexible coke, milled delayed coke, milled post-thermal treated coke, milled pyrolytic coke, and / or milled coal-derived coke (e.g., milled blast furnace coke and / or milled metallurgical coke). Furthermore, any other suitable type of micropropped coke particles may be used additionally or alternatively.

[0100] Regarding the use of microproppant coke particles comprising wet and / or dry flexible coke fines as at least a portion of the coke proppant particles described herein, such flexible coke fines are FLEXICOKING TM The process byproducts are collected as particles not recovered in the secondary cyclone separator of the heater within the flexible coke oven. More specifically, the particles are first collected as dry flexible coke fines in a tertiary cyclone separator, and then the smaller particles from the tertiary cyclone separator are recovered as wet flexible coke fines in a Venturi scrubber. While at least a portion of these flexible coke fines are generally considered waste, this disclosure provides for the efficient utilization of such flexible coke fines during hydraulic fracturing operations.

[0101] Regarding the use of micropropped coke particles, including screened fluid coke, screened flexible coke, screened delayed coke, screened post-thermal treated coke, screened pyrolytic coke, and / or screened coal-derived coke (e.g., screened blast furnace coke and / or screened metallurgical coke), as at least a portion of the coke proppant particles described herein, any suitable type (one or more) of bulk coke pellets can be separated into larger and smaller particles suitable for use as micropropped coke particles using any suitable type (one or more) of filters, screens, and / or related mechanical equipment. Furthermore, regarding the use of micropropped coke particles, including milled fluid coke, milled flexible coke, milled delayed coke, milled thermally post-treated coke, milled pyrolytic coke, and / or milled coal-derived coke (e.g., milled blast furnace coke and / or milled metallurgical coke), as at least a portion of the coke proppant particles described herein, such micropropped coke particles can be produced using any suitable type (one or more) of grinding / milling techniques (one or more). For example, in some embodiments, coke particles can be processed using hammer milling, spray milling, ball milling, etc., each of which typically involves crushing or pulverizing the coke particles into suitable sizes and shapes. Moreover, those skilled in the art will understand that, depending on the details of the particular implementation, any number of other grinding, milling, or other processing techniques may be additionally or alternatively used.

[0102] In various embodiments, the microproppant coke particles used according to the embodiments described herein may include a particle size of up to 105 μm (140 mesh), or in some cases, up to 88 μm (170 mesh), but may be in the range of about 0.0001 μm to 105 μm (e.g., about 0.0001, 0.001, 0.01, 0.1 μm to 0.5, 1.0, 2.0, 5.0, 8.0, 10 μm, to 15, 20, 25, 30, 35, 40, 45 μm, to 50, 53, 55, 60, 63, 65 μm, to 74, 75, 80, 85, 88, 90, 95, 100, 105 μm).

[0103] Furthermore, in various implementation schemes, these micropropagated coke particles have a density of approximately 1.0 g / cm³. 3 Approximately 2.0 g / cm³ 3 (For example, approximately 1.0, 1.1, 1.2, 1.3 g / cm³) 3 Up to 1.4, 1.5, 1.6, 1.7 g / cm³ 3 Up to 1.8, 1.9, 2.0 g / cm³ 3 The apparent density of coke is approximately 2.5 g / cm³, but the precise apparent density of the particles can vary depending on the specific type (or type) of coke used. In contrast, sand typically has an apparent density of at least approximately 2.5 g / cm³.3 The apparent density is [missing information]. Therefore, since the settling rate is proportional to the density difference between the solid particles and the carrying fluid (as shown in the expressions for both Stokes terminal settling velocity and Ferguson & Church settling velocity), these microproppant coke particles have a much lower settling rate than sand. As a result, proppant particles formed from microproppant coke particles will perform better than proppant particles formed from sand in terms of transport capacity within hydraulic fractures created, reopened, and / or extended during hydraulic fracturing operations.

[0104] Furthermore, the use of micro-propped coke particles as at least a portion of the coke proppant particles described herein offers numerous additional advantages over non-coke proppants. For example, the micro-propped coke particles are small enough to penetrate areas of secondary and natural fractures that non-coke proppants cannot effectively reach. As another example, due to the enhanced transport properties of the micro-propped coke particles, these particles can generate larger hydraulic fractures than non-coke proppants (i.e., by increasing one or more dimensions of such hydraulic fractures, such as fracture length, height, and / or azimuth). As yet another example, using micro-propped coke particles as at least a portion of the coke proppant particles described herein allows for an increase in fracturing fluid flow rate, as a portion of the fracturing fluid can be diverted into secondary hydraulic fractures and / or natural fractures. As yet another example, using micro-propped coke particles as at least a portion of the coke proppant particles described herein helps control fracturing fluid leakage into secondary and natural fractures, thereby improving fracturing fluid efficiency and resulting in larger conductive fractures.

[0105] Regarding the friction reducer used to coat the coke proppant particles according to the embodiments described herein, such friction reducer may include, but is not limited to, a base polymer, such as high molecular weight polyacrylamide, which will dissolve in a water-based fracturing fluid, thereby reducing turbulence and friction within the wellbore and the corresponding formation. Specifically, the high molecular weight polyacrylamide has a molecular weight of approximately 1.19 g / cm³. 3 The coke proppant has a high density and is highly absorbent of water. Therefore, the friction-reducing coating, at least partially formed from high molecular weight polyacrylamide, will swell when dissolved in water-based fracturing fluid. This swelling, combined with the lower density of the polymer compared to the fracturing fluid, will result in a low-density layer around the coke proppant particles. This, in turn, will reduce the average apparent density of the particles to approach the apparent density of the surrounding fracturing fluid. Furthermore, as the coke proppant particles travel downhole, the friction-reducing coating will rapidly mix with the surrounding fracturing fluid and collide with the surrounding casing, causing the coating to partially or completely dissolve within the fracturing fluid, thereby imparting friction-reducing properties to the fracturing fluid. This friction-reducing property then allows the coke proppant particles to be further delivered into the corresponding formation, reaching the extension area of ​​the corresponding hydraulic fracture.

