RU2835795C1 - Hydraulic fracturing system and method (embodiments) - Google Patents

Abstract

FIELD: oil, gas and coke-chemical industry.

SUBSTANCE: invention relates to oil and gas industry. In particular, a method of hydraulic fracturing is disclosed, which includes dehydration of a mixture for hydraulic fracturing of a formation at a centralized facility, wherein dehydration includes removal of at least a portion of water from the mixture for hydraulic fracturing; use of a low-shear addition system at a centralized facility to add a friction-reducing additive to the mixture for hydraulic fracturing to obtain a mixture for hydraulic fracturing with reduced friction, wherein the low shear addition system comprises at least one ejector or at least one screw; transportation of the mixture for hydraulic fracturing with reduced friction from the centralized facility to at least one hydraulic fracturing site through at least one pipeline and injection of the mixture for hydraulic fracturing with reduced friction into the reservoir for intensification of at least one well at said at least one hydraulic fracturing site.

EFFECT: higher efficiency of hydraulic fracturing.

20 cl, 18 dwg

Description

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the priority and benefit of U.S. Provisional Patent Application No. 63/033,619, entitled “Distribution of Hydraulic Fracturing Fluids,” filed June 2, 2020, the contents of which are incorporated herein by reference in their entirety for all purposes.

LEVEL OF TECHNOLOGY

[0002] The present invention generally relates to adding low shear friction reducing additives to a water source at a central location, transporting the reduced friction water to a well site, and introducing the reduced friction water into a reservoir to stimulate a well.

[0003] This section is intended to familiarize the reader with various aspects of the technical field that may relate to various aspects of the present methods that are described and/or claimed below. It is believed that this description is useful in providing the reader with additional information to provide a better understanding of the various aspects of the present invention. Accordingly, it should be understood that these statements are to be read in this light and not as an acceptance of any kind.

[0004] Shale oil and shale gas are generally only economically viable in the United States and Canada, where hydrocarbon prices are favorable and the scale of operations allows fixed costs to be spread across the maximum number of activities while minimizing variable costs. In general, wells typically go through three planning stages (e.g., drilling, completion, and production) in the operator's decision-making process. Often, there is limited cooperation and knowledge sharing between departments and decision-making teams within the operator's organization. For example, completions engineers often do not communicate effectively with operations teams, and thus senior managers in the organization are forced to implement simple cost-cutting measures such as reusing produced water from hydraulic fracturing in the field.

Typically, oil and gas wells produce water along with the hydrocarbons. Both produced water and the returned fracturing fluid or "flowback" (e.g. typically 15-50% of the initial volume is returned, usually gradually mixed with the produced water) are considered oilfield waste and are therefore subject to regulatory restrictions on handling and disposal. Oil and gas producers often contract out the disposal and treatment of produced water to specialist water handling and disposal (WHD) firms. In many cases, the produced water is treated and injected into saltwater disposal (SWD) wells. This creates quite a bit of additional cost for the oil and gas producers. For example, each drilling site must have chemical and sand storage equipment (e.g., storage mechanisms such as tanks, containers, bins, etc.) and mixing equipment, such as for mixing chemicals and sand together. In addition, chemicals and sand must be transported to the drilling sites via trucks. With respect to sand transportation, sand is typically first transported from the quarry to a transfer station where trucks are loaded and the sand is transported to the drilling sites. These trucks must then return empty to the transfer station, doubling the distance that must be traveled for each delivery. In some areas, there are approximately 550 trucks per well per week (e.g., approximately 70 trucks per day per well). The delivery of chemicals to drilling sites is very similar to sand, except that chemicals may be delivered from multiple staging points, with each staging point using different transportation methods, such as flatbed shipping containers, shipping tanks, and/or specialized tanks.

Thus, it was recognized that improved decision-making systems for produced water were desirable.

For example, document US 2018/0187508 A1 discloses a device and method for distributing fluids in a wellbore, which uses a mixing unit to produce a fracturing fluid by mixing a fluid (e.g., water) with various additives, such as sand (or other proppant) and chemicals. The mixing unit may be provided at a remote location, and at least one transfer pump is provided for pumping the fracturing fluid through at least one pipeline to at least one fracturing site.

SUMMARY OF THE INVENTION

[0005] The essence of certain embodiments of the invention described herein is set forth below. It should be understood that these aspects are presented only to briefly familiarize the reader with the essence of some embodiments of the invention and that these aspects do not limit the scope of the present invention.

[0006] Certain embodiments of the present invention include a method that includes using low-shear addition systems at a centralized facility to add a friction reducing additive to a fluid to produce a low-friction fracturing mixture. The method also includes transporting the low-friction fracturing mixture from the centralized facility to at least one fracturing site. The method further includes pumping the low-friction fracturing mixture into a reservoir to stimulate at least one well at the at least one fracturing site.

[0007] Certain embodiments of the present invention also include a system that includes a low-shear addition system located at a centralized facility and configured to add a friction reducing additive to a fluid to produce a low-friction fracturing mixture. The system also includes at least one transfer pump configured to pump the low-friction fracturing mixture through at least one pipeline to at least one fracturing site.

[0008] Certain embodiments of the present invention also include a method that includes adding a friction reducing additive to a fluid to form a low-friction fracturing mixture using a low-shear addition system at a centralized facility. The low-shear addition system includes at least one ejector configured to disperse the friction reducing additive into the fluid. The method also includes transporting the low-friction fracturing mixture from the centralized facility to at least one fracturing site. The method further includes pumping the low-friction fracturing mixture into a reservoir to stimulate at least one well at the at least one fracturing site.

[0009] Various modifications of the features noted above may be made with respect to various aspects of the present invention. Additional features may also be included in these various aspects. These modifications and additional features may exist individually or in any combination. For example, various features described below in connection with one or more of the illustrated embodiments of the invention may be included in any of the above-described aspects of the present invention individually or in any combination. The summary of the invention presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the invention without limiting the claimed subject matter.

BRIEF DESCRIPTION OF GRAPHIC MATERIALS

[0010] Various aspects of the present invention may be better understood by reading the following detailed description and with reference to the drawings, in which:

[0011] Fig. 1 shows a drilling site with a drilling rig located above an underground formation that includes one or more oil and/or gas reservoirs;

[0012] Fig. 2 shows an illustrative life cycle of produced water at drilling sites;

[0013] Fig. 3 is a schematic illustration of a system in which the fracturing mixture is mixed in situ at fracturing sites in accordance with the life cycle shown in Fig. 2;

[0014] Fig. 4 illustrates a novel circular life cycle of produced water produced at well sites in accordance with embodiments of the present invention;

[0015] Fig. 5 is a schematic diagram of a system in accordance with the new circular life cycle shown in Fig. 4, in accordance with embodiments of the present invention;

[0016] Fig. 6 is a schematic diagram of various operational components of the centralized facility shown in Figs. 4 and 5, in accordance with embodiments of the present invention;

[0017] Fig. 7 is a schematic illustration of a sand quarry that utilizes non-conventional water (e.g., produced water or other non-fresh water) in sand mining operations, in accordance with embodiments of the present invention;

[0018] Fig. 8 is a conceptual illustration of how a dilution manifold of a centralized facility process equipment may dilute chemicals and sand into a resulting fracturing mixture in accordance with embodiments of the present invention;

[0019] Fig. 9 shows an illustrative dilution manifold receiving a flow of relatively pure liquid into a first flow conduit and a flow of concentrated liquid into a second flow conduit, in accordance with embodiments of the present invention;

[0020] Fig. 10 shows dewatering equipment of a process equipment of a centralized facility for dewatering a sand-containing stream for density control in accordance with embodiments of the present invention;

[0021] Fig. 11 shows a relatively long pipe that can be used to mix sand, chemicals and/or produced water to form a fracturing mixture, in accordance with embodiments of the present invention;

[0022] Fig. 12 illustrates a method including a collection point (e.g., a centralized facility) where materials (e.g., sand, chemicals, and/or produced water) are added together in desired proportions but not mixed together using conventional active mixing methods, in accordance with embodiments of the present invention;

[0023] Fig. 13 is a schematic illustration of a centralized facility in which a friction reducing additive can be added to a fluid to form a reduced friction fracturing mixture using a low shear addition system, in accordance with embodiments of the present invention;

[0024] Fig. 14 shows an ejector configured to be gravity fed from a solids dosing system or other transport mechanism in accordance with embodiments of the present invention;

[0025] Fig. 15 shows an ejector configured to pneumatically transport and disperse air and solid particles into a propellant fluid, in accordance with embodiments of the present invention;

[0026] Fig. 16 is a schematic diagram of a process control system in accordance with embodiments of the present invention;

[0027] Fig. 17 is a cross-sectional view of a pipeline that includes an outer pipe and an inner pipe disposed concentrically within the outer pipe for transporting a fracturing mixture with reduced friction, in accordance with embodiments of the present invention;

[0028] Fig. 18 is a cross-sectional view of a pipeline that includes an outer pipe and a plurality of inner pipes located within the outer pipe for transporting a fracturing mixture with reduced friction, in accordance with embodiments of the present invention.

