CN118318093A

CN118318093A - Proppant particulates formed from delayed coke and related methods

Info

Publication number: CN118318093A
Application number: CN202380013967.0A
Authority: CN
Inventors: P·A·戈登; 冯朗
Original assignee: ExxonMobil Technology and Engineering Co
Current assignee: ExxonMobil Technology and Engineering Co
Priority date: 2022-11-09
Filing date: 2023-10-12
Publication date: 2024-07-09

Abstract

Proppant particulates such as sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an open state after hydraulic pressure is released. The fracturing fluid and method of hydraulic fracturing may also use proppant particulates composed of petroleum coke material. Such proppant particulates can be better transported into the fracture and can produce less fines that reduce the flow of fluid through the proppant pack due to having a lower density than conventional proppants such as sand. The proppant particulates of the present disclosure are composed of thermally post-treated delayed cokes and exhibit mechanical properties comparable to fluidized cokes and flexible coke petroleum coke materials used as proppant particulates.

Description

Proppant particulates formed from delayed coke and related methods

Cross Reference to Related Applications

The present application claims priority from 63/382968 submitted at 11/9 of 2022. The application also relates to the following: U.S.2021/0253944 entitled "Proppant Particulates Formed from Flexicoke and Methods Related Thereto" filed on 1/27 of 2021; WO 2021/15837 entitled "Proppant Particulates Formed from Flexicoke and Methods Related Thereto" filed on 1/27 of 2027; U.S.2021/0246364 entitled "Proppant Particulates Formed from Fluid Coke and Methods Related Thereto" filed on 1/27 of 2021; WO 2021/158398 entitled "Proppant Particulates Formed from Fluid Coke and Methods Related Thereto" filed on 1/27 of 2021; U.S.63/186,981 submitted at 11/5/2021 and PCTUS2022/070811 submitted at 24/2/2022.

Technical Field

The present disclosure relates to fracturing operations and proppant particulates employed therein.

Background

Wellbores may be drilled into subterranean formations to facilitate the removal (production) of hydrocarbon or water resources therefrom. In many cases, it is desirable to stimulate a subterranean formation in some manner in order to facilitate the removal of resources. The stimulation operations may include any operation performed on the matrix of the subterranean formation in order to improve fluid conductivity therethrough, including hydraulic fracturing, which is a common stimulation operation for unconventional reservoirs.

Hydraulic fracturing operations pump large amounts of fluid into a subterranean formation (e.g., a low permeability formation) at high hydraulic pressures to promote the formation of one or more fractures and create a highly conductive flow path within the matrix of the subterranean formation. Primary fractures extending from the wellbore may be formed during the fracturing operation, and in some cases secondary fractures may dendritic extend from the primary fractures. These slits may be vertical, horizontal or a combination of directions that form a tortuous path.

Proppant particulates are typically included in the fracturing fluid to hold the fracture open after the hydraulic pressure is released following the hydraulic fracturing operation. Once the fracture is reached, the proppant particulates settle therein to form a proppant pack (proppant pack) to prevent the fracture from closing once the hydraulic pressure is released.

Difficulties are often encountered during hydraulic fracturing operations, particularly in connection with the deposition of proppant particulates in fractures created or extended under hydraulic pressure. Because the proppant particulates are typically denser materials (as compared to the hydraulic fracturing fluid used), efficient transport of the proppant particulates can be difficult due to settling, making it challenging to distribute the proppant particulates to a further extent of the fracture network. In addition, fine particles (referred to as "fines", which are less than about 20 μm, e.g., in the range of about 0.01 μm to about 20 μm, inclusive of any values and subsets therebetween) can clog the port throats (through which fracturing fluid flows) in the proppant pack created by the crushing of the proppant particulates within the fracture, resulting in stagnant fluid conductivity, which can reduce productivity and/or require wellbore cleanup operations.

Lower density particles such as coke have been used in fracturing operations, for example, as described in U.S. patent No. 3,664,420, incorporated herein by reference in its entirety. In said patent, coke is used as far field diverter (far-FIELD DIVERTER) instead of proppant. Far field diverter fills in the tip or end of the primary and secondary fractures to form a very low permeability zone. In this patent, after far field diverter is pumped into the fracture tip, a relatively high density and large size of proppant particles (e.g., metal pellets) are packed into the majority of the fracture to form a high permeability zone.

Fluidized and flexible cokes (flexicoke) have previously been demonstrated to have mechanical properties that make them suitable for use as proppants during fracturing operations involving unconventional reservoirs. In contrast, delayed cokes have weaker mechanical properties and are therefore considered less efficient in such fracturing operations despite their wide availability. Thus, the use of delayed coke as a proppant is more associated with fracture conductivity loss as measured with increasing closure stress. There is a need to improve the mechanical properties of delayed cokes used as proppant particulates in subterranean fracturing operations.

Disclosure of Invention

The present disclosure relates generally to fracturing, and more particularly to proppant particulates formed from delayed cokes for fracturing, and methods related thereto.

A non-limiting example fracturing fluid of the present disclosure comprises: a carrier fluid; and thermally post-treated delayed coke proppant particulates, wherein the thermally post-treated delayed coke proppant particulates comprise delayed coke that has been thermally post-treated to a temperature in the range of about 400 ℃ to about 1000 ℃ for a predetermined duration and milled to a predetermined average size diameter, in any order

Non-limiting example methods of the present disclosure include: introducing a fracturing fluid into the subterranean formation, the fracturing fluid comprising a carrier fluid and thermally post-treated delayed coke proppant particulates, wherein the thermally post-treated delayed coke proppant particulates comprise delayed coke that has been thermally post-treated to a temperature in the range of about 400 ℃ to about 1000 ℃ for a predetermined duration and milled to a predetermined average size diameter, in any order.

These and other features and attributes of the disclosed methods and compositions, as well as their advantageous applications and/or uses, will be apparent from the detailed description that follows.

Brief description of the drawings

The following drawings are included to illustrate certain aspects of the embodiments and are not to be considered exclusive embodiments. The disclosed subject matter is capable of considerable modification, alteration, combination, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure.

Figures 1A-1C show images of the size and shape of a typical delayed coke compared to fluidized coke (fluidized coke).

Fig. 2 shows a graph of typical delayed cokes versus fluidized cokes, flexicokes, and sand proppant particulates for fracture conductivity testing results.

FIG. 3 is a simplified flow diagram of a method and system of treating delayed cokes of the present disclosure.

Fig. 4 shows comparative fracture conductivity results for fluidized coke and conventional sand.

Fig. 5 shows the comparative size distribution results of fluidized coke and conventional sand.

Fig. 6 shows the comparative shape distribution results of fluidized coke and conventional sand.

Fig. 7A and 7B illustrate the effects of heat post-treated delayed coke C/H ratio and TGA in accordance with one or more aspects of the present disclosure.

Fig. 8 illustrates an apparent density of thermally post-treated delayed coke in accordance with one or more aspects of the present disclosure.

Fig. 9A illustrates a nano-indentation technique and fig. 9B illustrates a remaining indentation formed on a delayed coke sample in accordance with one or more aspects of the present disclosure.

Fig. 10A and 10B illustrate graphs of nanoindentation results for delayed coke samples, fluidized coke samples, epoxy reference samples, and conventional sand samples, in accordance with one or more aspects of the present disclosure.

FIG. 11 illustrates a graph of stress strain curves for various delayed coke 40/70 mesh samples, in accordance with one or more aspects of the present disclosure.

Fig. 12A and 12B illustrate graphs of fracture conductivity results for delayed coke samples, fluidized coke samples, and flexible coke samples, in accordance with one or more aspects of the present disclosure.

Detailed Description

As discussed above, proppant particulates may be effectively used during fracturing operations, but there may be problems associated with their use. First, the high density of typical proppant particulates may impede their transport, possibly resulting in inadequate proppant particulate placement within one or more fractures. Second, some proppant particulates tend to form fines due to low crush strength values, which may result in reduced fracture conductivity due to fines accumulation within the fracture.

The present disclosure alleviates the above difficulties and also provides related advantages. In particular, the present disclosure provides proppant particulates composed of delayed cokes that use a heat treatment route to enhance the mechanical properties of the delayed cokes to be comparable to fluidized cokes and flexible cokes. Delaying the grinding of the coke proppant particulates to the mesh range of interest and exhibiting low density and high crush strength solves two significant drawbacks of conventional proppant particulates typically formed from sand particles.