[0106] In various embodiments, the friction-reducing agent coating further comprises a binder that forms a first layer of the coating and can be used to enable the friction-reducing agent to bind more effectively to the outer surface of the coke proppant particles. Such binders may include, but are not limited to, one or more proteins, one or more amino acids, one or more sugars, and / or one or more polysaccharides. The friction-reducing agent layer can then be applied over the binder layer. In other embodiments, the binder may be mixed with the friction-reducing agent, and the mixture forms at least a portion of the coating on or over the outer surface of the coke proppant particles. In some embodiments, the binder layer may cover various portions of the outer surface of the coke proppant particles, and the friction-reducing agent may directly contact and cover certain portions of the outer surface of the coke proppant particles and part or all of the binder layer.

[0107] Any suitable deposition method can be used to provide a friction-reducing agent coating on coke proppant particles. As a non-limiting example, the deposition method may include spraying a liquid binder or a liquid dispersion of a binder onto the coke proppant particles, and then coating the coke proppant particles with a friction-reducing agent in dry powder form using a stirring method. As another non-limiting example, the deposition method includes applying a friction-reducing agent in the form of an aqueous solution or an aqueous slurry suspension onto the coke proppant particles, and then drying the resulting coated coke proppant particles. In both examples, the deposition method may be carried out in multiple steps to form multiple coatings (e.g., at least one binder layer and at least one friction-reducing agent layer). Additionally, in both examples, during the deposition process, the weight of the friction modifier on the coke proppant particles can be from about 0.1% to about 2.3% by weight (e.g., 0.1, 0.2, 0.4, 0.6, 0.8, 1.0% to 1.2, 1.4, 1.6, 1.8, 2.0, 2.2, 2.3% by weight of friction modifier), based on the total weight of the friction modifier and the coke proppant particles. This weight percentage corresponds to 0.25 gpt (gallons per kilogal) to 6 gpt of friction modifier. Furthermore, for some embodiments in which a high-viscosity friction reducer (HVFR) is used, the weight of HVFR on the coke proppant particles during the deposition process can be from about 0.2 wt% to about 1.2 wt% HVFR (e.g., 0.2, 0.3, 0.4, 0.5, 0.6 wt% HVFR to 0.7, 0.8, 0.9, 1.0, 1.1, 1.2 wt% HVFR), based on the total weight of HVFR and coke proppant particles.

[0108] In various embodiments, the thickness of the friction-reducing agent coating (including a binder layer, if present) can range from about 1 μm to about 50 μm before the friction-reducing agent-coated coke proppant particles are mixed into the fracturing fluid. In some specific embodiments, the thickness can be from about 2 μm to about 25 μm before the friction-reducing agent-coated coke proppant particles are mixed into the fracturing fluid. However, the thickness can range from about 1, 5, 10 μm to about 15, 20, 25 μm, and from about 30, 35, 40, 45, 50 μm. Additionally, in some embodiments, when the friction-reducing agent coating is fully hydrated with water, particularly when the average apparent density of the initial coke proppant particles before coating with the friction-reducing agent is about 1.5 g / cm³, the coating is suitable for applications where the friction-reducing agent coating is applied. 3 At that time, the coke proppant particles coated with the friction reducer had a density of approximately 1.05 g / cm³. 3 Up to 1.5g / cm 3 (For example, 1.05, 1.15, 1.25 g / cm³) 3 Up to 1.35, 1.45, 1.5 g / cm³ 3 The apparent density of ).

[0109] Furthermore, in some embodiments, the deposition process can be performed at a facility located away from the hydraulic fracturing site. In other embodiments, a mobile processing facility located at the hydraulic fracturing site can be used to perform the deposition process. In some cases, it is preferable to perform the deposition process at (or near) the hydraulic fracturing site to reduce the risk of the coated particles becoming wet during transport.

[0110] Turning to details regarding exemplary characteristics of fracturing fluids in which coke proppant particles coated with the friction modifier described herein may be used, such fracturing fluids may include (in addition to the friction modifier-coated coke proppant particles) a flowable carrier fluid and one or more optional additives. In various embodiments, the fracturing fluid is formulated at the well site during the hydraulic fracturing process, in a mixing process that occurs simultaneously with the pumping of the fracturing fluid into the wellbore. When fracturing fluid is formulated at the well site, the friction modifier-coated coke proppant particles may be added in a manner similar to known methods of adding proppant to the fracturing fluid.

[0111] The carrier fluid according to this disclosure can be an aqueous carrier fluid containing water or a non-aqueous carrier fluid that is substantially anhydrous. Aqueous carrier fluids may include, for example, fresh water, brine (including seawater), treated water (e.g., treated production water), one or more other forms of aqueous fluids, or any combination thereof. A category of aqueous carrier fluids is commonly referred to as slickwater, and the corresponding fracturing operation is commonly referred to as slickwater fracturing. Non-aqueous carrier fluids may include, for example, oil-based fluids (e.g., hydrocarbons, olefins, mineral oils), alcohol-based fluids (e.g., methanol), or any combination thereof. In various embodiments, the viscosity of the carrier fluid can be modified by foaming or gelling. Foaming can be achieved using, for example, air or other gases (e.g., CO2, N2), alone or in combination. Gelation can be achieved using, for example, guar gum (e.g., hydroxypropyl guar gum), cellulose, or other gelling agents, which may or may not be crosslinked using one or more crosslinking agents, such as polyvalent metal ions or borate anions, and other suitable crosslinking agents.

[0112] In some cases, the carrier fluid used according to the embodiments described herein includes one or more types of aqueous carrier fluids, particularly considering the typically required large volumes (e.g., possibly from about 60,000 to about 1,000,000 gallons / wellbore). The aqueous carrier fluid may be gelled or may not be gelled. Using gelled aqueous carrier fluids (crosslinked or uncrosslinked) can facilitate better proppant particle delivery (i.e., reduced settling) and provide improved physical and chemical strength to withstand the temperature, pressure, and shear stresses encountered by the fracturing fluid during hydraulic fracturing operations. In some cases, the fracturing fluid includes an aqueous carrier fluid (which may or may not be foamed or gelled) and an acid (e.g., HCl) to further stimulate and expand the pore area of ​​the fracture surface matrix. It goes without saying that the low density of the coke proppant particles coated with the friction modifiers described herein allows for a reduction or elimination of the need for foaming or gelling of the carrier fluid.