DETAILED DESCRIPTION

[0029] One or more specific embodiments of the present invention will now be described. These described embodiments of the invention are provided solely as examples of the techniques disclosed herein. Furthermore, in order to provide a brief description of these embodiments of the invention, all features of an actual implementation of the invention may not be disclosed in this description. It should be understood that in developing any such actual implementation, as in any engineering or development project, numerous implementation-specific decisions must be made to achieve the designer's specific goals, such as to meet system-related or manufacturing constraints that may be different for each implementation. Moreover, it should be understood that such development work may be complex and time-consuming, but will nonetheless be routine design, fabrication, and manufacturing practice for those skilled in the art having the benefit of the present invention.

[0030] When introducing elements of various embodiments of the present invention, the singular forms "a", "an", and "having" are intended to include one or more such elements. The terms "comprising", "including", and "having" are inclusive and contemplate that there may be additional elements in addition to those listed. Furthermore, it should be understood that references to "one embodiment" or "an embodiment of the present invention" in this disclosure should not be construed as excluding the existence of additional embodiments of the invention set forth that also include the features.

[0031] As used herein, the terms "connect," "connection," "connected," "in connection with," and "connecting" mean "in direct connection with" or "in connection through one or more elements"; and the term "set" means "one element" or "more than one element." In addition, the terms "link," "linkage," "linked," "linked together," and "linked with" mean "directly linked together" or "linked together through one or more elements." As used herein, the terms "up" and "down," "uphole" and "downhole," "upper" and "lower," "top" and "bottom," and other similar terms denoting positions relative to a given point or element are used to more clearly describe certain elements. Typically, these terms refer to the reference point on the surface from which drilling operations commence, which is the top (e.g., uphole or upper) point, and the total depth along the drilling axis is the lowest (e.g., downhole or upper) point, regardless of whether the borehole (e.g., wellbore, borehole) is relative to a vertical, horizontal, or inclined surface.

[0032] As used herein, the term "fracture" shall be understood as one or more faults or fracture surfaces in a rock. Fractures can significantly increase the permeability of rocks by connecting pores to each other, and for this reason, in some reservoirs, fractures may be mechanically induced to enhance hydrocarbon flow. Some fractures may also be referred to as natural fractures to distinguish them from fractures formed as a result of stimulation. Fractures may also be grouped into fracture clusters (or "perforation clusters"), where the fractures of a given fracture cluster (perforation cluster) connect to the wellbore through a single perforation interval. In the context of this document, the term "hydraulic fracturing" refers to the process and methods of breaking a geological formation and creating a fracture (i.e., the rock around a wellbore) by injecting fluid at relatively high pressures (e.g., pressures above a certain closure pressure) in order to increase production from a hydrocarbon reservoir.

[0033] Furthermore, as used herein, the terms "real time," "in real time," or "substantially real time" may be used interchangeably and are used to describe operations (e.g., computing operations) that are performed without any human-perceivable interruption between the operations. For example, as used herein, data related to the systems described herein may be collected, transmitted, and/or applied in control computing "in substantially real time" such that the data reading, data transmission, and/or data processing steps occur once per second, once every 0.1 seconds, once every 0.01 seconds, or even more frequently during the operations of the systems (e.g., during the operation of the systems). Furthermore, as used herein, the terms "automatic" and "automated" are intended to describe operations that are performed or caused to be performed, for example, by a process control system (i.e., solely by the process control system, without human intervention).

[0034] Typically, oil and gas wells produce water along with the hydrocarbons in one form or another. Both the produced water and the returned fracturing fluid or "flowback" (e.g., typically 15-50% of the initial volume is returned, usually gradually mixing with the produced water) are considered oilfield waste and are therefore subject to regulatory restrictions regarding handling and disposal. In Fig. 1 shows a drilling site 10 with a drilling rig 12 positioned above a subterranean formation 14 that includes one or more oil and/or gas reservoirs 16. During operation, the derrick and hoist of the drilling rig 12 may raise and lower a drill string 18 into and out of a wellbore 20 to drill the wellbore 20 into the subterranean formation 14 and to position downhole tools in the wellbore 20 to facilitate completion and production operations of the well 22. For example, in some operations, a fracturing fluid (e.g., a fracturing mixture) may be introduced into the wellbore 22 through the drill string 18, as shown by arrow 24, which may be used to create fractures 26 in the subterranean formation 14 to facilitate production of oil and/or gas resources from the well 22. As described in more detail herein, the associated water and the returned fracturing fluid may be returned to the surface 28 of the well site 10 (e.g., through the annular space between the drill string 18 and the wellbore 20), as shown by arrow 30. Under certain circumstances, for every barrel of oil produced from the well 22, approximately three barrels of formation water (e.g., water with a relatively high salt content) are also produced.

[0035] Oil and gas producing companies often contract out water handling and disposal (WHD) services to specialized water handling and disposal (WHD) firms. In many cases, the produced water is treated and injected into saltwater disposal (SWD) wells. Fig. 2 shows an illustrative life cycle 32 of produced water produced at well sites 10. As shown in Fig. 2, water is produced in association with oil and gas in one or more production wells 22. Each formation fluid (e.g. oil, gas, produced water, returned fracturing fluid, etc.) can then be separated using one or more separators 34, with most of the produced oil and gas being sent to oil and gas pipelines 36, 38, respectively, and the remainder being flared through a flare stack 40, and produced water being sent to a temporary storage 42 for local (e.g. at the drilling site 10) treatment and subsequent storage in, for example, a surface pond 44. In general, most of the produced water is re-injected into the SWD wells 46, with only a small portion being used for fracturing purposes by injecting into the formation 14 via one or more fracturing wells 48.

[0036] The life cycle 32 shown in Fig. 2 creates quite a lot of additional costs for oil and gas producing companies. For example, at each drilling site 10 there must be equipment for storing chemicals and sand (e.g., storage mechanisms such as tanks, containers, bins, etc.) and mixing equipment, such as for mixing chemicals and sand together. In addition, the chemicals and sand must be delivered to the drilling sites 10 by trucks. With respect to the transportation of sand, the sand is typically first transported from the quarry to a transfer point, where the trucks are loaded and the sand is sent to the drilling sites 10. These trucks must then return empty to the transfer point, which doubles the distance that must be traveled for each delivery. In some areas, there are approximately 550 trucks per well 22 per week (e.g., approximately 70 trucks per day per well 22). The delivery of chemicals to drilling sites 10 is carried out in a manner very similar to sand, except that the chemicals may be delivered from multiple staging points, with each staging point using different transportation methods, such as flatbed shipping containers, shipping tanks, and/or specialized tanks.

[0037] Fig. 3 is a schematic illustration of a system 50 in which a fracturing mixture is mixed in situ at fracturing sites 52 in accordance with the life cycle 32 shown in Fig. 2. It should be understood that the fracturing sites 52 described herein may be a subset of the drilling sites 10 described herein, with the only difference being that the fracturing sites 52 are drilling sites that include fracturing wells 48 (and possibly production wells 22), whereas the drilling sites 10 include production wells 22 (and possibly fracturing wells 48).

[0038] As shown in Fig. 3, specialized equipment is used at the fracturing sites 52 to mix water, sand, friction reducers, and other chemicals (e.g., iron controls, biocides, clay stabilizers, surfactants, etc.) in specific ratios to form a fracturing mixture in situ at the fracturing sites 52. The fracturing mixture is then transported to relatively high pressure equipment for pumping the fracturing mixture into a well. As described in more detail herein, in such embodiments, the chemicals applied in situ at the fracturing sites 52 are typically transported over land using trucks 54 (or flatbed trucks or any other chemical containers). In addition, sand is also transported from sand pits 56 via trucks 54 (e.g., air slides, sand boxes, etc.) through sand distribution stations 58 (e.g., transfer stations, at some of which wet sand from sand pits 56 is converted to dry sand prior to transportation) to fracturing pads 52. In addition, water is often pumped from fracturing water basins 60 and/or from fresh water sources 62 via temporary pumping lines to fracturing pads 52, but trucks 54 are still widely used in cases where such infrastructure or services are not available.