Typically, delayed cokes are used as an inexpensive low BTU fuel source in various thermal manufacturing processes. By using delayed coke as the proppant particulates, a useful application of the material is created without the associated CO ₂ emissions. Indeed, the use of delayed coke as a proppant rather than as a fuel is a form of sequestering carbon that would otherwise contribute to the emission of CO ₂.

In addition, the costs associated with hydraulic fracturing can also be reduced, at least because large amounts of delayed cokes are readily available from already existing petroleum refinery process streams (80% of the total coke is delayed coke) and are generally cost competitive with sand or other conventional proppant particulates; and their low density may reduce or eliminate the need to use gelled fracturing fluids (and costs associated with gelation), potentially reducing the required pumping pressures, water consumption, and wellbore cleaning operations.

Additional advantages not provided by the present disclosure in current proppant particle methods include, but are not limited to, moderate heat treatment without reaching complete calcination, as is commonly practiced, where the heat treatment can reach 1200-1300 ℃, which has a profound effect on the mechanical strength of the material; careful removal of fines after grinding the delayed coke results in a proppant particulate product with a great improvement; and acceptable proppant particle performance.

Illustrative aspects of the present disclosure include fracturing fluids comprising proppant particulates composed of delayed cokes derived from thermal processing pathways to enhance their mechanical properties. The delayed coke proppant particulates are adapted to support one or more fractures induced in horizontal, vertical, or tortuous wellbores (including hydrocarbon-containing production wellbores and water-containing production wellbores) and in unconventional formations (e.g., sandstone, shale, etc.) during hydraulic fracturing operations.

Definition and test method

As used herein, the term "proppant particulates" or shorthand "proppants" and grammatical variations thereof refers to solid materials capable of maintaining induced fracture patency during and after hydraulic fracturing treatments. The term "proppant pack" refers to a collection of proppants.

As used herein, the term "delayed coke" and grammatical variations thereof refers to waste carbon product remaining in the delayed coker regardless of morphology (e.g., regardless of size, shape, and particle shape of the intra-particle orientation domains), including shot coke (shot coke), sponge coke, transition coke (transition coke), and needle coke. In one or more instances, delayed cokes may refer to petroleum shot cokes derived from delayed coking processes. Delayed coking processes involve heating a residuum feed to its thermal cracking temperature in two or more reactors ("coke drums") which crack heavy long chain hydrocarbon molecules into a gasification product stream and a concentrated solid carbon coke (referred to as "delayed coke"). The process and resulting coke are referred to as "delayed" because the resid feed is maintained by the reactor while cracking occurs. The delayed coke of the present disclosure is referred to as "shot coke" because its appearance is characterized as hemispherical aggregates, and because it is identified as an undesirable petroleum coke grade at least because of its difficulty in handling, and is generally unacceptable for specialty coke applications. In all cases of the present disclosure, the term "delayed coke" refers to shot coke.

The delayed coke may be characterized as having a sulfur content in the range of about 1 weight percent (wt%) to about 8wt%, a volatile material in the range of about 8wt% to about 15 wt%, a hadamard grindability index (Hargrove grindability index) in the range of about 30 to 130, and a density in the range of about 1.2 to about 1.4.

As used herein, the term "thermally post-treated delayed coke proppant particulates" and grammatical variations thereof refers to delayed cokes that have been at least thermally treated after a coking process, as described herein. The term also encompasses such heat treated delayed cokes that have been ground and optionally removed of fines. That is, unless otherwise indicated, the term "thermally post-treated delayed coke proppant particulates" encompasses thermally treated and milled (in all cases the term "milled" and grammatical variations thereof encompass "milled", depending on the particular machinery used) delayed cokes, which may or may not have fines removed.

As used herein, the term "fluidized coke" and grammatical variations thereof refers to materials obtained by a decarbonization process for upgrading heavy hydrocarbon feeds and/or processing challenging feeds. This process produces various lighter, more valuable liquid hydrocarbon products, as well as a significant amount of fluidized coke as a by-product. The fluidized coke by-products contain high carbon content and various impurities. The distinguishing feature of fluidized coke is that the decarbonation process occurs in a fluidized bed (continuous) process, where the materials are mixed and cycled all the time during the reaction process, as opposed to delayed coke, which forms a spent carbon bed in a batch process.

The term "flexible coke" and grammatical variations thereof refers to materials produced by modified variants of fluid coking, known as FLEXICOKING ^TMTM (trademark of ExxonMobil research and engineering company "). Fleximaging ^TM is based on the fluidized bed technology developed by ExxonMobil and is a decarbonization process for upgrading heavy hydrocarbon feeds. Unlike fluid coking, which uses a reactor and a burner, the FLEXICOKING ^TM process uses a reactor, a heater, and a gasifier.

As used herein, with respect to the density of the proppant particulates, the term "apparent density" refers to the density of the proppant pack, which may be expressed in units of g/cm ³. The apparent density of the present disclosure is measured in a helium (He) -based pycnometer assay.

As used herein, with respect to the density of the proppant particulates, the term "bulk density" and grammatical variations thereof refers to the density of the proppant pack, which may be expressed in units of g/cm ³. The bulk density values of the present disclosure are based on API RP-19C (2020) entitled "Measurement of Proppants Used in Hydraulic Fracturing AND GRAVEL-packing Operations [ measurement of proppant used in hydraulic fracturing and gravel packing operations ]".

The term "carbon to hydrogen ratio" or "C/H ratio" and grammatical variations thereof refers to the amount of elemental carbon to elemental hydrogen in a petroleum composition. The C/H ratio was measured according to ASTM D5373-21 entitled "Test Methods for Determination of Carbon,Hydrogen and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke[ Standard test method for determining carbon, hydrogen and Nitrogen in coal analysis samples and carbon in coal and Coke analysis samples ] ".

As used herein, the term "thermogravimetric analysis" or "TGA" and grammatical variations thereof refers to the weight loss of a sample as a function of temperature (°c) and is expressed as% degradants.

As used herein, the term "nanoindentation" and grammatical variations thereof refers to a method of measuring a mechanical property of a material. Nanoindentation measurements according to the present disclosure were performed using a nanoindenter equipped with a diamond Berkovich tip geometry that was driven onto the proppant particle surface within an 8 x 8 square grid of points spaced about 6 μm from point to point. The reduced elastic modulus (E _r) and the localized hardness (H) are two mechanical properties determined by nanoindentation measurements, defined mathematically in equations 4.1 and 5. The material modulus can be approximated by a compromise in elastic modulus, with the limitation that the nanoindenter modulus is large compared to the material under study. The local hardness is defined as the ratio of the maximum load to the indentation contact area.

As used herein, the term "fracture conductivity" refers to the degree to which fluid flows in a proppant-fillable fracture. It is a stress-dependent quantity and is generally evaluated at various stress (pressure) levels. Fracture conductivity values of the present disclosure are based on american petroleum institute recommended practice 19D (API RP-19D) standards, titled "Measuring the Long-Term Conductivity of Proppants [ measure long term conductivity of proppants ]" (first edition, month 5 of 2008, month 5 of 2015 reconfirming).

As used herein, with respect to proppant particulates, the term "crush strength" refers to the stress load that the proppant particulates can withstand prior to crushing (e.g., breaking or cracking). The crush strength values of the present disclosure are based on API RP-19C.

All numbers in the detailed description and claims herein are modified by the term "about" or "approximately" to the indicated value and account for experimental errors and deviations that would be expected by one of ordinary skill in the art.

As used in this disclosure and the claims, the singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise.

The term "and/or" as used in the phrase, e.g., "a and/or B" herein is intended to include "a and B", "a or B", "a" and "B".

Proppants, methods and systems

Hydraulic fracturing operations require effective proppant particulates to maintain permeability and conductivity of the production well, such as for effective hydrocarbon recovery. Effective proppant particulates are generally associated with a variety of specific characteristics or properties, including efficient transport of the proppant particulates within the carrier fluid, sufficient crush strength to maintain a fracture that is supported upon removal of hydraulic pressure, and efficient conductivity once the wellbore begins to produce.

The rate of settling of the proppant particulates within the fracturing fluid at least partially determines its transport capacity within the one or more fractures created during the hydraulic fracturing operation. Equation 1 may be used to determine the settling rate of the proppant particulates:

Wherein v is a proppant particle; ρ _p-ρ_f is proportional to the density difference between the proppant particles and the carrier fluid; η is the viscosity of the carrier fluid; g is the gravitational constant; and σ ² is proportional to the square of the proppant particle size. As will be appreciated, proppant particulates having a lower apparent density and/or smaller average particle size settle at a slower rate (and thus have better transport) within the same carrier fluid than proppant particulates having a higher apparent degree and/or larger average particle size.