[0113] In various implementations, the carrier fluid can be a high-salinity carrier fluid with a specific gravity of up to 1.1. In such implementations, the high-salinity carrier fluid can be an aqueous carrier fluid constituting the produced water, which can be cost-effectively and efficiently reused as a carrier fluid. In such embodiments, the utilization of the high-salinity carrier fluid increases the buoyancy effect, which can further improve the proppant delivery capacity of the corresponding fracturing fluid.

[0114] In various embodiments, the fracturing fluid includes one or more additives. Such additives may include, but are not limited to, one or more acids, one or more biocides, one or more breaker agents, one or more corrosion inhibitors, one or more crosslinking agents, one or more friction reducers (e.g., one or more high-viscosity friction reducers), one or more gels, one or more crosslinked gels, one or more oxygen scavengers, one or more pH control additives, one or more scale inhibitors, one or more surfactants, one or more weighting agents, one or more inert solids, one or more fluid loss control agents, one or more emulsifiers, one or more emulsion diluents, one or more emulsion thickeners, one or more viscosity modifiers, one or more foaming agents, one or more stabilizers, one or more chelating agents, one or more miscible solvents, one or more oxidizing agents, one or more reducing agents, one or more clay stabilizers, or any combination thereof. It is noteworthy that, in addition to a friction reducer coating, the fracturing fluid may contain or not contain one or more added friction reducers. However, in embodiments in which the fracturing fluid contains one or more friction modifiers, such friction modifiers may be included, for example, in a lower concentration range of about 0.5 gpt to about 1.0 gpt (e.g., about 0.5, 0.6, 0.7 gpt to 0.8, 0.9, 1.0 gpt).

[0115] The methods described herein include the preparation of fracturing fluids. In some embodiments, friction-reducing agent-coated coke proppant particles may be transported from a remote facility in dry form (e.g., via truck or rail). The transported friction-reducing agent-coated coke proppant particles can then be added directly to the wellbore at the production site, along with the carrying fluid and optional additives, or premixed in a hopper or other mixing device. For example, in some embodiments, small clumps of friction-reducing agent-coated coke proppant particles are added directly to the fracturing fluid (e.g., as if introduced into the wellbore). In other embodiments, a portion or all of the fracturing fluid is premixed at the production site. Any other suitable mixtures or additions of friction-reducing agent-coated coke proppant particles may also be used to produce the desired fracturing fluid composition without departing from the scope of this disclosure.

[0116] The hydraulic fracturing method applicable to one or more embodiments described herein involves pumping fracturing fluid at high pumping rates into a subsurface formation to create hydraulic fractures in the formation. In various embodiments, this process is performed one stage at a time along the wellbore. Specifically, the stage of interest is hydraulically isolated from any other stages that have previously been hydraulically fracturing and propped. In some embodiments, the stage of interest includes a perforated cluster within the production casing string of the wellbore, which allows fracturing fluid to flow out of the wellbore and into the subsurface formation. In some embodiments, during one or more durations of the hydraulic fracturing operation, the pumping rate of the fracturing fluid is at least about 20 barrels / minute (bbl / min) (0.05 cubic meters / second (m³ / min)). 3 / s), preferably at least about 30 bbl / min (0.08 m 3 / s), more preferably at least 50 bbl / min (0.14 m 3 / s) and at most 1000 bbl / min (2.73 m 3 / s (e.g., the rate can be constant, steadily increasing, or pulsed). In some embodiments, these high rates can be utilized after approximately 10% of the total volume of fracturing fluid to be pumped into the subsurface formation has been injected. That is, the pumping rate can be low in the early stages of a hydraulic fracturing operation and can be increased as hydraulic fractures begin to form. Typically, the average pumping rate of the fracturing fluid throughout the hydraulic fracturing operation can be approximately 10 bbl / min (0.03 m³ / s). 3 / s), preferably about 15bbl / min (0.04m 3 / s), more preferably at least 25 bbl / min (0.07 m 3 / s) and at most about 250 bbl / min (0.68 m 3 / s). Typically, during more than 30% of a hydraulic fracturing operation that exceeds the time required to complete a particular stage of hydraulic fracturing, the pumping rate of the fracturing fluid can be around 20 bbl / min (0.05 m³ / s). 3 / s) to approximately 150bbl / min (0.41m 3 / s) or approximately 40 bbl / min (0.11 m 3 / s) to approximately 120bbl / min (0.33m 3 / s) or approximately 40 bbl / min (0.11 m 3 / s) to approximately 100 bbl / min (0.27m 3 Within the range of / s).

[0117] In various embodiments, the hydraulic fracturing method described herein can be performed such that the concentration of friction-reducing agent-coated coke proppant particles (and any other type (one or more) of proppant particles) in the injected fracturing fluid is changed in real time or on-the-fly during the hydraulic fracturing operation, thereby maintaining hydraulic pressure in the subsurface formation and hydraulic fractures. For example, in some embodiments, the initially injected fracturing fluid is injected at a low pumping rate and contains about 1 wt% of proppant particles (i.e., comprising friction-reducing agent-coated coke proppant particles and any other type (one or more) of proppant particles) based on the total weight of the fracturing fluid (i.e., comprising the carrier fluid, friction-reducing agent-coated coke proppant particles, any other type (one or more) of proppant particles, and any additives). As the hydraulic fracture begins to form and grow, the pumping rate can be increased, and the concentration of proppant particles can be gradually increased (with or without a corresponding gradual increase in the pumping rate), with the maximum concentration of total proppant particles potentially reaching, for example, from about 2.5 wt% to about 20 wt%, based on the total weight of the fracturing fluid. For example, the maximum concentration of total proppant particles can reach at least 2.5 wt%, preferably at least 8 wt%, more preferably at least 16 wt%. In some embodiments, all proppant particles are coke particles coated with a friction modifier. In other embodiments, during one or more periods of hydraulic fracturing operation, at least about 2 wt% to about 100 wt% of any proppant particles suspended in the fracturing fluid are coke particles coated with a friction modifier, for example, at least about 2 wt%, preferably at least about 15 wt%, more preferably at least about 25 wt%, and in some cases, up to 100 wt%.