[0039] Thus, sand is delivered to the fracturing sites 52 by trucks 54, and the sand is loaded into bins or containers before being delivered to specialized units, commonly known as fracturing mixture blenders, by belt conveyors, augers and/or gravity feed. In addition, chemicals are also delivered to the fracturing sites 52 by trucks 54, and from there to the fracturing mixture blenders as needed. Finally, the fracturing mixture blenders deliver the fracturing mixture to relatively high pressure pumps that inject the fracturing mixture into the formation. As shown in FIG. 3, each of these mechanisms for delivering chemicals, sand and water to the fracturing sites 52 incurs transportation costs and also creates unwanted pollution. In addition, the need for specialized equipment to produce the fracturing mixture on site at the fracturing sites 52 causes even greater additional costs.

[0040] To eliminate some of these additional costs, embodiments described herein include a novel method in which a fracturing mixture (e.g., produced using sand, water, friction reducers, and/or other chemicals) is mixed at a centralized facility and delivered via pipeline or temporary transfer lines (such as transfer hoses, layflat hoses, polymer pipes, metal pipes, etc.) to the fracturing pads 52 as needed. Such centralized receipt and delivery of fracturing mixture may be referred to as "mix on demand" and eliminates all mixing equipment required at the fracturing sites 52, eliminates the associated trucking required to transport sand and chemicals to the fracturing sites 52, eliminates certain on-site storage at the fracturing sites 52, and eliminates the logistics associated with obtaining sand and chemicals for delivery to the fracturing sites 52.

[0041] For example, Fig. 4 illustrates a new circular life cycle 64 of produced water produced at well sites 10, as described in more detail herein. As shown in Fig. 4, water is produced in association with oil and gas in one or more production wells 22. Each formation fluid (e.g., oil, gas, produced water, returned fracturing fluid, etc.) may then be separated using one or more separators 34, with most of the produced oil and gas being sent to oil and gas pipelines 36, 38, respectively, and the remainder being flared via a flare stack 40, and the produced water being sent to a temporary storage facility 42 for local (e.g., at the well site 10) treatment and subsequent storage in, for example, a surface pond 44. However, in embodiments described herein, at least a portion of the produced water may be delivered (e.g., via one or more pipelines) to a centralized facility 66, where the produced water may be reconditioned according to a certain specification and used for mixing fracturing fluid/mixture, which can then be delivered (e.g. via one or more pipelines) to one or more fracturing wells 48, where it can be injected into the formation 14 for fracturing purposes.

[0042] Although the centralized facility 66 is depicted as being located in relatively close proximity to the production wells 22 and the fracturing wells 48, as described in more detail herein, it may in fact be located at least 0.5 miles from the drilling sites 10 and/or fracturing sites 52, at least 1.0 mile from the drilling sites 10 and/or fracturing sites 52, at least 2.0 miles from the drilling sites 10 and/or fracturing sites 52, at least 5.0 miles from the drilling sites 10 and/or fracturing sites 52, at least 10.0 miles from the drilling sites 10 and/or fracturing sites 52, or even further from the drilling sites sites 10 and/or fracturing sites 52. However, again, in some embodiments, the centralized facility 66 may instead be adjacent to (or located in close proximity, such as within 0.1 mile of) one or more drilling sites 10 and/or fracturing sites 52.

[0043] Fig. 5 is a schematic illustration of a system 68 (in accordance with the new circular life cycle 64 shown in Fig. 4) in which a centralized facility 66 receives produced water from one or more well sites 10 via one or more produced water pipelines 70, receives wet sand from one or more sand pits 56 via one or more wet sand pipelines 72, and delivers fracturing mixture to one or more fracturing sites 52 (e.g., each of which has one or more fracturing wells 48) via one or more fracturing mixture pipelines 74. As shown in Fig. 5 and described in more detail herein, the centralized facility 66 may include, among other things, a reclaimed water basin 76 (or other reservoir) for storing produced water received from one or more drilling sites 10, and processing equipment 78 (e.g., (e.g., sand and chemical mixing equipment) for mixing produced water received from one or more drilling sites 10, sand received from one or more mobile sand pits 56, and chemicals stored at the centralized facility 66 into a fracturing mixture that is delivered to one or more fracturing sites 52.

[0044] Embodiments described herein replace the use of fresh water in hydraulic fracturing operations (e.g., at the hydraulic fracturing sites 52) with treated produced water (e.g., from the well sites 10). As described in more detail herein, in some embodiments, the produced water may first be treated and conditioned for hydraulic fracturing purposes (e.g., the content of oil, organic material, calcium, magnesium, Fe2, Fe3, and other minerals is adjusted to desired values) at a centralized facility 66. The treated and conditioned water may then be used to mix a hydraulic fracturing mixture at the centralized facility 66. Finally, the hydraulic fracturing mixture may then be distributed via one or more hydraulic fracturing mixture pipelines 74 to one or more hydraulic fracturing sites 52, where it will be used for hydraulic fracturing operations. It should be noted that the fracturing mixture supplied to one or more fracturing pads 52 will be ready for injection into the well into the formation 14 without the need for additional mixing at one or more fracturing pads 52. Accordingly, as shown in Figs. 2 and 3, the production wells 22, the separators 34, the surface pond 44, the SWD wells 46, etc. will no longer be required at the fracturing pads 52.

[0045] As shown in FIG. 5, in some embodiments, wet sand (or proppant) will be transported to a centralized facility 66 via one or more wet sand pipelines 72. In some embodiments, the sand will be mixed in a specific concentration range and, if necessary, diluted at the centralized facility 66 (and/or at the fracturing pads 52) in accordance with various injection schedule requirements. Thus, the embodiments described herein eliminate the need for transporting sand by truck. As described above, it is estimated that approximately 550 trucks per well will be removed from the roads. In addition to reducing greenhouse gas emissions, road damage will also be reduced and safety will be improved due to reduced traffic volumes. In addition, less clutter on the site will result in a safer working environment for completion operations.

[0046] In addition, as described in more detail herein, other additives such as friction reducers, surfactants, clay stabilizers, etc., can be processed and mixed with the fracturing mixture at the centralized facility 66. If necessary, the concentration of these additives can be adjusted at the fracturing pads 52 in accordance with changes in concentration. Thus, the embodiments described herein reduce the storage areas of chemicals at the fracturing pads 52 and allow fracturing operators to focus on relatively high pressure operations, increasing safety at the site while improving the quality of service.

[0047] Thus, the system 68 shown in Fig. 5 and described in more detail herein changes the traditional logistics chain for delivering sand, chemicals, and water to fracturing sites, including new methods of mining sand, transporting sand via pipelines, managing the density of the fracturing mixture, etc. As described in more detail herein, the embodiments described herein also enable more efficient use of equipment, more consistent and reliable mixing of fluid, sand, and chemicals, and an improved environmental footprint at similar or lower costs. Furthermore, in addition to providing the ability to sustainably manage the life cycle of produced water, the embodiments described herein provide other environmental benefits including, but not limited to, reducing carbon emissions by approximately 500 tons per well, reducing the number of trucks on the road by approximately 550 trucks per well due to source sand supply, and reducing the number of trucks on the road by approximately 5,000 trucks per well due to optimized water delivery logistics.

[0048] Fig. 6 is a schematic illustration of various operational components of the centralized facility 66 shown in Figs. 4 and 5. As shown in Fig. 6 and described in more detail herein, wet sand 80 may be received at the centralized facility 66 from one or more sand quarries 56, such as via one or more wet sand pipelines 72 (however, in other embodiments, the sand may be mined near or relatively close to the centralized facility 66) and stored in a sand storage 82, such as bins. Additionally, chemicals 84 may be received at the centralized facility 66, such as via trucks delivering chemicals 84, as described in more detail herein, and the chemicals 84 may be stored in a chemical storage 86, such as tanks or containers for chemicals.

[0049] Additionally, produced water 88 may be received at the centralized facility 66 from one or more well sites 10, such as via one or more produced water pipelines 70, and stored in a reservoir 76, such as tanks or a reclaimed water pond. Although the present document primarily describes the use of produced water 88 received from one or more well sites 10, in other embodiments, the centralized facility 66 may receive and use another source of water, including, but not limited to, fresh water, water intended for injection through SWD wells 46, water prepared for use in hydraulic fracturing equipment, water treated to remove certain contaminants, brackish water, water with a relatively high total dissolved solids (TDS) content, etc.