Proppant particle efficacy is also related to fracture conductivity, which is characterized by the fluid flow rate in propped fractures under gradient pressure, which are propped by the proppant pack. Fracture conductivity C _f is the product of proppant pack permeability k and its thickness h and can be determined using equations 2 and 3:

c _f = kh equation 2,

Wherein C is a constant; phi is the proppant pack void fraction; σ is the average particle size diameter of the proppant particulates; and Φ is a shape factor related to the non-sphericity of the proppant particulates. Fracture conductivity favors proppant particulates with larger average particle size diameters, as well as thick proppant packs and narrow particle size distributions, in the contradictory relationship of settling rate and transport.

Fracture conductivity is related to the mechanical properties of the proppant particulates. Nanoindentation analysis according to the Oliver-Pharr protocol can be used to characterize these properties to obtain local mechanical properties of the proppant particulates. The nanoindenter uses a calibrated diamond tip to form a measured indentation on the surface of the material to establish a load-displacement curve. The load (P) -displacement (h) curve is established by bringing the tip of the nanoindenter into contact with the surface of the material to a maximum force and then retracting the tip. The stiffness (S) is experimentally determined as the slope of the load-displacement curve during initial unloading, and the compromise elastic modulus is determined via the relationship according to equation 4:

Where a (h) is the projected area of the nanoindenter tip and is a known function of penetration depth for a given geometry. The reduction modulus E _r is related to the Young's modulus E _S of the test sample according to equation 4.1:

Where E _s and v _s are the Young's modulus and Poisson's ratio of the proppant particle sample, and E _i and v _i are the Young's modulus and Poisson's ratio of the indenter tip. For diamond indenter, E _i =1140 GPa and v _i =0.07 and terms Is negligible for the samples of interest herein.

The local hardness (H) of the material is determined according to equation 5:

Where P _max is the maximum load and A is the contact area established by the nanoindenter tip at the maximum applied load.

As provided above, it has been shown that typical delayed cokes exhibit poor mechanical quality compared to fluidized and flexible cokes, with the result of reduced fracture conductivity. Several significant differences are noted with delayed versus flexible coke, among others as described herein.

First, the size and shape of the delayed cokes are significantly different compared to fluidized cokes and flexible cokes. Fluidized and flexible coke particles are more round and spherical in nature due to the environment in which they are formed and the majority of the size distribution of the particles lies between 100 and 500 micrometers (μm), which has been within the range of interest for proppant particles used in fracturing operations. In contrast, shot coke (in the form of delayed coke) is formed, for example, as an aggregate of generally spherical shapes ranging between 1 millimeter (mm) and 4.5mm (e.g., about the diameter of a golf ball). Accordingly, it is desirable to reduce the particle size for use as proppant particulates (e.g., by ball milling, jet or hammer milling or grinding). Such grinding (or milling) to the proppant particle size range results in less round, angular particles, and also results in a large amount of smaller fines, which can interfere with fracture conductivity.

Figures 1A-1C illustrate the above-described size and shape differences, providing images comparing shot coke (representing delayed coke) and fluidized coke (also representing flexible coke). Fig. 1A shows an image of shot coke present when the coking process is completed. As noted above, the size of the generally spherical aggregates is quite large (1 mm to 4.5 mm). Fig. 1B and 1C show polarized light micrographs of ground shot coke and fluidized coke, respectively. The ground shot coke was mechanically screened to obtain a 100 mesh size sample. The bulk density of the milled shot coke of fig. 1B was measured to be 0.62 grams/cubic centimeter (g/cm ³) to 0.64g/cm ³, whereas the bulk density of the milled fluidized coke of fig. 1C was measured to be 0.76g/cm ³ to 0.86g/cm ³. This is a result of the greater angular nature of the abrasive particles, which are less efficiently packed together and result in a lower density than the more spherical particles comprising fluidized coke. Furthermore, as can be seen in fig. 1B, even with fine mechanical sieving, it is challenging to remove very fine particles from the ground material. The retained particles can be shown to significantly interfere with fracture conductivity.

The second significant difference in delayed versus both fluidized and flexible cokes is their volatile matter content. The volatile materials consist of heavy hydrocarbons in the petroleum coke particle matrix and in its pores and represent an incomplete conversion of the resid molecules into (relatively) hydrogen-deficient aromatic domains, which are structurally ordered into layered complexes. Delayed cokes typically have higher levels of volatiles than both fluidized and flexible cokes. Indeed, delayed cokes typically have a volatile matter content in the range of about 8 wt% to about 15 wt%, while fluidized cokes and flexible cokes typically have a volatile matter content in the range of about 2 wt% to about 6 wt%, which may be due to the relatively higher thermal intensity (THERMAL SEVERITY) of the coking process of fluidized cokes and flexible cokes compared to delayed coking. Higher volatile content means lower degree of polymerization and graphitization and may be at least in part responsible for the lower mechanical strength associated with delayed coke.

Without being bound by theory, due to the differences described above, and other differences not described herein, a typical delayed coke is observed to have less mechanical strength, and thus less fracture conductivity, to be used as a proppant particle, than fluidized and flexible cokes, and conventional proppant particles (e.g., sand). Such results can be observed in fig. 2, illustrating the fracture conductivity of 100 mesh shot coke compared to each of fluidized coke, flexible coke, and conventional sand, as measured by the recommended practice set forth by API RP 19D, as described in example 1. In short, fluidized coke, flexible coke, and sand exhibit similar fracture conductivity, while shot coke exhibits significantly reduced fracture conductivity, particularly as closure stress increases.

Accordingly, the present disclosure provides methods of enhancing or upgrading the mechanical properties of delayed cokes such that low density, inexpensive, and readily available materials can be effectively used as proppant particulates for hydraulic fracturing. In particular, the present disclosure provides for thermal post-treatment of delayed cokes, which may be advantageously performed as a supplement to removing fines generated during size milling to produce carbon-rich enhanced delayed coke materials suitable for use as proppant particulates. The resulting treated delayed cokes have similar mechanical properties as fluidized cokes and flexible cokes.

Referring now to fig. 3, a simplified flow diagram of a system 300 of the present disclosure for processing delayed cokes is illustrated. The delayed coke 302 is received from a conventional delayed coker system. The received delayed coke 302 is typically in the form of large agglomerates. Subsequently, the delayed coke 302 is milled 304 to the size of interest using one or more milling and/or grinding devices. The grinding and/or milling device is not considered to be particularly limited and may include, but is not limited to, a grinding wheel, ball mill, jet mill, hammer mill, or other suitable milling (grinding) device. In one or more aspects, the delayed coke 302 may be ground 304 to a size having an average diameter in the range of about 100 μm to about 600 μm, covering any value and subset therebetween, such as about 100 μm to about 400 μm, or about 200 μm to about 400 μm, or about 100 μm to about 200 μm.

With continued reference to fig. 3, after milling 304, heat treating 306 the milled delayed coke to a specified temperature and duration. The heat treatment may be carried out in any heater or kiln suitable for achieving the desired temperature. The heat treatment 306 is conducted to achieve pyrolysis-like conditions in one or more aspects of the present disclosure, which may be conducted in a kiln (e.g., rotary calciner _, the specific temperature and duration of the heat treatment 306 may depend on a number of factors including, but not limited to, the end product, the specific hydraulic fracturing operation for which the treated delayed coke proppant particulates are to be used, and the conditions associated therewith.

After heat treatment 306, the milled and heat treated delayed coke may be processed to remove fine particles 308. Such fines removal process 308 may be performed by any suitable separation device and is not considered to be particularly limited. In one or more aspects, for example, the separation device may include, but is not limited to, an elutriator, cyclone, flotation machine, or other separation apparatus. The fines removal process 308 is performed to minimize any particles that fall outside of a desired range (e.g., a desired range between about 100 μm to about 600 μm in average diameter size) during milling 304.

With continued reference to fig. 3, after the fines removal process 308, the coke material is screened 310 using a screening device to a particle size range of interest for the proppant particulates used during the hydraulic fracturing operation. The screening device is not considered to be particularly limited and examples include, but are not limited to, mechanical shakers, manual sieves, and the like. The size of the screen may be any size suitable for performance in a particular fracturing operation, such as, but not limited to, 30/50 mesh (300 μm to 600 μm), 40/70 (212 μm to 420 μm), 70/140 mesh (106 μm to 212 μm), and the like.