[0118] As for other types of proppant particles that may be included in fracturing fluids and / or fracturing fluids alone, such proppant particles may include, but are not limited to, uncoated coke proppant particles and / or non-coke proppant particles. Non-limiting examples of non-coke proppant particles that may be used include sand, crushed granite, ceramic beads, polymer microparticles, LWP, and / or ULWP. Furthermore, such other proppant particles may be directly blended into the fracturing fluid along with friction-reducing coated coke proppant particles, or may be added to a separate fracturing fluid that is sequentially introduced into the formation along with the fracturing fluid containing friction-reducing coated coke proppant particles.

[0119] In various embodiments, fracturing fluid containing friction-reducing agent-coated coke proppant particles is introduced into the subsurface formation during the pad phase of a hydraulic fracturing operation to allow the friction-reducing agent-coated coke proppant particles to travel within the fracturing fluid to the tip (or at least near) the formed hydraulic fracture. In such embodiments, fracturing fluid containing friction-reducing agent-coated coke proppant particles may also be introduced into the subsurface formation during the later stages of the hydraulic fracturing operation, such that the later-introduced slurry carrying fluid and friction-reducing agent-coated coke proppant particles continues to displace the earlier-introduced slurry carrying fluid and friction-reducing agent-coated coke proppant particles further away from the wellbore. Furthermore, in some embodiments, fracturing fluid containing friction-reducing agent-coated coke proppant particles is introduced into the subsurface formation continuously or intermittently throughout the hydraulic fracturing operation. In such an implementation, the ratio of friction-reducing agent-coated coke proppant particles introduced into the underground formation to other types (one or more) of proppant particles (if any) can be maintained at a stable (or substantially stable) value, or the ratio can be changed as the hydraulic fracturing operation proceeds.

[0120] The hydraulic fracturing method described herein can be carried out in a drilled hydrocarbon-producing wellbore comprising vertical, skew, highly skew, and / or lateral sections. Such wellbores can be drilled into various types of unconventional subsurface formations, including but not limited to tight sandstone formations, tight carbonate formations, shale gas formations, coalbed methane formations, and / or tight oil formations. As described herein, such wellbores are typically completed using a casing string cemented to the subsurface formation. To reach the subsurface formation, multiple perforation clusters are typically created through the production casing string; in this case, the wellbore may be referred to as a plug-and-perf ("plug-and-perf") casing cavity completion. Alternative completion techniques may be used without departing from the scope of this disclosure, but in each completion technique, a finite length of wellbore is exposed for hydraulic fracturing and injection of fracturing fluid. This finite section is referred to herein as a "stage". In plug and perforated completions, the stage length can be based on the distance the pipe and cement have been perforated and can exceed about 25 ft (7.6 m), but more typically exceeds about 100 ft (30.5 m).

[0121] During the plugging and perforation process, one or more diverting materials may be used to isolate the considered stage, allowing pressurized fracturing fluid to flow through the perforated cluster within the specific stage and into the subsurface formation to generate one or more hydraulic fractures only in the stage region. Such diverting materials may include, but are not limited to, one or more types of plugs (e.g., bridge plugs, packers, baffle / plug combinations, etc.), one or more types of particulate diverting agents (e.g., sand, ceramic materials, salt, wax, resin, and / or other compounds), one or more types of perforation plugging devices, one or more types of ball-seat devices (e.g., plugging balls, with or without retaining devices), one or more types of chemical diverting agents (e.g., liquids and / or gels), and / or one or more types of dart-sleeve devices (e.g., any type of sleeve device in which a ball or dart drops from the surface, contacts and opens a specific sleeve, allowing injection into a new stage while blocking flow to the underlying stage). Furthermore, in some embodiments, at least a portion of such diverting material is provided in a soluble, biodegradable, or self-destructible form, such that the diverting material is designed to dissolve, degrade, or self-destruct separately and then flow out of the wellbore, potentially eliminating the need for wellbore cleanup procedures.

[0122] For each linear foot of the stage, at least approximately 6 barrels (0.95 cubic meters) can be injected. 3 Preferably at least about 24 barrels (3.8m) 3 ), more preferably at least about 60 barrels (9.5m 3 And at most about 6,000 barrels (953.9m³) 3 Fracturing fluid is injected to cause hydraulic fractures to grow. In some embodiments, at least about 0.3 barrels (0.05 m³) may be injected for each linear foot of the stage. 3 ), preferably about 1.1 barrels (0.2m) 3 More preferably at least 2.8 barrels (0.4m) 3 And at most 285 barrels (45.3m) 3 ), or no more than 143 barrels (22.7m) 3 ), or no more than 114 barrels (18.1m) 3 The proppant particles (i.e., including coke proppant particles and any other type (one or more) of proppant particles) are used to support hydraulic fractures.

[0123] Turning to the details of the exemplary method according to this disclosure, Figure 9This is a process flow diagram of an exemplary method 900 for preparing coke proppant particles with a friction-reducing agent coating. The exemplary method 900 may begin at optional block 902, where a binder may be deposited on and / or above the outer surface of the coke proppant particles. This binder may be designed to increase the ability of the friction-reducing agent to adhere to the outer surface of the coke proppant particles, as described for block 904.