[0050] As described in more detail herein, the centralized facility 66 may be located at least 0.5 miles from the sand pits 56, drilling sites 10, and/or fracturing sites 52, at least 1.0 mile from the sand pits 56, drilling sites 10, and/or fracturing sites 52, at least 2.0 miles from the sand pits 56, drilling sites 10, and/or fracturing sites 52, at least 5.0 miles from the sand pits 56, drilling sites 10, and/or fracturing sites 52, at least 10.0 miles from the sand pits 56, drilling sites 10, and/or fracturing sites 52, or even further from the sand pits 56, drilling sites 10, and/or fracturing sites 52. However, again, in some embodiments, the centralized facility 66 may instead be adjacent to (or located in close proximity, such as within 0.1 mile of) one or more sand pits 56, drilling sites 10, and/or fracturing sites 52.

[0051] As described in more detail herein, the processing equipment 78 of the centralized facility 66 may process the sand 80, chemicals 84, and produced water 88 to produce, among other things, a fracturing mixture 90 that may be delivered to one or more fracturing pads 52 from the centralized facility 66, such as via one or more fracturing mixture pipelines 74. As shown, in some embodiments, a portion of the produced fracturing mixture 90 may be stored in a fracturing mixture storage 92, such as a mixture tank. Additionally, in some embodiments, a portion of the water from the processing equipment 78 may be recycled back to the reservoir 76, as described in more detail herein.

[0052] Additionally, in some embodiments, the process control system 94 may be used to control the process operations of the centralized facility 66, as described in more detail herein. For example, in some embodiments, the process control system 94 may send control signals to various equipment (e.g., valves, pumps, etc.) of the centralized facility 66, such as to automatically control the properties (densities, chemical concentrations, flow rates, water compositions, etc.) of the resulting fracturing mixture 90 in substantially real time in accordance with desired setpoints based on parameters of the sand 80, chemicals 84, and produced water 88 that may be measured by various sensors 96 located around the centralized facility 66. Additionally, in some embodiments, the process control system 94 may ensure that the produced water 88 is within the fracturing water specification limits prior to mixing the produced water 88 with the sand 80 and chemicals 84 to form the fracturing mixture 90.

[0053] In addition, in some embodiments, produced water 88 stored at a centralized facility 66 may be used to facilitate production operations at one or more sand pits 56, rather than fresh water that is typically used in traditional sand pits. For example, in some embodiments, produced water 88 may be transported to one or more sand pits 56 via one or more water supply pipelines 95. In general, sand 80 may be mined near the service area. From one or more sand pits 56, sand 80 may be transported either directly to one or more fracturing pads 52 or to a centralized facility 66 for processing. In general, the relative geographic locations of one or more sand pits 56 and one or more fracturing pads 52 will determine the most efficient destinations.

[0054] Fig. 7 is a schematic illustration of a sand pit 56 that uses non-traditional water (e.g., produced water 88 or other non-fresh water) in sand mining operations. As described in more detail herein, sand pits typically use fresh water to operate the pits in a closed system, with the primary losses associated with moisture remaining in the sand during processing. Traditional sand pits typically use fresh water because they typically do not have access to produced water, and because of specific specifications typically received from customers. In contrast, embodiments described herein provide sand pits 56 (mobile or stationary) with water from an unconventional source (e.g., produced water 88 from drilling sites 10 or hydraulic fracturing sites 52, water intended for injection through SWD wells 46), water in the process of being reused, etc.) and use the water source in the mining process. In embodiments described herein, the unconventional water is used to wash sand 80 (e.g., stored in one or more pit bins 98) in a washing unit 100, and then the sand 80 is transported by the water 88 to a receiving site (e.g., a hydraulic fracturing site 52).

[0055] There are several embodiments of the sand pit 56 shown in Fig. 7. For example, in some embodiments, the sand pit 56 may be a closed loop or an open loop. In addition, in some embodiments, the sand pit 56 may be a fixed installation or a mobile installation. In addition, in some embodiments, the washing unit 100 may be located separately from the sand pit 56 or the centralized facility 66, and its operation may be carried out in an autonomous manner or in combination with the decantation area. In addition, in some embodiments, the mining process carried out in the sand pit 56 may include washing sand 80 using the washing unit 100, transporting sand 80 in the sand pit 56 as a mixture (e.g., proppant) and/or transporting sand 80 directly from the sand pit 56.

[0056] Additionally, although FIG. 7 shows that the source of water used in the sand pit 56 is produced water 88 (e.g., from the drilling sites 10 or the fracturing sites 52), in other embodiments, it may include water intended for injection through the SWD wells 46, water prepared for use in fracturing equipment, water treated to remove certain contaminants, brackish water, water with a relatively high total dissolved solids (TDS), etc. Additionally, although FIG. 6 shows that the produced water 88 is delivered from the centralized facility 66, in other embodiments, it may instead be received in the sand pit 56 directly from one or more drilling sites 10 or one or more fracturing sites 52, or may be received from a processing facility. Additionally, although FIG. 7 shows that the mixture (e.g., proppant) obtained in the sand pit 56 is delivered to the fracturing site 52, in other embodiments, it may instead be delivered to fracturing mixture tanks, a loading and unloading station, fracturing equipment, a decanting area, or other locations. In addition, in some embodiments, certain chemicals may be added to the mixture to facilitate the transport of the mixture from the sand pit 56.

[0057] Returning now to Fig. 6, as described in more detail herein, the process equipment 78 of the centralized facility 66 may include various subsystems that enable the operation of the centralized facility 66. For example, in some embodiments, the various subsystems of the process equipment 78 may include, among other things, a dilution manifold for diluting the chemicals 84 and sand 80 into the resulting fracturing mixture 90, equipment for dewatering the sand-containing stream for density control, a relatively long pipe for passively mixing the sand 80, chemicals 84, and produced water 88, and a low-shear addition system for adding friction reducing additives. It should be understood that any and all of these subsystems may be used individually or in combination with any and all combinations of other subsystems. Each of these subsystems will be described in more detail below.

[0058] For example, Fig. 8 conceptually shows how a dilution manifold 102 of the processing equipment 78 of the centralized facility 66 can dilute the chemicals 84 and the sand 80 in the resulting fracturing mixture 90. As shown in Fig. 8, the dilution manifold 102 is configured to automatically proportionally distribute two different fluid streams (e.g., a relatively clean fluid stream 104 that does not contain or contains at most minor amounts of the chemicals 84 or the sand 80, and a concentrated fluid stream 106 that contains a relatively large amount of the chemicals 84 and/or the sand 80) to achieve specific concentrations of certain chemicals 84 and/or the sand 80 in the fracturing mixture 90 at the outlet of the dilution manifold 102.

[0059] Fig. 9 shows an exemplary dilution manifold 102 that receives a relatively clean liquid stream 104 into a first flow path 108 and a concentrated liquid stream 106 into a second flow path 110. Again, the relatively clean liquid stream 104 may contain no or at most minor amounts (e.g., less than 5%, less than 3%, less than 1%, or even less) of the chemicals 84 or the sand 80, while the concentrated liquid stream 106 may contain relatively large amounts (e.g., more than 5%, more than 10%, more than 15%, more than 20%, or even more) of the chemicals 84 and/or the sand 80.

[0060] In some embodiments, the dilution manifold 102 may include respective flow meters 112, density meters 114, and fluid control valves 116 in both flow channels 108, 110 to automatically adjust the suction ratios of the fluid streams 104, 106 to discharge a fluid stream (e.g., fracturing mixture 90) with desired concentrations and densities of chemicals 84 and/or sand 80 through the outlet channel 118 of the dilution manifold 102. In particular, although not shown in FIG. 9, in some embodiments, the process control system 94 (see FIG. 6) can receive signals from the flow meters 112 and the densities meters 114 relating to the flow rates and densities of the respective fluid streams 104, 106, and, at least in part based on the received signals, generate and send control signals to the fluid control valves 116 to automatically adjust the mixing of the fluid streams 104, 106 to maintain desired ratios of the fluids to achieve desired concentrations and densities of the chemicals 84 and/or sand 80 in the fluid stream (e.g., the fracturing mixture 90) discharged from the outlet channel 118 of the dilution manifold 102. In general, the dilution manifold 102 utilizes the turbulence of the liquid flows 104, 106 within the outlet channel 118 to homogenize the final mixture without the need for ejectors, mixing chambers or tanks, impellers, or other active mixing mechanisms.