The final treated delayed coke proppant particulates 312 are thereafter obtained, having suitable mechanical properties for use in hydraulic fracturing operations.

It should be noted that fig. 3 is not the only method for performing the heat treatment enhancement of delayed cokes as provided herein. For example, each of steps 304-312 may be performed in any order without departing from the scope of the present disclosure. Furthermore, certain steps in fig. 3 may be repeated more than once (e.g., multiple milling devices may be used, multiple separation devices may be used, etc.), or alternatively, one or more steps may be combined into a single step (e.g., a heating device may also be used as one or both of the separation device and/or the screening device). That is, the process illustrated in FIG. 3 is non-limiting.

The thermally post-treated delayed coke proppant particulates of the present disclosure are formed using conventional delayed coking processes, as described herein, and are further thermally treated to a temperature in the range of about 400 ℃ to about 1000 ℃, or about 600 ℃ to about 800 ℃, covering any value and subset therebetween. The duration of the heat treatment may range from about 15 minutes to about 24 hours, or from about 1 hour to about 12 hours, or from about 1 hour to about 6 hours, or from about 1 hour to about 4 hours, covering any value and subset therebetween to achieve an improved mechanical response. The temperature and time are selected to achieve an improved mechanical response.

After milling, but before or after heat treatment, fines may be removed from the delayed coke for preparing the thermally post-treated delayed coke proppant particulates described herein. In one or more cases, the fines are removed such that no more than about 10% (including 0%) of the particles have a diameter less than the desired size range as described herein.

The thermally post-treated delayed coke proppant particulates may have a reduced elastic modulus in the range of about 5 gigapascals (GPa) to about 50GPa, such as about 10GPa to about 40GPa, inclusive of any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates may have a local hardness value in the range of about 1GPa to about 5GPa, such as about 2GPa to about 4GPa, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein may have a carbon content of from about 80 wt% to about 99.5 wt%, or from about 85 wt% to about 96 wt%, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein may have a carbon to hydrogen weight ratio of about 50:1 to about 120:1, or about 60:1 to about 98:1, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein can have a percent of degradants in the range of about 0% to about 3%, as measured by TGA, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein may have an impurity content (weight percent of all components except carbon and hydrogen) of from about 1wt% to about 15 wt%, or from about 3 wt% to about 10 wt%, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein may have a sulfur content of from 0 wt% to about 6 wt%, or from about 0.2 wt% to about 5wt%, covering any value and subset therebetween.

The thermally post-treated delayed coke proppant particulates described herein may have a nitrogen content of from 0 wt% to about 2 wt%, or from about 0.1 wt% to about 1 wt%, covering any value and subset therebetween.

The apparent density of the thermally post-treated delayed coke proppant particulates of the present disclosure can range from about 1.4 grams/cubic centimeter (g/cm ³) to about 2.1g/cm ³, or from about 1.4g/cm ³ to about 1.8g/cm ³, covering any value and subset therebetween. Conventional sand proppant particulates typically have an apparent density of greater than about 2.5g/cm ³. Thus, the thermally post-treated delayed coke proppant particulates described herein have a significantly smaller apparent density than conventional sand proppant particulates, indicating their relatively more efficient transport and lower sedimentation rate within the fracture formed as part of the hydraulic fracturing operation.

The bulk density of the thermally post-treated delayed coke proppant particulates can be less than about 0.7g/cm ³, for example in the range of about 0.5g/cm ³ to about 0.65g/cm ³, covering any value and subset therebetween.

Typical proppant particulates consist of sand having a particle diameter ranging from about 100 micrometers (μm) to about 1000 μm. The thermally post-treated delayed coke proppant particulates described herein are comparable in particle diameter size to conventional proppant particulates, having an average diameter of about 100 μm to about 500 μm, or about 100 μm to about 400 μm, or about 150 μm to about 350 μm, covering any value and subset therebetween.

As shown below, the deformation of the thermally post-treated delayed coke proppant particulates of the present disclosure may be at least partially size dependent. In some aspects, the crush strength of the thermally post-treated delayed coke proppant particulates described herein can be in the range of about 3000psi to about 12,000psi, or about 3000psi to about 6000psi, or about 5000psi to about 10,000psi, or about 7500psi to about 12,000 psi.

The long term fracture conductivity of the proppant pack containing the thermally post-treated delayed coke proppant particulates of the present disclosure is comparable to conventional sand proppant particulates, as well as fluidized coke and flexible coke proppant particulates, particularly at comparable particle sizes, as described herein.

The thermally post-treated delayed coke proppant particulates described herein may be used as part of a fracturing fluid comprising a flowable (e.g., liquid or gelled) carrier fluid and one or more optional additives. The fluid is typically formulated in a mixing process that is performed at the well site when pumped during hydraulic fracturing. When the fluid is formulated at the well site, the thermally post-treated delayed coke proppant particulates can be added in a similar manner to known methods for adding sand to fracturing fluids. In some aspects, it may be preferable to first process (e.g., at a manufacturing facility) the delayed coke proppant particulates received from the coking process to provide thermal post-treatment and/or to remove any undesirable size materials (fines) and then use them as proppant particulates. Optionally, the thermal post-treatment and/or fines removal may be performed at another facility, or in situ. For example, bag filters or other separation methods may be used to remove fines, whether in storage, during transport, or in the field, in order to obtain a more uniform size distribution. In addition to thermally post-treated delayed coke proppant particulates, it is within the scope of the present disclosure to include thermally post-treated delayed coke proppant particulates alone or in combination with one or more other types of proppant particulates (e.g., fluidized coke or flexible coke, and even conventional proppant particulates). When the thermally post-treated delayed coke proppant particulates are included in combination with another type of proppant particulates, the various proppant particulates may be mixed as dry solids, mixed in a slurry, or added separately to a fracturing fluid formulated at a facility or well site.

The carrier fluid of the present disclosure may be a water-based fluid or a non-water-based fluid. The water-based fluid may include, for example, fresh water, brine (including seawater), treated water (e.g., treated process water), other forms of aqueous fluid, and any combination thereof. One type of water-based fluid is commonly referred to as slick water (slickwater), and the corresponding fracturing operation is referred to as slick water fracturing. The non-aqueous based fluid may include, for example, oil-based fluids (e.g., hydrocarbons, olefins, mineral oils), alcohol-based fluids (e.g., methanol), liquefied or supercritical CO ₂ (carbon dioxide), and any combination thereof. In one or more aspects, the carrier fluid selected for use in the present disclosure is a water-based fluid.

In various aspects, the viscosity of the carrier fluid may be changed by foaming or gelation. Foaming may be achieved using, for example, air or other gases (e.g., CO ₂、N₂), alone or in combination. Gelation may be achieved using, for example, guar gum (e.g., hydroxypropyl guar), cellulose, or other gelling agents that may or may not be crosslinked using one or more crosslinking agents (e.g., multivalent metal ions or borate anions, among other suitable crosslinking agents). However, because the thermally post-treated delayed coke proppant particulates described herein have low densities, such viscosity modifying additives are generally avoided, thus reducing costs and potential damage to the wellbore.

In some cases, the carrier fluid used in hydraulic fracturing of horizontal wells is one or more water-based fluid types, particularly in view of the large volumes of fluid that are typically required for hydraulic fracturing. The water-based fluid may or may not be gelled, as described above. In some cases, the fracturing fluid may contain an aqueous-based carrier fluid (which may or may not be foamed or gelled) and an acid (e.g., HCl) to further promote and enlarge the pore area of the fracture surface matrix.

In addition, certain fracturing fluids suitable for use in the present disclosure may contain one or more additives, such as, for example, diluent aids, biocides, breakers (cutters), corrosion inhibitors, crosslinkers, friction reducers (e.g., polyacrylamides), gels, salts (e.g., KCl), oxygen scavengers, pH control additives, scale inhibitors, surfactants, weighting agents, inert solids, fluid loss control agents, emulsifiers, emulsion diluents, emulsion thickeners, viscosifiers, particulates, plugging materials, foaming agents, gases, buffers, stabilizers, chelating agents, mutual solvents, oxidizing agents, reducing agents, clay stabilizers, and any combination thereof.