[0124] At box 904, a friction modifier may be deposited on and / or above the outer surface of the coke proppant particles to obtain friction modifier-coated coke proppant particles. The weight percentage of the friction modifier used during the deposition process is from 0.1 wt% to 2.3 wt% (e.g., 0.1, 0.2, 0.4, 0.6, 0.8, 1.0 wt% to 1.2, 1.4, 1.6, 1.8, 2.0, 2.2, 2.3 wt%), based on the total weight of the friction modifier and the coke proppant particles. For some embodiments in which HVFR is utilized, the weight percentage of HVFR used during the deposition process may be from about 0.2 wt% to about 1.2 wt% HVFR (e.g., 0.2, 0.3, 0.4, 0.5, 0.6 wt% to 0.7, 0.8, 0.9, 1.0, 1.1, 1.2 wt%, based on the total weight of HVFR and the coke proppant particles). Furthermore, the thickness of the friction-reducing agent coating can range from about 1 μm to 50 μm. In some specific embodiments, the thickness can range from about 2 μm to about 25 μm. However, the thickness can range from about 1, 5, 10 μm to about 15, 20, 25 μm, and from about 30, 35, 40, 45, 50 μm. Additionally, in some embodiments, when the friction-reducing agent coating is fully hydrated with water, particularly when the average apparent density of the initial coke proppant particles is about 1.5 g / cm³, the coating is suitable for applications where the friction-reducing agent ... 3 At that time, the coke proppant particles coated with friction reducer can have a particle size of approximately 1.05 g / cm³. 3 Up to 1.5g / cm 3 (For example, 1.05, 1.15, 1.25 g / cm³) 3 Up to 1.35, 1.45, 1.5 g / cm³ 3 The apparent density of ).

[0125] In various embodiments, the friction-reducing coating may comprise a copolymer containing acrylamide and acrylic structural units. In some such embodiments, the copolymer may further comprise AMPS structural units. In other such embodiments, the copolymer may further comprise TMAEA structural units.

[0126] In some embodiments, depositing the friction modifier on the outer surface of the coke proppant particles at block 904 may include spraying a liquid binder onto the coke proppant particles to obtain pre-coated coke proppant particles, and subsequently mixing the pre-coated coke proppant particles with the friction modifier in the form of a dry powder. In other embodiments, depositing the friction modifier on the outer surface of the coke proppant particles at block 904 may include forming an aqueous solution or slurry containing the friction modifier, mixing the coke proppant particles with the aqueous solution or slurry to obtain wet coke proppant particles, and subsequently drying the wet coke proppant particles.

[0127] In some embodiments, method 900 can be performed using equipment located at a subsequent hydraulic fracturing operation site, the equipment being designed to utilize friction-reducing agent-coated coke proppant particles. This can help prevent the friction-reducing agent-coated coke proppant particles from becoming wet during transport to the hydraulic fracturing site. However, in other embodiments, method 900 can be performed at a remote facility.

[0128] In some embodiments, at least a portion of the coke proppant particles may have a particle size of 74 μm to about 860 μm (e.g., 74, 84, 89, 97, 104, 107 μm to 109, 117, 130, 140, 160, 180 μm, to 200, 230, 280, 425, 450, 520 μm, to 700, 860 μm). In some embodiments, the coke proppant particles may include fluid coke, flexible coke, delayed coke, post-thermal treated coke, pyrolytic coke, coal-derived coke (e.g., blast furnace coke and / or metallurgical coke) or any combination thereof. In some embodiments, the coke proppant particles may consist only of petroleum coke particles. In some embodiments, the coke proppant particles may include microproppant coke particles. In such embodiments, the microproppant coke particles may include wet flexible coke fines and / or dry flexible coke fines. Alternatively or alternatively, in such embodiments, the microproppant coke particles may include screened fluid coke, screened flexible coke, screened delayed coke, screened post-heat treated coke, screened pyrolytic coke, and / or screened coal-derived coke (e.g., screened blast furnace coke and / or screened metallurgical coke). Alternatively or alternatively, in such embodiments, the microproppant coke particles may include ground fluid coke, ground flexible coke, ground delayed coke, ground post-heat treated coke, ground pyrolytic coke, and / or ground coal-derived coke (e.g., ground blast furnace coke and / or ground metallurgical coke).

[0129] Those skilled in the art will understand that Figure 9The exemplary method 900 is readily modifiable without altering the technical effects provided by this disclosure. For example, in some embodiments, one or more blocks may be omitted from method 900, and / or one or more blocks may be added to method 900. In practice, the precise manner in which method 900 is performed will depend at least in part on the specific details of its execution.

[0130] Figure 10 This is a process flow diagram of an exemplary hydraulic fracturing method 1000 using coke proppant particles coated with a friction modifier. The exemplary method 1000 begins at block 1002, where subsurface formations are hydraulically fracturing via a wellbore by introducing fracturing fluid comprising coke proppant particles carrying fluid and a friction modifier-coated material into the subsurface formation. The friction modifier-coated coke proppant particles can be used as follows... Figure 9 As described in method 900.

[0131] In some embodiments, the fracturing fluid may also contain non-coke proppant particles. In such embodiments, non-coke proppant particles may include, but are not limited to, sand, crushed granite, ceramic beads, polymer microparticles, LWP, ULWP, or any combination thereof. Furthermore, in some embodiments, the fracturing fluid may also contain uncoated coke proppant particles, which are added to the fracturing fluid after a friction modifier coating has been deposited on the outer surface of the coke proppant particles.

[0132] In some embodiments, the carrier fluid may be an aqueous carrier fluid containing water. In other embodiments, the carrier fluid may be a non-aqueous carrier fluid that is substantially free of water. Furthermore, in some embodiments, the fracturing fluid may also contain one or more additives, including but not limited to one or more acids, one or more biocides, one or more breaker agents, one or more corrosion inhibitors, one or more crosslinking agents, one or more gels, one or more crosslinking gels, one or more oxygen scavengers, one or more pH control additives, one or more scale inhibitors, one or more surfactants, one or more weighting agents, one or more inert solids, one or more fluid loss control agents, one or more emulsifiers, one or more emulsion diluents, one or more emulsion thickeners, one or more viscous agents, one or more foaming agents, one or more stabilizers, one or more chelating agents, one or more miscible solvents, one or more oxidizing agents, one or more reducing agents, and / or one or more clay stabilizers. In some such embodiments, at least a portion of these additives may be included as part of a friction-reducing coating.