[0061] Also shown in Fig. 10 is a dewatering equipment 120 of the processing equipment 78 of the centralized facility 66 for dewatering a sand-containing stream for density control. In general, the dewatering equipment 120 receives a first mixture 122 (e.g., a fracturing mixture 90) that contains a relatively high concentration of proppant (e.g., sand 80). The first mixture 122 is passed through the dewatering equipment 120 to remove water (e.g., wastewater) 124 from the first mixture 122 to produce a second mixture 126 with an increased concentration of proppant, which can be stored in a storage facility 128 for fracturing mixture (e.g., a storage facility 92 shown in Fig. 6) in some embodiments. Although not shown in Fig. 10, in some embodiments, the process control system 94 (see FIG. 6) may control the proppant concentration in the second mixture 126 in accordance with a designated setpoint by, for example, sending control signals to the dewatering equipment 120.

[0062] Then, in some embodiments, the second mixture 126 may be mixed with water (e.g., wastewater) 130 via mixing equipment 132, which dilutes the concentration of the second mixture 126 to produce a third mixture 134 with a different designated proppant concentration setpoint, which may be delivered to a receiving location, such as a fracturing pad 52. As with other mixing equipment described herein, in some embodiments, the mixing equipment 132 shown in Fig. 10 may employ passive mixing of the second mixture 126 and water 130. Again, although not shown in Fig. 10, in some embodiments, the process control system 94 (see FIG. 6) may control the proppant concentration in the third mixture 134 in accordance with another designated setpoint by, for example, sending control signals to various valves to control the respective flow rates of the second mixture 126 and water 130.

[0063] Additionally, as shown in Fig. 11, in some embodiments, a relatively long pipe 136 may be used to mix sand 80, chemicals 84, and/or produced water 88 to form a fracturing mixture 90 described herein. As described in more detail herein, traditional fracturing mixture delivery operations involve shearing the fracturing mixture using mechanical means such as centrifugal pumps, vortex mixers, mixing tanks, etc. In contrast, embodiments described herein enable passive mixing by means of pipe 136 instead of using active mixing. In this manner, pipe 136 achieves a homogeneous fracturing mixture 90 used in fracturing operations at one or more fracturing sites 52 without using specialized mixing equipment for the mixture.

[0064] As shown in Fig. 12, the method includes a collection point (e.g., centralized facility 66 described herein) where materials (e.g., sand 80, chemicals 84, and/or produced water 88) are added to each other in desired proportions, but are not mixed together using traditional active mixing methods. Instead, after collection, the heterogeneous mixture of materials is agitated to be directed through a relatively long pipe 136 using a centrifugal pump 138. In some embodiments, the pipe 136 may be greater than 0.5 miles, greater than 1.0 miles, greater than 2.0 miles, greater than 5.0 miles, greater than 10.0 miles, or even longer. In some embodiments, the mixture may be agitated multiple times along the relatively long pipe 136 to ensure proper flow rate as it moves through the pipe 136 to one or more destinations (e.g., one or more fracturing sites 52). Relying on the shear forces in the relatively long pipe 136 and the relatively long travel time in the pipe 136, the fracturing mixture 90 reaches one or more destinations as a homogeneous mixture of materials. In some embodiments, the material mixture flowing through the relatively long pipe 136 can flow at a speed of from about 4 feet per second to about 16 feet per second, at a speed of from about 6 feet per second to about 12 feet per second, or at a speed of from about 8 feet per second to about 10 feet per second.

[0065] Although the present document primarily describes mixing sand 80, chemicals 84, and produced water 88 to form a fracturing mixture 90, other embodiments may mix other combinations of materials using the methods described herein. For example, in some embodiments, the fracturing mixture 90 may consist of only sand 80 and produced water 88, only chemicals 84 and produced water 88, only chemicals 84 and acids, or any other possible combinations. Additionally, in some embodiments, the sand 80 used to form the fracturing mixture 90 may be dry sand, wet sand, or sand in a liquid. Furthermore, in some embodiments, the chemicals 84 used to form the fracturing mixture 90 may be dry chemicals, liquid chemicals, or some combination thereof.

[0066] Additionally, although the collection point is generally described herein as a centralized facility 66, in other embodiments, the collection point at which the fracturing mixture 90 is started may instead be an open tank or a closed tank. Additionally, in some embodiments, the sand 80 used to produce the fracturing mixture 90 may be received from a mobile sand pit 56 or from a stationary sand pit 56. Additionally, although the destination point is generally described herein as one or more fracturing sites 52, in other embodiments, the destination point to which the fracturing mixture 90 is delivered may instead be a storage tank, a stirred tank, or equipment that pumps the fracturing mixture 90 into a well.

[0067] In addition, in some embodiments, the relatively long pipe 136 that can be used to provide the passive mixing described herein can include a transfer hose, a layflat hose, a polymer pipe, a metal pipe (e.g., temporary or permanent), or a pipe made of other materials. In addition, in some embodiments, the relatively long pipe 136 can have an interior surface that is textured (i.e., not smooth, but having ridges, indentations, etc.) to facilitate mixing of materials. In addition, in some embodiments, the fracturing mixture 90 can be distributed from a collection point (e.g., a centralized facility 66, in some embodiments) by means of a centrifugal pump, a positive displacement pump, or any other suitable pump. Additionally, in some embodiments, the relatively long pipe 136 may have a plurality of booster pumps located along the length of the pipe 136 to provide re-excitation of the mixture to enable it to be pumped a relatively long distance.

[0068] In general, the proppant transport mechanism is essentially a velocity that reaches a maximum as the flow rate reaches a maximum. The flow rate limitation is generally determined by the effective surface treatment pressure, which is affected by overburden pressure, the pressure drop across the perforated surface (e.g., when perforating serves as the mechanism for contacting the reservoir from a cased well), the hydrostatic weight of the fracturing mixture, the friction pressure loss in the pipes, etc. Friction reducers can be used as a technology that provides the ability to reduce the friction pressure loss component in the pipes by up to 80% compared to the base fluid and/or mixture. The use of friction reducers can result in higher injection rates in the perforations, which results in higher velocity and more intensive transport of sand.

[0069] Most water-soluble polymers reduce friction; however, anionic polyacrylamides have been found to be particularly well suited for hydraulic fracturing applications in terms of cost and performance optimization. A certain level of expertise is required to effectively select and use anionic polyacrylamides. However, in general, they are well understood and very effective in terms of both cost and friction reducing performance per pound of material. In general, it is important to match the polymer chemistry to the water salinity, and the primary determinant of success is the tolerance of divalent cations (e.g., Ca2+, Mg2+, Fe2+, …) due to their tendency to significantly suppress the radius of gyration of the polymer in solution due to the way in which concentrated cation charges bond with anion charges along the polymer backbone, thereby reducing the net negative charge and sometimes crosslinking the polymer with itself. Accordingly, as described in more detail herein, in some embodiments, sensors may be used to detect properties of a fluid (e.g., fracturing mixture 90), and these detected properties may be used to determine which polymers to use, as well as the concentrations of the polymers.

[0070] It has also been recognized that higher molecular weight polymers are more effective, on a pound for pound basis, in reducing friction than lower molecular weight polymers. The polymers are highly hygroscopic and are widely used in water management projects in the oil and gas, pulp and paper, and water treatment industries as flocculants/clarifiers and in solution as dry products in water-absorbing solutions such as diapers. Certain blended friction reducer packages have a hydrocarbon phase or carrier that suspends either surfactant-stabilized droplets of concentrated polymer (e.g., up to 30% by weight) or suspended particles of dry polyacrylamide. The hydrocarbon phase is designed to allow the highly hygroscopic polymer to be dispersed in solution prior to hydration, thereby avoiding the formation of relatively viscous regimes in the process line where the polymer concentration is high enough that local viscosity prevents dispersion and hydration of the next polymer entering the system.

[0071] Historically, relatively high shear at the point of addition has been used to allow the preparation of homogeneous mixtures that are effective in hydraulic fracturing. However, recent improvements in dry pressure reducer technology have made it easier to add polymers under relatively low shear conditions without unfavorable viscosity at suitable concentrations for hydraulic fracturing, as described in more detail herein. This provides potential cost savings in products due to the absence of a hydrocarbon phase and surfactants, and in logistics by allowing dry additives to be transported to the site rather than liquids. These recent improvements have in turn led to further cost savings and simplification by centralizing liquid preparation at a point where, for example, produced water 88 is collected and stored for many operators.