The present disclosure includes methods of hydraulic fracturing using a fracturing fluid comprising thermally post-treated delayed coke proppant particulates alone or in combination with other proppant particulates during a hydraulic fracturing operation. That is, the thermally post-treated delayed coke proppant particulates may form an integral part of the proppant pack or may form an integral part of the proppant pack. Other proppant particle types that may be used with the thermal post-treatment delayed coke proppant particles described herein include, but are not limited to, conventional sand proppant particles described herein, as well as those made from bauxite, ceramic, glass, fluidized coke, flexible coke, and any combination thereof, and may or may not have surface modification. Proppant particulates composed of other materials are also within the scope of the present disclosure provided that any such selected proppant particulates (including those composed of the above materials) are capable of maintaining their integrity upon the induction of the intra-fracture removal of hydraulic pressure such that the particulate mass of about 80%, preferably about 90% and more preferably about 95% or more of the other proppant particulates remains intact when subjected to a stress of 5000psi (a requirement that the thermally post-treated delayed coke proppant particulates of the present disclosure also meet). That is, the thermally post-treated delayed coke proppant particulates and any other proppant particulates used in the methods described herein must maintain mechanical integrity as the fracture closes because any such type of particulates must mix or otherwise combine to form a functional proppant pack for successful hydraulic fracturing operations.

The methods described herein include the preparation of fracturing fluids, which are not considered to be particularly limited, as the thermally post-treated delayed coke proppant particulates can be transported from a manufacturing site (e.g., refinery or synthetic fuel plant) in dry form or as part of a wet slurry. The dry and wet forms may be transported by truck or rail, and the wet form may also be transported by pipeline. The transported dry or wet form of thermally post-treated delayed coke proppant particulates can be added to a carrier fluid including optional additives at the production site, either directly into the wellbore or by premixing in a hopper or other mixing device. In some aspects, for example, when all of the proppant particulates within the fracturing fluid at a given time are thermally post-treated delayed coke proppant particulates, a particulate block (slug) in dry or wet form may be added directly to the fracturing fluid (e.g., when it is introduced into the wellbore). These particle clumps of heat-treated delayed coke proppant particulates may be followed by the addition of heat-treated delayed coke proppant particulates alone, or the addition of subsequent particle clumps of heat-treated delayed coke proppant particulates and other proppant particulates. In other aspects, for example when other proppant particle types are combined with the flexible coke proppant particles, a portion or all of the fracturing fluid may be premixed at the production site, or each proppant type may be added directly to the fracturing fluid separately. Any other suitable mixing or addition of thermally post-treated delayed coke proppant particulates may also be used to produce the desired fracturing fluid composition without departing from the scope of this disclosure.

Hydraulic fracturing methods suitable for use in one or more aspects of the present disclosure include pumping a fracturing fluid containing thermally post-treated delayed coke proppant particulates into a subterranean formation at a high pumping rate to form at least a primary fracture, and potentially one or more secondary fractures extending from the primary fracture, one or more tertiary fractures extending from the secondary fracture, and the like (all collectively referred to as "fractures"). In a preferred aspect, this process is performed one stage at a time along the well. This stage is hydraulically isolated from any other stage that has been previously fractured. In one embodiment, the stage of fracturing has clustered perforations (e.g., perforations in the wellbore and/or subsurface formation) to allow hydraulic fracturing fluid to flow into the formation through the metallic tubular casing of the well. When drilling, such metallic tubular casings are installed as part of the completion and are used to provide mechanical integrity to the well. In some aspects, the pump rate used during hydraulic fracturing may be at least about 20 barrels (barrels)/minute (bbl/min), preferably about 30bbl/min, and more preferably more than 50bbl/min and less than 1000bbl/min for one or more durations during the fracturing operation (e.g., the rate may be constant, steadily increasing or pulsed). In some aspects, these high rates may be used after about 10% of the total volume of fracturing fluid to be pumped into the formation has been injected. That is, at an early stage of the hydraulic fracturing operation, the pump rate may be lower and as fracture(s) begin to form, the pump rate may be increased. In general, the average pump rate of the fracturing fluid throughout the operation may be about 10bbl/min, preferably about 15bbl/min, and more preferably more than 25 bbl/min and less than 250bbl/min. Typically, the pump rate during the fracturing operation is in the range of about 20bbl/min to about 150bbl/min, or about 40bbl/min to about 120bbl/min, or about 40bbl/min to about 100bbl/min for greater than 30% of the time required to complete the fracturing stage.

In various aspects, the hydraulic fracturing methods described herein may be performed in which the concentration of proppant particulates (including thermally post-treated delayed coke proppant particulates and any other proppant particulates) within the injected fracturing fluid is varied (i.e., the real-time (on-the-fly) variation is performed while the fracturing operation is performed such that hydraulic pressure is maintained within the formation and fracture (s)). For example, in some aspects, the initially injected fracturing fluid may be injected at a low pump rate and may contain from 0 volume percent (vol%) to about 1vol% proppant particulates. As one or more fractures begin to form and grow, the pump rate increases and the concentration of proppant particulates may increase in a stepwise manner (with or without a stepwise increase in pump rate), with a maximum concentration of proppant particulates reaching about 2.5% to about 20% by volume, covering any value and subset therebetween. For example, the maximum concentration of proppant particulates can reach at least 2.5% by volume, preferably about 8% by volume, and more preferably about 16% by volume. In some aspects, all of the proppant particulates are thermally post-treated delayed coke proppant particulates. In other aspects, at least about 2% to about 100% by volume of any proppant particulates suspended within the fracturing fluid during one or more time periods during the hydraulic fracturing operation are thermally post-treated delayed coke proppant particulates, such as at least about 2%, preferably about 15%, more preferably about 25%, and even more preferably 100%.

It should be noted that some or all of the thermally post-treated delayed coke proppant particulates may be coated. Coatings are often used on sand particles used in hydraulic fracturing to improve their flowability or to mitigate their flowback during production. Such types of coatings are within the scope of the present disclosure. Coated thermally post-treated delayed coke proppant particulates may be introduced at any stage of the hydraulic fracturing process, wherein the resulting composition is either a mixture of coated and uncoated thermally post-treated delayed coke proppant particulates or fully coated thermally post-treated delayed coke proppant particulates.

In one or more aspects, the thermally post-treated delayed coke proppant particulates may be introduced after about 1/8 to about 3/4 of the total volume of fracturing fluid has been injected into the formation. Since the thermally post-treated delayed coke proppant particulates have a low density, it may be advantageous to introduce the thermally post-treated delayed coke proppant particulates during a subsequent period of fracturing after which the fracture(s) have grown substantially so that the thermally post-treated delayed coke proppant particulates can move within the fracturing fluid to a remote location of the formed fracture(s). Denser proppant particulates will not reach these remote locations due to, for example, sedimentation effects.

The hydraulic fracturing methods described herein may be performed in drilled horizontal, vertical, or tortuous wellbores, hydrocarbon (e.g., oil and/or gas) producing wellbores, and water producing wellbores. These wellbores may be in various subterranean formation types including, but not limited to, shale formations, oil sands, gas sands, and the like.

Wellbores are typically completed using a metal (e.g., steel) tubular or casing that is secured in a subterranean formation. To contact the formation, a plurality of perforations, commonly referred to as bridge plugs (plugs) and perforations ("bridge plugs and perforations"), are created through the tubing and cement along the portion to be treated. Alternative completion techniques may be used without departing from the scope of the present disclosure, but in each technique, a limited length of wellbore is exposed for hydraulic fracturing and injection of fracturing fluids. This limited portion is referred to herein as the "stage". In bridge plugs and perforated completions, the stage length may be based on the distance the tubing and cement are run through and may be in the range of, for example, about 10 feet (ft) to about 2000ft, and more typically in the range of about 100ft to about 300ft, covering any value and subset therebetween. This stage is isolated (e.g., sliding sleeve, ball) so that pressurized fracturing fluid from the surface can flow through the perforations and into the formation, creating one or more fractures only in the region of this stage. Clustered perforations may be used to facilitate initiation of multiple fractures. For example, clustered perforations may be formed in stage sections having a length of about 1ft to about 3ft and spaced about 2ft to about 30ft apart, covering any value and subset therebetween.