[0133] In some embodiments, the carrier fluid may be substantially free of friction modifiers contained in the coated coke proppant particles. In other embodiments, the coated coke proppant particles may contain a first weight of friction modifier W1, and the carrier fluid may contain a second weight of friction modifier W2, wherein 10% ≤ W1 / (W1+W2)*100% ≤ 90%, and the ratio of W1 / (W1+W2) may be in the range of, for example, 0.1, 0.2, 0.3, 0.4, 0.5 to 0.6, 0.7, 0.8, 0.9.

[0134] In various implementations, fracturing fluid can be introduced into the subsurface formation via a wellbore for each of the multiple stages of a hydrocarbon well. For each stage, fracturing fluid can be introduced into the subsurface formation during at least a portion of the pad phase of the hydraulic fracturing operation and during at least a portion of the remainder of the hydraulic fracturing operation.

[0135] Furthermore, at box 1004, hydrocarbon fluids can be produced from the subsurface formation via the wellbore after hydraulic fracturing at box 1002. According to the aspects and embodiments described herein, utilizing coke proppant particles coated with a friction reducer as part of the proppant introduced into the subsurface formation at box 1002 can increase the overall SRV in the subsurface formation, thereby improving the production performance of the hydrocarbon well.

[0136] Those skilled in the art will understand that Figure 10 The exemplary method 1000 is readily modifiable without altering the technical effects provided by this disclosure. For example, in some embodiments, one or more blocks may be omitted from method 1000, and / or one or more blocks may be added to method 1000. In practice, the precise manner in which method 1000 is performed will depend at least in part on the specific details of its execution.

[0137] This disclosure may include one or more of the following non-limiting aspects and implementation methods:

[0138] A1. Coke proppant particles coated with a friction reducer, comprising a friction reducer coating deposited on and / or above the outer surface of the coke proppant particles, wherein the friction reducer coating has a thickness of 1 μm to 50 μm.

[0139] A2.A1 coke proppant particles coated with a friction reducer, wherein the friction reducer coating has a thickness of 2 μm to 25 μm.

[0140] Coke proppant particles coated with friction reducers of A3, A1, or A2, wherein the friction reducer coating comprises a copolymer having acrylamide and acrylic structural units.

[0141] A4.A3 friction-reducing agent coated coke proppant particles, wherein the copolymer further comprises 2-acryloylamino-2-methylpropanesulfonic acid ("AMPS") structural units.

[0142] A5.A3 friction-reducing agent coated coke proppant particles, wherein the friction-reducing agent coating further comprises trimethylaminoethyl acrylate ("TMAEA") structural units.

[0143] A6. Coke proppant particles coated with a friction reducer according to any one of A1 to A5, wherein the friction reducer coating comprises a binder.

[0144] A7.A6 Coke proppant particles coated with a friction reducer, wherein the friction reducer coating comprises (i) an adhesive layer adjacent to the outer surface of the coke proppant particles, and (ii) a friction reducer coating above the adhesive layer.

[0145] A8. Coke proppant particles coated with a friction reducer according to any one of A1 to A7, wherein the friction reducer coating comprises a friction reducer; and wherein the weight percentage of the friction reducer is from 0.1 wt% to 2.3 wt% based on the total weight of the friction reducer and the coke proppant particles.

[0146] A9.A8 coke proppant particles coated with a friction reducer, wherein the friction reducer comprises a high-viscosity friction reducer ("HVFR"), and wherein the weight percentage of the friction reducer is from 0.2 wt% to 1.2 wt% based on the total weight of the friction reducer and the coke proppant particles.

[0147] A10. Coke proppant particles coated with a friction reducer according to any one of A1 to A9, wherein the coke proppant particles comprise at least one of the following substances: fluid coke; flexible coke; delayed coke; heat-treated coke; pyrolytic coke; and coal-derived coke.

[0148] Coke proppant particles coated with a friction reducer according to any one of A1 to A10, wherein the coke proppant particles comprise microproppant coke particles.

[0149] Coke proppant particles coated with a friction reducer according to any one of A12, A6 to A11, wherein the binder comprises at least one of a protein, an amino acid, a sugar, and a polysaccharide.

[0150] B1. Fracturing fluid, comprising: a carrier fluid; and coke proppant particles coated with a friction modifier of any one of A1 to A9.

[0151] B2.B1 fracturing fluid, wherein when the friction-reducing agent coating is hydrated with water, the coke proppant particles coated with the friction-reducing agent have a density of 1.05 g / cm³. 3 Up to 1.5g / cm3 Apparent density.

[0152] B3, B1, or B2 fracturing fluids, wherein the friction-reducing coating comprises a copolymer having acrylamide and acrylic structural units.

[0153] B4.B3 fracturing fluid, wherein the copolymer further comprises 2-acryloylamino-2-methylpropanesulfonic acid ("AMPS") structural units.

[0154] B5.B3 fracturing fluid, wherein the friction-reducing agent coating further comprises trimethylaminoethyl acrylate ("TMAEA") structural units.

[0155] Fracturing fluid of any one of B6, B1 to B5, wherein the friction-reducing agent coating comprises a binder.

[0156] The fracturing fluid of B7.B6, wherein the friction-reducing agent coating comprises (i) a binder layer adjacent to the outer surface of the coke proppant particles, and (ii) a friction-reducing agent coating above the binder layer.

[0157] The fracturing fluid of any one of B8, B1 to B7, wherein the coke proppant particles comprise at least one of the following substances: fluid coke; flexible coke; delayed coke; thermally post-treated coke; pyrolytic coke; and coal-derived coke.

[0158] Fracturing fluid of any one of B9, B1 to B8, wherein the coke proppant particles comprise microproppant coke particles.

[0159] The fracturing fluid of any one of B10, B1 to B9, wherein the fracturing fluid further comprises non-coke proppant particles.