[0072] Thus, embodiments described herein also generally include systems and methods that facilitate low-shear (or even no-shear) addition of friction reducing additives to a fluid (e.g., fracturing mixture 90) at a centralized facility 66, transport of the low-shear fluid to a wellsite 10 (or fracturing site 52), and injection of low-shear water into a reservoir 16 to stimulate a production well 22. As used herein, the term "low shear" is used to describe relatively low levels of shear or even no shear (e.g., such as passive mixing) compared to other traditional methods.

[0073] Fig. 13 shows a low-shear addition system 140 of the processing equipment 78 of the centralized facility 66 configured to add a friction reducing additive 142 to a fluid 144 to form a fracturing mixture 90 that can be delivered to one or more fracturing pads 52. In some embodiments, the fluid 144 may be produced water 88, a combination of produced water 88 and sand 80, a combination of produced water 88, sand 80 and chemicals 84, or any other combination thereof, as described in more detail herein. In addition, although the present document primarily describes the use of produced water 88 received from one or more well sites 10, in other embodiments, another source of water may be used to produce the fracturing mixture 90, including, but not limited to, fresh water, water intended for injection through the SWD wells 46, water prepared for use in fracturing equipment, water treated to remove certain contaminants, brackish water, water with a relatively high total dissolved solids (TDS) content, etc. As described in more detail herein, once the fracturing mixture 90 is produced, it may be transported from the centralized facility 66 to one or more fracturing sites 52, such as via one or more fracturing mixture pipelines 74, wherein the fracturing mixture 90 may be injected into one or more reservoirs (e.g., via one or more pumps 146 hydraulic fracturing) through one or more wells 48 hydraulic fracturing at one or more sites 52 hydraulic fracturing to intensify one or more production wells 22.

[0074] In some embodiments, the slip additive 142 may include at least polyacrylamide and/or partially hydrolyzed polyacrylamide and/or cross-linked polyacrylamide and/or polymethacrylamide and/or partially hydrolyzed polymethacrylamide and/or cross-linked polymethacrylamide and/or polyacrylic acid and/or polymethacrylic acid and/or polyacrylate and/or polymethacrylate and/or carboxymethylcellulose and/or polyvinylpyrrolidone and/or a polysaccharide (such as xanthan gum, gellan gum and diutan gum) and/or guar. In addition, in some embodiments, the slip additive 142 may include a copolymer of at least polyacrylamide and/or partially hydrolyzed polyacrylamide and/or cross-linked polyacrylamide and/or polymethacrylamide and/or partially hydrolyzed polymethacrylamide and/or cross-linked polymethacrylamide and/or polyacrylic acid and/or polymethacrylic acid and/or polyacrylate and/or polymethacrylate and/or carboxymethylcellulose and/or polyvinylpyrrolidone and/or a polysaccharide (such as xanthan gum, gellan gum and diutan gum).

[0075] As shown in Fig. 13, in some embodiments, one or more transfer pumps 148 located at one or more well sites 10 may be used to pump produced water 88 from one or more production wells 22 via one or more produced water pipelines 70 to a centralized facility 66. As described in more detail herein, using the produced water 88 from one or more production wells 22 to produce a fracturing mixture 90 for use in one or more fracturing wells 48 provides economic and environmental efficiencies, among other benefits. However, although in Fig. 13 shows and is primarily described herein as using produced water 88 from one or more production wells 22, in other embodiments water from other water sources (such as those described herein), such as those located at or near the centralized facility 66, may also be used to produce the fracturing mixture 90 described herein.

[0076] As described in more detail herein, the low shear addition system 140 facilitates the production of a fracturing mixture 90 with reduced friction in a relatively low shear environment, as opposed to traditional systems that include relatively high shear mixers and the use of transport units to transport fluids to well sites. Many different types of low shear addition systems 140 can be used. For example, ejectors consist of tools into which a motive fluid is introduced and a secondary fluid is set in motion (e.g., to mix fluids, to thoroughly mix two or more fluids, to bulk transport solids, etc.), often by the Venturi effect of the motive fluid. In general, velocities are rapidly matched in ejectors, with close contact occurring at relatively low shear but high dispersion. Although there are many variations, all ejectors generally have the same operating principle. Ejectors are an effective low-shear mechanism for air-assisted lifting and dissolving high volumes of powdered solids in liquids (e.g., mixing polyacrylamide polymers in water, as described in more detail herein). In contrast, other low-shear mixing systems simply pour solids onto a liquid phase; however, this practice is only applicable to solids that are easily dispersed. However, in some embodiments, polyacrylamides can be hydrated by this mechanism when added slowly in small amounts.

[0077] In some embodiments, the low-shear addition system 140 may include one or more ejectors configured to add the friction reducing additive 142 to the fluid 144 to produce the low-friction fracturing mixture 90 in a relatively low-shear environment. FIGS. 14 and 15 illustrate examples of ejectors 150A, 150B that may be used in the low-shear addition systems 140 to disperse solids into the liquid phase as described herein. The ejector 150A shown in FIG. 14 is gravity fed via a solids metering system or other transport mechanism. As shown in FIG. 14, the ejector 150A is configured to receive air and solids (for example, including a friction-reducing additive 142) through an opening 152A in the upper part of the ejector 150A. In some embodiments, the mechanism for feeding the gearbox 150A by gravity can be supplemented by a vacuum 154A created in the opening 152A of the ejector 150A. As also shown in Fig. 14, the propellant fluid 144 that has been pumped into the ejector 150A) may be introduced into the ejector 150A via a passage 156A that includes a nozzle 158A through which the fluid 144 may flow such that the friction reducing additive 142 is dispersed in the fluid 144 in a relatively low shear environment 160A within the main chamber 162A of the ejector 150A before exiting the ejector 150A as a low friction fracturing mixture 90 and, in some embodiments, delivered to one or more drilling sites 10 and/or one or more fracturing sites 52, such as via one or more relatively long pipes 136, as described herein.

[0078] In contrast, the ejector 150B shown in Fig. 15 is configured to pneumatically transport and disperse air and solids (e.g., including friction reducing additive 142) into the propellant fluid 144. For example, as shown in Fig. 15, the fluid 144 may be introduced into the ejector 150B through an opening 152B in the upper portion of the ejector 150B. As also shown in Fig. 15, the ejector 150B is configured to receive air and solids (e.g., including a friction reducing additive 142) through a passage 156B that includes a nozzle 158B (e.g., a gel gun) through which the air and solids can flow such that the friction reducing additive 142 is dispersed in a liquid 144 in a relatively low shear environment 160B within a main chamber 162B of the ejector 150B before exiting the ejector 150B as a low-friction fracturing mixture 90 and, in some embodiments, delivered to one or more drilling sites 10 and/or one or more fracturing sites 52, such as through one or more relatively long pipes 136, as described herein. In some embodiments, the pneumatic nature of the reducer 150B may be supplemented by a vacuum 154B created in the channel 156B of the ejector 150B.

[0079] In addition, in other embodiments, the low-shear addition system 140 may employ other types of low-shear (or no-shear) addition mechanisms. For example, in some embodiments, the low-shear addition system 140 may employ low-shear addition mechanisms in which the slip additive 142 is simply gravity fed, such as a gravity-fed auger system, into a channel or reservoir that includes the liquid 144.

[0080] Regardless of the type of low shear addition system 140 employed, embodiments described herein facilitate the production of a fracturing treatment fluid (e.g., a low friction fracturing mixture 90) in relatively large volumes and/or on a continuous basis at a centralized facility 66. Centralized production of a low friction fracturing mixture 90, as described herein, allows operators to save costs by achieving economies of scale on proppants (e.g., sand 80) and chemicals 84, eliminating manual transportation of proppants and chemicals 84 to/from one or more well sites 10 and/or one or more fracturing sites 52, sourcing/selecting chemicals, mixing proppants and/or chemicals, renting/owning pumps and control systems for on-site chemical addition, etc. The cost savings are also achieved because the friction reducer 142 can be added via the low shear addition system 140 to produce the low friction fracturing mixture 90, which is capable of being conditioned en route to one or more well sites 10 and/or one or more fracturing sites 52 (e.g., via the relatively long pipes 136 described herein, in some embodiments) under low shear - the gentle conditioning of the low friction fracturing mixture 90 means that the median molecular weight of the friction reducer 142 in the low friction fracturing mixture 90 is maintained to a greater extent than in relatively high shear mixers, increasing the efficiency of the polymers by as much as 15%. Finally, in some embodiments, cost savings are achieved due to the fact that the density of the produced water 88 is higher than that of fresh water, and therefore the contribution of the hydrostatic component (e.g., the weight of the low-friction fracturing mixture 90) to the effective fracturing pressure of the formation is higher, thereby providing the possibility of saving on diesel fuel for powering the fracturing pumps 146 used to fracturing the formation in the wells 22, and/or leading to the completion of stages in a shorter time.