For each linear foot stage, at least about 6 barrels (about 24 cubic feet (ft ³)), preferably about 24 barrels (about 135ft ³), and more preferably at least 60 barrels (about 335ft ³) and less than 6000 barrels (about 33,500ft ³) of fracturing fluid may be injected to grow one or more fractures. In some aspects, at least about 1.6ft ³, preferably about 6.4ft ³, and more preferably at least 16ft ³ and less than 1600ft ³ of proppant particulates may be injected to support the fracture for each linear foot stage. In some aspects, to prevent hanging of proppant particulates during injection into the fracture, the volume ratio of proppant particulates to the liquid portion of the fracturing fluid (primarily carrier fluid) is greater than 0 and less than about 0.25 and preferably less than about 0.15. If the volume ratio becomes too large, a phenomenon called "sand removal (sanding out)" will occur.

Some commercial operations, such as commercial shale fracturing operations, may be particularly suitable for hydraulic fracturing using the delayed coke proppant particulates and methods described herein for thermal aftertreatment, as the mass of proppant particulates required at each stage in such operations may be substantial and significant economic benefits may be obtained using the delayed coke proppant particulates. The cost of the delayed coke as a source of delayed coke proppant particulates for the thermal aftertreatment can be less than the cost of sand and significantly less than the lower density proppant particulates, which provides significant economic benefits. Indeed, in some cases, stages in the shale formation may be designed to require at least about 30,000, preferably about 100,000, and more preferably about 500,000 pounds (mass) of proppant particulates. In such cases, economic and performance benefits may be optimized when at least about 5%, preferably greater than about 25% and up to 100% of the proppant particle mass comprises thermally post-treated delayed coke proppant particles.

The multiple stages of the wellbore are isolated and hydraulic fracturing is performed at each stage. The thermally post-treated delayed coke proppant particulates of the present disclosure can be used in any, multiple, or all of the more stages, including at least 2 stages, preferably at least 10 stages, and more preferably at least 20 stages.

Example embodiment

Non-limiting example embodiments of the present disclosure include:

Embodiment 1. Fracturing fluid comprising: a carrier fluid; and thermally post-treated delayed coke proppant particulates, wherein the thermally post-treated delayed coke proppant particulates comprise delayed coke that has been thermally post-treated to a temperature in the range of about 400 ℃ to about 1000 ℃ for a predetermined duration and milled to a predetermined average size diameter, in any order.

Embodiment 2. The fracturing fluid of embodiment 1, wherein the predetermined duration is in the range of about 15 minutes to about 24 hours.

Embodiment 3. The fracturing fluid of embodiment 1 or 2, wherein the predetermined average particle size distribution is in the range of about 100 microns to about 600 microns.

Embodiment 4. The fracturing fluid of embodiments 1-3 wherein the thermally post-treated delayed coke proppant particulates have an apparent density in the range of about 1.4g/cm ³ to about 2.1g/cm ³.

Embodiment 5. The fracturing fluid of embodiments 1-3 wherein the thermally post-treated delayed coke proppant particulates have a bulk density of less than about 0.7g/cm ³.

Embodiment 6. The fracturing fluid of any of embodiments 1-5, wherein the thermally post-treated delayed coke proppant particulates have a reduced elastic modulus in the range of about 5 gigapascals to about 50 gigapascals.

Embodiment 7. The fracturing fluid of any of embodiments 1-6, wherein the thermally post-treated delayed coke proppant particulates have a hardness value in the range of about 1 gigapascal to about 4 gigapascal.

Embodiment 8 the fracturing fluid of any of embodiments 1-7, wherein the thermally post-treated delayed coke proppant particulates have a carbon to hydrogen weight ratio of from about 50:1 to about 120:1.

Embodiment 9. The fracturing fluid of any of embodiments 1-8, wherein the thermally post-treated delayed coke proppant particulates have a percent degradable in the range of about 0% to about 3% as determined by thermogravimetric analysis.

Any combination of embodiments 1-4 and 6-9 is within the scope of the present disclosure without limitation. Any combination of embodiments 1-3 and 5-9 is within the scope of the present disclosure without limitation.

Embodiment 10. Method comprising: introducing a fracturing fluid into the subterranean formation, the fracturing fluid comprising a carrier fluid and thermally post-treated delayed coke proppant particulates, wherein the thermally post-treated delayed coke proppant particulates comprise delayed coke that has been thermally post-treated to a temperature in the range of about 400 ℃ to about 1000 ℃ for a predetermined duration and milled to a predetermined average size diameter, in any order.

Embodiment 11 the method of embodiment 10, further comprising removing at least a portion of the fines having an average particle size distribution of less than about 20 microns prior to introducing the fracturing fluid into the subterranean formation.

Embodiment 12 the method of embodiments 10-11, further comprising depositing at least a portion of the thermally post-treated delayed coke proppant particulates within one or more fractures in the subterranean formation to form a proppant pack.

Embodiment 13. The method of embodiments 10-12, wherein the predetermined duration is in a range of about 15 minutes to about 24 hours.

Embodiment 14. The method of embodiments 10-13, wherein the predetermined average particle size distribution is in a range of about 100 microns to about 600 microns.

Embodiment 15. The method of embodiments 10-14, wherein the thermally post-treated delayed coke proppant particulates have an apparent density in the range of from about 1.4g/cm ³ to about 2.1g/cm ³.

Embodiment 16. The method of embodiments 10-14, wherein the thermally post-treated delayed coke proppant particulates have a bulk density of less than about 0.7g/cm ³.

Embodiment 17 the method of any of embodiments 10-16, wherein the thermally post-treated delayed coke proppant particulates have a reduced elastic modulus in the range of about 5 gigapascals to about 50 gigapascals.

Embodiment 18 the method of any of embodiments 10-17, wherein the thermally post-treated delayed coke proppant particulates have a hardness value in the range of about 1 gigapascal to about 4 gigapascal.

Embodiment 19 the method of any of embodiments 10-18, wherein the thermally post-treated delayed coke proppant particulates have a carbon to hydrogen weight ratio of from about 50:1 to about 120:1.

Embodiment 20 the method of any of embodiments 10-19, wherein the thermally post-treated delayed coke proppant particulates have a percent degradable in the range of about 0% to about 3% as determined by thermogravimetric analysis.

Any combination of embodiments 10-15 and 17-20 is within the scope of the present disclosure without limitation. Any combination of embodiments 1-14 and 16-20 is within the scope of the present disclosure without limitation.

In order to facilitate a better understanding of aspects of the present disclosure, the following examples of preferred or representative aspects are presented. The following examples should not be construed as limiting or restricting the scope of the present disclosure in any way.

Examples

In the following examples, various experiments were conducted and measurements were made to evaluate and verify the thermal post-treatment methods of delayed cokes described herein such that the treated delayed cokes exhibited mechanical properties suitable for use as proppant particulates during hydraulic fracturing operations.

Example 1: fracture conductivity comparison

In this example, the crack conductivity of 100 mesh samples of sand control (CT 1), fluidized coke (FC 1), flexible coke (FX 1) and two shot coke (representing delayed coke) samples were collected from different sources (DC 1 and DC 2). Each of DC1 and DC2 was ground to obtain a 100 mesh sample.

Fracture conductivity was determined using proppant pack sandwiched between Ohio sandstone cores, with a proppant particle loading of 2 pounds per square foot (lb/ft ²) of fracture surface. The system was allowed to relax at 150 ^° F (65.6 ℃) under a confining stress of 1000 pounds per square inch (psi) and the permeability of the proppant pack was measured by cross-flowing a 2% kcl aqueous solution under a small pressure gradient. Permeability multiplied by pack height and reported as fracture conductivity, measured in millidarcy feet (mD-ft).

During testing, the applied stress (closure stress) was increased from 2000psi to 8000psi at 2000psi intervals, and the system was allowed to relax for about 50 hours before the conductivity was measured at the stress level of interest. Fig. 2 illustrates a graph representing fracture conductivity results. As shown, the fluidized coke (FC 1) and flexible coke (FX 1) samples have similar conductivity characteristics as the control sand (CT 1) typically used in hydraulic fracturing operations; however, shot coke samples (DC 1 and DC 2) both exhibited poor properties, especially at higher closure stresses. Note that the asterisks indicate the minimum recommended fracture conductivity at 6000psi closure stress.

Example 2: influence of grinding (milling) and fines on fracture conductivity

In this example, the relative importance of the grinding, particle shape, and fines characteristics of the proppant particulates to fracture conductivity was evaluated. In this example, a fluidized coke sample (FC 2) was compared to a conventional sand sample (CT 2). The results are shown in FIG. 4 after (1) 40/70 mesh (no milling), (2) 100 mesh (no milling), (3) 100 mesh (40/70 mesh sample milled with high speed rotary mill and separating the sample portion between 70/100 mesh), and (4) removal of fines by elutriation of the milled 100 mesh sample (from (3)).