[0160] A fracturing fluid of any one of B11 to B10, wherein the fracturing fluid further comprises at least one additive, and wherein the at least one additive comprises at least one of the following substances: acid, biocide, breaker, corrosion inhibitor, crosslinking agent, gel, crosslinking gel, oxygen scavenger, pH control additive, scale inhibitor, surfactant, weighting agent, inert solid, filtrate control agent, emulsifier, emulsion diluent, emulsion thickener, viscous agent, foaming agent, stabilizer, chelating agent, mutual solvent, oxidant, reducing agent, and clay stabilizer.

[0161] B12.B11 fracturing fluids, wherein the friction-reducing agent coating further comprises at least a portion of the at least one additive.

[0162] Fracturing fluid of any one of B13 to B12, wherein at least a portion of the coke proppant particles have a particle size of 210 μm to 860 μm.

[0163] B14. A fracturing fluid of any one of A6 to B13, wherein the binder comprises at least one of protein, amino acid, sugar, and polysaccharide. C1. A method for preparing coke proppant particles coated with a friction reducer, comprising depositing a friction reducer on and / or above the outer surface of coke proppant particles to obtain friction reducer-coated coke proppant particles; wherein the weight percentage of the friction reducer used during the deposition process is from 0.1 wt% to 2.3 wt% based on the total weight of the friction reducer and the coke proppant particles; and wherein the thickness of the resulting friction reducer coating is from 1 μm to 50 μm.

[0164] The C2.C1 method, wherein the friction modifier comprises a high-viscosity friction modifier (“HVFR”), and wherein the weight percentage of the friction modifier used during the deposition process is from 0.2 wt% to 1.2 wt%, based on the total weight of the friction modifier and the coke proppant particles.

[0165] Methods C3, C1, or C2, wherein when the friction-reducing agent coating is hydrated with water, the coke proppant particles coated with the friction-reducing agent have a density of 1.05 g / cm³. 3 Up to 1.5g / cm 3 Apparent density.

[0166] The method of any one of C4, C1 to C3, wherein the thickness of the friction reducing agent coating is 2 μm to 25 μm.

[0167] The method of any one of C5, C1 to C4, wherein the friction reducer comprises a copolymer having acrylamide structural units and acrylic structural units.

[0168] The C6.C5 method, wherein the copolymer further comprises 2-acryloylamino-2-methylpropanesulfonic acid ("AMPS") structural units.

[0169] The C7.C5 method, wherein the copolymer further comprises trimethylaminoethyl acrylate structural units.

[0170] The method of any one of C8, C1 to C7, wherein the friction-reducing agent coating further comprises a binder, and wherein the method comprises depositing the binder on the outer surface of the coke proppant particles before depositing the friction-reducing agent on the outer surface of the coke proppant particles.

[0171] The method of any one of C9, C1 to C8, wherein depositing the friction reducer on the outer surface of the coke proppant particles comprises: spraying a liquid binder onto the coke proppant particles to obtain pre-coated coke proppant particles; and subsequently mixing the pre-coated coke proppant particles with the friction reducer in the form of a dry powder.

[0172] The method of any one of C10, C1 to C8, wherein depositing the friction reducer on the outer surface of the coke proppant particles comprises: forming an aqueous solution or slurry containing the friction reducer; mixing the coke proppant particles with the aqueous solution or slurry to obtain wet coke proppant particles; and subsequently drying the wet coke proppant particles.

[0173] The method of any one of C11 to C10, wherein the coke proppant particles comprise at least one of the following substances: fluid coke; flexible coke; delayed coke; thermally post-treated coke; pyrolytic coke; and coal-derived coke.

[0174] The method of any one of C12, C1 to C11, wherein the coke proppant particles comprise microproppant coke particles.

[0175] The method of any one of C13, C1 to C12, wherein the coke proppant particles have a particle size of 74 μm to 860 μm.

[0176] D1. A method for preparing fracturing fluid, comprising: providing coke proppant particles coated with a friction reducer of any one of A1 to A12; and mixing the friction reducer-coated coke proppant particles with a carrying fluid and optionally one or more of the following additives: acid, biocide, breaker, corrosion inhibitor, crosslinking agent, gel, crosslinking gel, oxygen scavenger, pH control additive, scale inhibitor, surfactant, weighting agent, inert solid, filtration control agent, emulsifier, emulsion diluent, emulsion thickener, viscous agent, foaming agent, stabilizer, chelating agent, mutual solvent, oxidant, reducing agent, and clay stabilizer.

[0177] The method of D2.D1, wherein the carrying fluid is substantially free of friction modifiers contained in the coated coke proppant particles.

[0178] The method of D3.D1, wherein the coated coke proppant particles contain a first weight of friction modifier W1; wherein the carrying fluid contains a second weight of friction modifier W2; and wherein 10% ≤ W1 / (W1+W2)*100% ≤ 90%.

[0179] E1. A hydraulic fracturing method for underground formations, comprising introducing fracturing fluid, as described in any one of B1 to B14, into the underground formation. While the embodiments described herein are well calculated to achieve the advantages presented, it should be understood that these embodiments are readily modified, varied, and altered without departing from their spirit. In other words, the specific embodiments described herein are merely illustrative, as the teachings of this disclosure can be modified and practiced in different but equivalent ways that would be apparent to those skilled in the art benefiting from the teachings herein. Furthermore, the systems and methods disclosed herein illustratively can be suitably practiced in the absence of any elements not specifically disclosed herein and / or any optional elements disclosed herein. Although compositions and methods are described by way of “comprising” or “including” various components or steps, said compositions and methods may also consist “substantially” or “consisting of” said various components and steps. In fact, this disclosure includes all alternatives, modifications, and equivalents that fall within the true spirit and scope of the appended claims.

Claims

1. Coke proppant particles coated with a friction reducer, comprising a friction reducer coating deposited on and / or above the outer surface of the coke proppant particles, wherein the friction reducer coating has a thickness of 1 micrometer (μm) to 50 μm.

2. The coke proppant particles coated with the friction reducer of claim 1, wherein the friction reducer coating has a thickness of 2 μm to 25 μm.