[0081] Embodiments described herein provide well site operators with the ability to purchase pre-formulated effective fracturing mixture 90 from the same entity to which they currently provide their produced water 88 for treatment/disposal. However, embodiments described herein provide additional specific advantages. For example, in some embodiments, the produced water 88 may be transferred to a centralized facility 66 and stored there. Well operators 22 may then contract with the operators of the centralized facility 66 to “reserve” a volume of ready-to-use low friction fracturing mixture 90 based on upcoming well 22 completion activity. In response, the centralized facility 66 may prepare the low friction fracturing mixture 90 at a desired time immediately prior to releasing the low friction fracturing mixture 90. Such a mixture, upon request, leaves the centralized facility 66 and arrives at the well site 10 and/or the fracturing site 52 in the form of an effective liquid, which, for example, can be fed into a storage tank or blender, as described herein, and then pumped into the fracturing well 48 without the need to add any chemicals at the well site 10 and/or the fracturing site 52, in some embodiments.

[0082] Returning now to Fig. 13, as described in more detail herein, various other combinations of processing equipment 78 may be used to ensure that the low-friction fracturing mixture 90 is tailored to the specific needs of one or more fracturing wells 48 in which the low-friction fracturing mixture 90 is used. For example, in some embodiments, various combinations of processing lines may be used to transport the low-friction fracturing mixture 90 from the centralized facility 66 to the one or more well sites 10 via one or more fracturing mixture pipelines 74 (e.g., which may include the relatively long pipes 136 described herein in some embodiments). For example, as shown in Fig. 13, in some embodiments, one or more transfer pumps 164 located at the centralized facility 66 may be used to pump the low-friction fracturing mixture 90 from the centralized facility 66 to one or more drilling sites 10 and/or one or more fracturing sites 52 via one or more fracturing mixture conduits 74. Additionally, in some embodiments, one or more booster pumps 166 located along the one or more fracturing mixture conduits 74 may be used to periodically increase the pressure of the low-friction fracturing mixture 90 to allow the pressure of the low-friction fracturing mixture 90 to remain relatively low, as described in more detail herein. Similarly, as also shown in FIG. 13, in some embodiments, one or more transfer pumps 148 located at one or more drilling sites 10 may be used to pump produced water 88 from one or more drilling sites 10 to a centralized facility 66 via one or more produced water pipelines 70.

[0083] As described in more detail herein, the transfer pumps 164 and the booster pumps 166 that cause the fracturing mixture 90 (and other fluids, in some embodiments) to move from the centralized facility 66 to one or more fracturing sites 52 maintain the pressure of the fracturing mixture 90 (and other fluids) in a relatively low range of from about 0 pounds per square inch (psi) to about 200 psi, in some embodiments, compared to the relatively high pressure ranges in fracturing operations at the fracturing sites 52 of from about 1,000 psi to about 10,000 psi. For example, in some embodiments, the relatively low pressure applied may be no more than 400 psi. inch, not more than 350 psi, not more than 300 psi, not more than 250 psi, not more than 200 psi or even less.

[0084] Accordingly, relatively low pressure centrifugal pumps can be used as the transfer pumps 164 and the booster pumps 166, and transfer hoses, temporary layflat hoses, high density polyethylene (HDPE) pipes (or other polymer pipes), semi-permanent or permanent steel pipes and other relatively low pressure conduits can be used as one or more fracturing mixture conduits 74 (e.g., which can include the relatively long pipes 136 described herein). In general, the fracturing mixture conduits 74 can include any suitable pumping lines that are strong enough to transport water and solids. Similar to the fracturing mixture conduits 74, the wet sand conduits 72 described herein can also include any suitable pumping lines that are strong enough to transport water and solids.

[0085] Additionally, in some embodiments, additional water (e.g., non-friction-reduced water) may be added to adjust the composition of the fracturing mixture 90 with reduced friction. For example, in some embodiments, additional water from other water sources (e.g., such as those described herein) located at or near the centralized facility 66 may be added to the produced water 88 received from one or more well sites 10 to form a diluted produced water prior to adding the friction additive 142 to the produced water 88 using the low-shear addition system 140, wherein the friction additive 142 may then be added to the diluted produced water to form the fracturing mixture 90 with reduced friction using the low-shear addition system 140. In addition, in some embodiments, additional water from a water source located at one or more fracturing sites 52 may be added to the low-friction fracturing mixture 90 prior to pumping the low-friction fracturing mixture 90 into one or more fracturing wells 48. In addition, in some embodiments, additional water from a water source located at an intermediate location along one or more fracturing mixture pipelines 74 between the centralized facility 66 and the one or more fracturing sites 52 may be added to the low-friction fracturing mixture 90 prior to delivering the low-friction fracturing mixture 90 to the one or more fracturing sites 52. It should be understood that any combination of these methods of adding water can be used in some embodiments to adjust the composition of the low-friction fracturing mixture 90. In addition, as described in more detail herein, in some embodiments, additional water, other additives, and other fluids can be delivered from the centralized facility 66 to one or more fracturing sites 52 simultaneously and can be mixed with each other at one or more fracturing sites 52 before the low-friction fracturing mixture 90 is pumped into one or more fracturing wells 48.

[0086] Additionally, in some embodiments, one or more additives 168 may be added to the low-friction fracturing mixture 90 at the centralized facility 66 prior to transporting the low-friction fracturing mixture 90 to one or more fracturing sites 52. In some embodiments, one or more additives 168 may include at least one of a biocide and/or a flowback surfactant and/or an acid and/or a clay stabilizer and/or a marker element and/or a scale inhibitor and/or an oxygen scavenger and/or a hydrogen sulfide scavenger and/or a reducing agent and/or a chelating agent and/or an iron control agent and/or an anti-emulsion agent and/or a demulsifier and/or a breaker and/or a corrosion inhibitor and/or a pipeline cleaner and/or a gel plug.

[0087] Additionally, in some embodiments, the low friction fracturing mixture 90 may be stored in storage facilities such as tanks, lined basins, etc. For example, as shown in Fig. 7, in some embodiments, the low friction fracturing mixture 90 may be stored in a storage facility (see, for example, storage facility 92 in Fig. 6) located at the centralized facility 66 prior to transporting the low friction fracturing mixture 90 to one or more fracturing sites 52. In addition, in some embodiments, the low-friction fracturing mixture 90 may be stored in a storage facility located at one or more fracturing pads 52 after receiving the low-friction fracturing mixture 90 from the centralized facility 66 and before pumping the low-friction fracturing mixture 90 into one or more fracturing wells 48. In addition, in some embodiments, the low-friction fracturing mixture 90 may be stored at an intermediate location along one or more fracturing mixture pipelines 74 (e.g., which may include the relatively long pipes 136 described herein) between the centralized facility 66 and the one or more fracturing pads 52. It should be understood that in some embodiments, any combination of such storage options may be used.

[0088] Additionally, in some embodiments, one or more additional chemicals and/or proppants 170 may be added to the low-friction fracturing mixture 90 prior to pumping the low-friction fracturing mixture 90 into one or more fracturing wells 48. For example, in some embodiments, one or more chemicals and/or proppants 170 may be added to the low-friction fracturing mixture 90 using one or more blenders located at one or more fracturing pads 52 prior to pumping the low-friction fracturing mixture 90 into one or more fracturing wells 48. However, in other embodiments, one or more chemicals and/or proppants 170 may be added to the low-friction fracturing mixture 90 using one or more blenders located at a site that is external to the one or more fracturing pads 52 (e.g., including the centralized facility 66), prior to pumping the low-friction fracturing mixture 90 into one or more fracturing wells 48. It should be understood that the one or more chemicals and/or proppants 170 may include any other chemicals and/or proppants described herein.

[0089] Additionally, in some embodiments, one or more process control systems 94 may be used to control any operating parameters of the centralized facility 66 and/or one or more drilling sites 10 and/or one or more fracturing sites 52 to facilitate the production and delivery of the low friction fracturing mixture 90 to one or more fracturing wells 48 of the one or more fracturing sites 52, as described in more detail herein. In fact, in some embodiments, one or more process control systems 94 may be used to automatically (e.g., without human intervention) adjust any and all operating parameters of the centralized facility 66 and/or one or more drilling sites 10 and/or one or more fracturing sites 52 to facilitate the production and delivery of the low-friction fracturing mixture 90 to one or more fracturing wells 48 of the one or more fracturing sites 52, as described in more detail herein.