As shown, the clean 40/70 mesh (no grind) sample exhibited higher conductivity than the corresponding clean 100 mesh (no grind) sample. The 100 mesh (after grinding but without sieving) samples showed lower conductivity and higher levels of stress dependence-and conductivity loss-compared to the neat 100 mesh (without grinding) samples. However, after removal of fines from the ground 100 mesh sample, the FC2 sample showed similar crack conductivity to the clean 100 mesh (no grinding) sample, and the CT2 sample showed similar crack conductivity to the clean 40/70 mesh (no grinding) sample. Thus, removal of fines from the ground sample shows an improvement in fracture conductivity.

Example 3: influence of size and shape on fracture conductivity

In this example, the proppant particle size and shape distributions of FC2 (fluidized coke) and CT2 (conventional sand) of example 2 were characterized using automated digital imaging microscopy to measure cumulative distribution function statistics for circle equivalent diameters. In particular, each of FC2 and CT2 was evaluated using the following samples: (2) 100 mesh (no grinding), (3) 100 mesh (after grinding 40/70 mesh sample with high speed rotary mill and separating sample portion between 70/100 mesh), and (4) after removing fines by elutriation of the ground 100 mesh sample of example 2 (from (3)), i.e., 40/70 mesh (no grinding) sample (1) of example 2 was not evaluated in this example.

The results of the proppant particle size distribution are shown in fig. 5, with the volume weighted statistics provided in the large plot and the corresponding particle number weighted distribution provided in the insert. As shown, very small differences were observed in the overall distribution of each of the 100 mesh samples of FC2 and CT 2; however, when the distribution is detected on the basis of particle count, as shown in the inset of fig. 5, it can be seen that most of the sample consists of very small particles with equivalent diameter <20 microns. Furthermore, as shown, while the vast majority of the mass of each of the FC2 and CT2 samples was in the 100 mesh range, comparing a clean 100 mesh (no grinding) sample to a 100 mesh (grinding but no sieving) it is evident that the grinding sample has a significantly higher fines content and thus has a negative impact on the overall fracture conductivity.

The results of the proppant particle shape distribution are shown in fig. 6, with volume weighted statistics provided in the large graph and corresponding particle number weighted distributions provided in the inset. As shown, the shape of the proppant particulates (if any) will have minimal impact on fracture conductivity on a volumetric basis, as the aspect ratio is relatively similar in all 100 mesh samples for both FT2 and CT 2. However, as with the size distribution discussed above, when comparing a neat 100 mesh (no grind) sample to a100 mesh (post grind but no sift) sample, it is apparent that the grind sample has a greater number of smaller, vertically and horizontally proppant particulates due to the presence of fines (inset of fig. 6). Thus, it can be inferred that the fine powder removal after grinding has a greater effect on fracture conductivity than the shape of the proppant particulates themselves (see also fig. 4).

Example 4: effect of heat post-treatment

In this embodiment, the effect of the thermal post-treatment method of the present disclosure was evaluated based on several criteria. Two shot coke (representing delayed coke) samples DC1 and DC2 derived from the same source as example 1 were evaluated and compared to fluidized coke sample FC2 of example 1 and/or conventional sand CT2 of examples 2 and 3. The properties of each sample type were evaluated as a function of the strength of the thermal post-treatment process described herein. Each sample was heated to the target temperature in a tube furnace, as described above, for 1 hour and allowed to cool completely before removal. The samples were immersed in a stream of N ₂ gas during the heat treatment to achieve pyrolysis conditions. Subsequently, the samples were evaluated.

C/H ratio and TGA

In this example, a composition index of the heat treated sample of DC2 was analyzed that was expected to evolve as the heat treatment varied. The C/H ratio of the heat treated samples was measured by inductively coupled plasma atomic emission spectrometry (ICP-AES) and the volatile matter content was characterized by thermogravimetric analysis (TGA). In the TGA method employed herein, a small amount of sample is immersed in flowing N ₂ and subjected to a defined temperature rise from room temperature to 800 ℃, thereby releasing volatile components of the sample by various mechanisms. Volatile materials, or% degradants as shown in fig. 7B, are defined as mass loss of the sample between 110 ℃ and 1000 ℃. The results are shown in fig. 7A and 7B, respectively, wherein the results for samples heat treated at a holding temperature between 600 ℃ and 1000 ℃ are shown, compared to the baseline value of fluidized coke, and wherein the dashed line shows the C/H ratio or TGA of unground DC2 and FC2 (in the as received state) without heat treatment and is thus not related to the temperature increase.

As shown, in fig. 7A, the C/H ratio of ground DC2 steadily increased with heat treatment, because volatiles were released from the material, approximately 700 ℃ reached a level comparable to FC 2. Fig. 7B shows a continuous decrease in the residual volatile content in the sample after heat treatment, wherein the ground DC2 decreases below the FC2 level at heat treatment between about 600 ℃ and 650 ℃. It is also notable that the weight loss of DC2 ground during heat treatment is relatively small, ranging from about 3.3wt% at 600 ℃ to about 8.9 wt% at 800 ℃.

Thus, with increased temperature, delayed coke may achieve the same or better C/H ratio and TGA% degradants than fluidized coke (and flexible coke).

Apparent density of

In this example, we demonstrate that heat treatment from the previous example results in only a modest increase in apparent density. The apparent densities of 40/70 mesh ground DC1 and ground DC2 samples were evaluated using He pycnometer after heat treatment at a holding temperature between 500 and 800℃and compared to the received DC2 and FC 2. The results are shown in fig. 8, wherein the results between 600 ℃ and 800 ℃ are shown based on the baseline value of the fluidized coke, and wherein the horizontal dashed line shows the apparent densities of DC2 and FC2 in the receiving state without heat treatment and is thus not related to the temperature increase. For further comparison, the diagonal dashed line shows the apparent density of a commercially available 3.2 wt% S petroleum coke heated to the target temperature at 150 ℃/min, as reported in D.Kocaefe, A.Charette and L.Castonguay,Green coke pyrolysis:investigation of simultaneous changes in gas and solid phases,Fuel,74(6):791–799,1995.

The apparent density of ground DC1 and DC2 began to increase above 500℃and increased by about 15% at 700 ℃. Comparing ground DC1 and ground DC2, the heat treated shot coke showed negligible differences in behavior, albeit from two different sources. The apparent densities of the ground DC1 and ground DC2 samples crossed at about 600 ℃ compared to FC 2. Furthermore, the heat post-treatment method of the present disclosure shows the effect of the heating rate and overall heat intensity of the heat treatment process, as compared to the data of commercially available 3.2 wt% S petroleum coke. Typical calcination of petroleum green coke for use in anode manufacture will reach 1300 ℃ and achieve an apparent density of about 2.1g/cm ³ and a material loss of 15 to 25 wt% on a dry basis. Because it is desirable to have low density proppant particulates, it is apparent that heat treatment in the 700 ℃ range results in only modest density increases and material losses.

Nanoindentation

In this example, the mechanical properties of a thermally post-treated shot coke (representing delayed coke) sample of DC2 ground to 100 mesh and heat treated (at 1 hour or 4 hour duration) between 600 ℃ and 1000 ℃ were compared to conventional sand CT3, fluidized coke sample FC1 of example 1, and epoxy resin of the installed sample, as described below.

The samples were cast in epoxy as 1 inch diameter billets and polished smooth to expose flat grain (cross-sectional surface) for indentation. As described above, and as shown in fig. 9A, nanoindentation was performed using a nanoindenter equipped with a diamond Berkovich tip. Ten (10) different proppant particulates were sampled at each temperature to collect statistics of the average modulus and hardness properties, as well as their standard deviation. Fig. 9B shows a residual indentation formed on a DC2 shot coke sample according to the present embodiment.

The nanoindentation results are shown in fig. 10A and 10B, where fig. 10A shows the reduced elastic modulus results and fig. 10B shows the hardness results.

As shown in fig. 10A, the non-heat post-treated (as received) DC2 sample had a modulus of 3-4 gigapascals (Gpa) similar to the results of the epoxy resin alone. As the temperature increases, or the duration of the same temperature increases, the modulus increases to a value similar to that of FC1 fluidized coke, reaching the same value between about 700 ℃ and 800 ℃. Heat treatment to higher temperatures did not show a significant increase in modulus. While the heat post-treated heated DC2 sample has a smaller modulus than CT3 conventional sand, it does exhibit a modulus comparable to FC1, FC1 being a validated material for proppant particulates during fracturing operations.