3. The coke proppant particles coated with the friction reducer of claim 1, wherein the friction reducer coating comprises a copolymer having acrylamide structural units and acrylic structural units.

4. The coke support particles coated with the friction reducer of claim 3, wherein the copolymer further comprises 2-acryloylamino-2-methylpropanesulfonic acid structural units.

5. The coke proppant particles coated with the friction reducer of claim 3, wherein the friction reducer coating further comprises trimethylaminoethyl acrylate structural units.

6. The coke proppant particles coated with the friction reducer of claim 1, wherein the friction reducer coating comprises a binder.

7. The coke proppant particles coated with the friction reducer of claim 6, wherein the friction reducer coating comprises (i) an adhesive layer adjacent to the outer surface of the coke proppant particles, and (ii) a friction reducer coating above the adhesive layer.

8. The coke proppant particles coated with the friction reducer of claim 1, wherein the friction reducer coating comprises a friction reducer; and wherein the weight percentage of the friction reducer is from 0.1 wt% to 2.3 wt% based on the total weight of the friction reducer and the coke proppant particles.

9. The coke proppant particles coated with the friction reducer of claim 8, wherein the friction reducer comprises a high-viscosity friction reducer, and wherein the weight percentage of the friction reducer is 0.2% to 1.2% by weight, based on the total weight of the friction reducer and the coke proppant particles.

10. Fracturing fluid, comprising: Carrying fluid; and The coke proppant particles coated with the friction reducer of claim 1.

11. The fracturing fluid of claim 10, wherein when the friction modifier coating is hydrated with water, the coke proppant particles coated with the friction modifier have a content of 1.05 g / cm³. 3 ) to 1.5 g / cm 3 Apparent density.

12. The fracturing fluid of claim 10, wherein the friction-reducing coating comprises a copolymer having acrylamide structural units and acrylic structural units.

13. The fracturing fluid of claim 12, wherein the copolymer further comprises 2-acryloylamino-2-methylpropanesulfonic acid structural units.

14. The fracturing fluid of claim 12, wherein the friction-reducing coating further comprises trimethylaminoethyl acrylate structural units.

15. The fracturing fluid of claim 10, wherein the friction-reducing agent coating comprises a binder layer.

16. The fracturing fluid of claim 15, wherein the friction-reducing coating comprises (i) a binder layer adjacent to the outer surface of the coke proppant particles, and (ii) a friction-reducing coating above the binder layer.

17. The fracturing fluid of claim 10, wherein the fracturing fluid further comprises at least one additive, and wherein the at least one additive comprises at least one of the following substances: acid, biocide, breaker, corrosion inhibitor, crosslinking agent, gel, crosslinking gel, oxygen scavenger, pH control additive, scale inhibitor, surfactant, weighting agent, inert solid, filtration control agent, emulsifier, emulsion diluent, emulsion thickener, viscous agent, foaming agent, stabilizer, chelating agent, mutual solvent, oxidant, reducing agent, and clay stabilizer.

18. The fracturing fluid of claim 17, wherein the friction-reducing coating further comprises at least a portion of the at least one additive.

19. The fracturing fluid of claim 10, wherein at least a portion of the coke proppant particles has a particle size of 210 μm to 860 μm.

20. A method for preparing coke proppant particles coated with a friction-reducing agent, comprising depositing a friction-reducing agent on and / or above the outer surface of coke proppant particles to obtain coke proppant particles coated with a friction-reducing agent; wherein the weight percentage of the friction-reducing agent used during the deposition process is from 0.1 wt% to 2.3 wt% based on the total weight of the friction-reducing agent and the coke proppant particles; and wherein the thickness of the resulting friction-reducing agent coating is from 1 micrometer (μm) to 50 μm.

21. The method of claim 20, wherein the friction modifier comprises a high viscosity friction modifier (HVFR), and wherein the weight percentage of the friction modifier used during the deposition process is from 0.2 wt% to 1.2 wt% based on the total weight of the friction modifier and the coke proppant particles.

22. The method of claim 20, wherein when the friction-reducing agent coating is hydrated with water, the coke proppant particles coated with the friction-reducing agent have a content of 1.05 g / cm³. 3 ) to 1.5 g / cm 3 Apparent density.

23. The method of claim 20, wherein the thickness of the friction-reducing agent coating is 2 μm to 25 μm.

24. The method of claim 20, wherein the friction reducer comprises a copolymer having acrylamide structural units and acrylic structural units.

25. The method of claim 24, wherein the copolymer further comprises a 2-acryloylamino-2-methylpropanesulfonic acid structural unit.

26. The method of claim 24, wherein the copolymer further comprises a trimethylaminoethyl acrylate structural unit.

27. The method of claim 20, wherein the friction-reducing agent coating further comprises a binder, and wherein the method comprises depositing the binder on the outer surface of the coke proppant particles before depositing the friction-reducing agent on the outer surface of the coke proppant particles.

28. The method of claim 20, wherein depositing the friction reducer on the outer surface of the coke proppant particles comprises: A liquid binder is sprayed onto the coke proppant particles to obtain pre-coated coke proppant particles. and subsequently The pre-coated coke proppant particles are mixed with the friction reducer in the form of a dry powder.

29. The method of claim 20, wherein depositing the friction reducer on the outer surface of the coke proppant particles comprises: An aqueous solution or slurry containing the friction-reducing agent is formed; The coke proppant particles are mixed with the aqueous solution or slurry to obtain wet coke proppant particles. and subsequently The wet coke proppant particles are dried.

30. The method of claim 20, wherein the carrying fluid is substantially free of friction modifiers contained in the coated coke proppant particles.

31. The method of claim 20, wherein the coated coke proppant particles comprise a first weight of friction modifier W1; wherein the carrying fluid comprises a second weight of friction modifier W2; and wherein 10% ≤ W1 / (W1+W2)*100% ≤ 90%.

32. A hydraulic fracturing method for underground formations, comprising introducing the fracturing fluid of claim 10 into the underground formation.

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