Referring now to fig. 10B, the non-heat post-treated (as received) DC2 sample exhibited approximately twice the hardness compared to the hardness of the epoxy resin alone, with a hardness of about 0.2Gpa. Similar to modulus, as the heat treatment temperature increases, or the duration of the same temperature increases, the hardness of the DC2 heat treated sample increases to a value similar to that of FC1 fluidized coke, reaching the same value between about 700℃ and 800℃. The heat treatment to higher temperatures did not show a significant increase in hardness, but a slight increase was observed. While the heat treated DC2 sample has a smaller hardness than CT3 conventional sand, it does exhibit a hardness comparable to FC1, FC1 being a validated material for proppant particulates during fracturing operations.

Uniaxial compression

In this example, shot coke (representative of delayed coke) samples described above were uniaxially compressed using a pellet die compression test. Approximately 1 gram of each sample was loaded into a 0.5 inch diameter pellet die and compacted before being placed in the dieCompression in a (norwood, ma) load frame. The sample was compressed to 7500 newtons (N) (approximately 8600 psi) at a rate of 0.15 millimeters per minute (mm/min). Stress-strain curves for various shot coke 40/70 mesh samples are shown in fig. 11, where the curves have been shifted to a reference state where the applied stress is 1000 psi. DC2 is 40/70 mesh and heat post-treating two DC2 samples at 650℃and 700 ℃; each test was performed twice. As shown in fig. 11, the heat-post-treated DC2 samples showed improved compression (greater stiffness) compared to the non-heat-post-treated controls. Sample FX2 is a 40/70 mesh sample of flexible coke, shown for comparison. It can be seen that the overall compression behavior of the heat treated shot coke (delayed coke) sample is very similar to that of the flexible coke.

Fracture conductivity

In this example, the crack conductivity of a 40/70 mesh sample (DC 2) of shot coke (representative of delayed coke) with various thermal post-treatments and/or fines removal (labeled "+ fines removal" in fig. 12A and 12B) was examined and compared to a sample without thermal treatment and without fines removal.

Fracture conductivity was determined using proppant pack sandwiched between Ohio sandstone cores, with a proppant particle loading of 1.7lb/ft ² of fracture surface, unless otherwise indicated. The system was allowed to relax at 150°f under a confining stress of 1000 pounds per square inch (psi) and the permeability of the proppant pack was measured by cross-flowing a 2% kcl aqueous solution under a small pressure gradient. Permeability multiplied by pack height and reported as fracture conductivity, measured in mD-ft.

During testing, the applied stress (closure stress) was incrementally increased from 1000psi to 8000psi at 2000psi intervals, and the system was allowed to relax for about 50 hours before the conductivity was measured at the stress level of interest. Fig. 12A illustrates a graph representing fracture conductivity results. As shown, shot coke (DC 2) heat post-treated and treated to remove fines showed greater conductivity than the baseline sample (no heat treatment and no fines removal). Furthermore, the heat post-treated DC2 samples showed greater conductivity than the baseline samples even without fines removal.

As an additional comparison, the crack conductivity of shot coke samples treated at 700 ℃ and with fines removed (DC 2-700 ℃ + fines removal) was compared to untreated shot coke samples (DC 2-no heating), three separate fluidized coke type samples (FC 1, FC2 and FC 3) and flexible coke sample (FX 2). Fracture conductivity testing was performed as described above at a fracture surface loading of 2lb/ft ² proppant particulates. The results are shown in fig. 12B.

As shown in fig. 12B, the thermally post-treated DC2 samples exhibited comparable performance to fluidized coke and flexible coke, which are known to possess the mechanical properties necessary for performance as proppants.

Thus, the thermally post-treated delayed coke proppant particulates of the present disclosure are suitable for use in hydraulic fracturing operations.

As is apparent from the foregoing general description and specific embodiments, while the disclosed forms have been illustrated and described, various changes can be made without departing from the spirit and scope of the disclosure. Accordingly, it is not intended that the disclosure be limited thereby. For example, the compositions described herein may be free of any component or composition not explicitly recited or disclosed herein. Any method may lack any steps not recited or disclosed herein. Likewise, the term "comprising" is considered synonymous with the term "including". Whenever a method, composition, element or group of elements is preceded by the term "comprising" it should be understood that we also contemplate the same group of compositions or elements with the term "consisting essentially of", "consisting of", "selected from the group consisting of" or "being" followed by the recitation of the composition, element or elements, and vice versa.

Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the specification and claims are to be understood as being modified in all instances by the term "about". Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the embodiments of the present disclosure. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.

Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, each range of values disclosed herein (having the form "from about a to about b," or, equivalently, "from about a to b," or, equivalently, "from about a-b") should be understood to list each value and range encompassed within the broader range of values. Furthermore, the terms in the claims have their ordinary, ordinary meaning unless explicitly and clearly defined otherwise by the patentee. Furthermore, the indefinite articles "a" or "an" as used in the claims are defined herein to mean one or more than one of the element to which it is directed.

One or more illustrative embodiments are presented herein. In the interest of clarity, not all features of a physical implementation are described or shown in the present disclosure. It will be appreciated that in the development of any such actual embodiment, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related, business-related, government-related and other constraints, which will vary from one implementation to another. While a developer's efforts may be time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

Thus, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the disclosure. Embodiments of the illustrative disclosure herein may be suitably practiced in the absence of any element not specifically disclosed herein and/or any optional element disclosed herein.

Claims

1. A fracturing fluid comprising:

a carrier fluid; and

A thermally post-treated delayed coke proppant particle, wherein the thermally post-treated delayed coke proppant particle comprises a delayed coke that has been thermally post-treated to a temperature in the range of about 400 ℃ to about 1000 ℃ for a predetermined duration and a delayed coke milled to a predetermined average size diameter, in any order.

2. The fracturing fluid of claim 1, wherein the predetermined duration is in the range of about 15 minutes to about 24 hours.

3. The fracturing fluid of any of the preceding claims, wherein the predetermined average particle size distribution is in the range of about 100 microns to about 600 microns.

4. The fracturing fluid of any of the preceding claims, wherein the thermally post-treated delayed coke proppant particulates have an apparent density in the range of about 1.4g/cm ³ to about 2.1g/cm ³.

5. The fracturing fluid of any of the preceding claims, wherein the thermally post-treated delayed coke proppant particulates have a bulk density of less than about 0.7g/cm ³.

6. The fracturing fluid of any of the preceding claims, wherein the thermally post-treated delayed coke proppant particulates have a reduced elastic modulus in the range of about 5 gigapascals to about 50 gigapascals.

7. The fracturing fluid of claim 6, wherein the thermally post-treated delayed coke proppant particulates have a hardness value in the range of about 1 gigapascal to about 4 gigapascal.

8. The fracturing fluid of any of the preceding claims, wherein the thermally post-treated delayed coke proppant particulates have a carbon to hydrogen weight ratio of from about 50:1 to about 120:1.

9. The fracturing fluid of any of the preceding claims, wherein the thermally post-treated delayed coke proppant particulates have a percent degradable in the range of about 0% to about 3% as determined by thermogravimetric analysis.

10. The method comprises the following steps: introducing a fracturing fluid into the subterranean formation, the fracturing fluid comprising a carrier fluid and the thermally post-treated delayed coke proppant particulates of claim 1.

11. The method of claim 10, further comprising removing at least a portion of the fines having an average particle size distribution of less than about 20 microns prior to introducing the fracturing fluid into the subterranean formation.

12. The method of claims 10 and 11, further comprising depositing at least a portion of the thermally post-treated delayed coke proppant particulates within one or more fractures in the subterranean formation to form a proppant pack.

13. The method of claims 10-12, wherein the predetermined duration is in the range of about 15 minutes to about 24 hours.

14. The method of claims 10-13, wherein the predetermined average particle size distribution is in the range of about 100 microns to about 600 microns.

15. The method of claims 10-14, wherein the thermally post-treated delayed coke proppant particulates have one or more of the following properties:

(a) Apparent density in the range of about 1.4g/cm ³ to about 2.1g/cm ³

(B) A bulk density of less than about 0.7g/cm ³,

(C) The reduced modulus of elasticity is in the range of about 5 gigapascals to about 50 gigapascals.