[0090] For example, as shown in Fig. 7, the process control system 94A may be used to control the operating parameters of the process equipment 78 located at the centralized facility 66 based at least in part on real-time measurement data collected by one or more sensors (see, for example, the sensors 96 shown in FIG. 6) located around the centralized facility 66. In some embodiments, the operating parameters of the process equipment located at the centralized facility 66 that may be controlled by the process control system 94A may include, but are not limited to, the mixing ratio of the sand 80, chemicals 84, and produced water 88 through manipulation of the flow pumps and/or valves of the centralized facility 66, the flow rates and/or compositions of the friction reducing additive 142 and/or fluid 144 entering the low shear addition system 140 through manipulation of the flow pumps and/or valves of the centralized facility 66, the ratio of mixing the friction reducing additive 142 and the fluid 144 supplied to the low shear addition system 140 by manipulating the flow pumps and/or valves of the centralized facility 66, the flow rates and/or compositions of one or more additives 168 supplied to the low friction fracturing mixture 90 by manipulating the valves of the centralized facility 66, the flow rates of the low friction fracturing mixture 90 supplied to one or more fracturing pads 52 by manipulating the transfer pumps 164, etc.

[0091] In some embodiments, the real-time measurement data that may be collected by one or more sensors (see, for example, sensors 96 shown in FIG. 6) located around the centralized facility 66 may include, among other things, the water quality (e.g., pH, conductivity, etc.) of the water sources at the centralized facility 66 (e.g., produced water 88 received from one or more well pads 10, other water sources, etc.), the specific gravity of the sand 80, chemicals 84, produced water 88, and/or low-friction fracturing mixture 90 produced at the centralized facility 66, the turbidity of the sand 80, chemicals 84, produced water 88, and/or low-friction fracturing mixture 90 produced at the centralized facility 66, the compositions of the sand 80, chemicals 84, produced water 88 and/or low friction fracturing mixture 90 obtained at the centralized facility 66, reducing the friction of the low friction fracturing mixture 90 obtained at the centralized facility 66 compared to water (e.g. produced water 88 received from one or more drilling sites 10 and/or additional water from a water source at the centralized facility 66), etc.

[0092] Additionally, as also shown in Fig. 7, one or more process control systems 94B may be used to control operating parameters of process equipment located at one or more fracturing sites 52 and/or one or more drilling sites 10, based at least in part on real-time measurement data collected by one or more sensors located around the one or more fracturing sites 52 and/or one or more drilling sites 10. It should be understood that in embodiments in which the drilling sites 10 are also fracturing sites 52, only one process control system 94B may be used.

[0093] In some embodiments, operating parameters of the process equipment located at the one or more fracturing sites 52 and/or the one or more well sites 10 that can be controlled by the process control system 94B may include, but are not limited to, flow rates of low friction fracturing mixture 90 delivered to the one or more fracturing sites 52 via manipulation of flow pumps and/or valves of the one or more fracturing sites 52, flow rates and/or compositions of one or more additional chemicals/proppants 170 supplied to one or more blenders via manipulation of valves to control mixing of one or more proppants 170 and low friction fracturing mixture 90 via the one or more blenders, flow rates of additional water supplied to the fracturing mixture 90 formation with reduced friction, by manipulating the valves of one or more fracturing pads 52, the flow rates of the mixture 90 for fracturing the formation with reduced friction, pumped into one or more fracturing wells 48, by manipulating one or more fracturing pumps 146 and/or valves of one or more fracturing pads 52, the flow rates of produced water 88 from one or more drilling pads 10, entering the centralized facility 66, by manipulating the transfer pumps 148A of one or more drilling pads 10, etc.

[0094] In some embodiments, the real-time measurement data that may be collected by one or more sensors located around one or more fracturing sites 52 and/or one or more drilling sites 10 may include, among other things, formation treatment pressure and other operating parameters of one or more wells 22 at one or more drilling sites 10, water quality (e.g., pH, conductivity, etc.) at one or more drilling sites 10 (e.g., produced water 88), specific gravity of low-friction fracturing mixture 90, turbidity of low-friction fracturing mixture 90, compositions of low-friction fracturing mixture 90, etc.

[0095] Additionally, in some embodiments, the process control systems 94A, 94B may interact with one another such that operating parameters of process equipment located at one or more fracturing sites 52 and/or one or more drilling sites 10 may be controlled in an aggregate manner by the process control systems 94A, 94B based at least in part on real-time measurement data collected by one or more sensors (see, for example, sensors 96 shown in Fig. 6) located around the centralized facility 66, and/or operating parameters of process equipment 78 located at the centralized facility 66 may be controlled in an aggregate manner by the process control systems 94A, 94B based at least in part on real-time measurement data collected by one or more sensors located around the one or more fracturing sites 52. and/or one or more drilling sites 10. In addition, it should be understood that control of other operating parameters of the process equipment 78 located at the centralized facility 66 and/or one or more hydraulic fracturing sites 52 and/or one or more drilling sites 10 can be performed by means of the process control system 94A and/or the process control system 94B based at least in part on other real-time measurement data collected by means of one or more sensors (see for example, sensors 96 shown in Fig. 6) located around the centralized facility 66 and/or one or more hydraulic fracturing sites 52 and/or one or more drilling sites 10. In fact, control of any operating parameters of the process equipment located at the centralized facility 66 and/or one or more hydraulic fracturing sites 52 and/or one or more drilling sites 10 can be performed by means of the process control system 94A and/or the process control system 94B based at least in part on any real-time measurement data collected by means of one or more sensors (see, for example, sensors 96 shown in Fig. 6) located around the centralized facility 66 and/or one or more hydraulic fracturing sites 52 and/or one or more drilling sites 10.

[0096] As shown in Fig. 16, in some embodiments

each (or, alternatively, all) of the process control systems 94 described herein may include one or more process control modules 172 (e.g., a program of computer-executable instructions and associated data) that may be configured to perform the various functions of the embodiments described herein. In some embodiments, to perform these various functions, the process control module 172 is executed on one or more processors 174 of the process control system(s) 94, which may be coupled to one or more storage media 176 of the process control system(s) 94. Indeed, in some embodiments, one or more process control modules 172 may be stored on one or more storage media 176.

[0097] In some embodiments, one or more processors 174 may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, a digital signal processor (DSP), or other control or computing device. In some embodiments, one or more storage media 176 may be implemented as one or more non-volatile computer-readable or machine-readable storage media. In some embodiments, one or more storage media 176 may include one or more different forms of memory, including semiconductor memories such as dynamic or static random access memories (DRAM or SRAM), erasable programmable read-only memories (EPROM), electrically erasable programmable read-only memories (EEPROM), and flash memory; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact discs (CDs) or digital video discs (DVDs); or other types of information storage devices. It should be noted that the computer-executable instructions and associated data of the process control module(s) 172 may be provided on a single computer-readable or machine-readable storage medium of storage media 176 or, alternatively, may be provided on a plurality of computer-readable or machine-readable storage media distributed over a large system, possibly having a plurality of nodes. Such a computer-readable or machine-readable storage medium or media are considered to be part of an article of manufacture (or an article of manufacture), which may refer to any single component manufactured or a plurality of components. In some embodiments, one or more storage media 176 may either be located on a machine executing the machine-readable instructions or located on a remote site from which the machine-readable instructions may be downloaded over a network for execution.

[0098] In some embodiments, the processor(s) 174 may be coupled to the communication circuit 178 of the process control system(s) 94 to enable the process control system(s) 94 to communicate with various sensors, various process equipment of the centralized facility 66 and/or one or more fracturing sites 52 and/or one or more drilling sites 10 (as well as other systems described herein), etc., to control the operation of the systems described in more detail herein. In some embodiments, the communication circuit 178 may also assist the process control system(s) 94 in transmitting data to the cloud storage 180 (or other wired and/or wireless communication network) for, for example, archiving data or to enable external computing systems 182 to access data and/or remotely interact with the process control system(s) 94.

[0099] In some embodiments, the communication circuit 178 may be, include, or be implemented via various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular network interface, and/or a satellite network interface, among others. In some embodiments, the communication circuit 178 may also include a communication device, such as a modem or a network interface card, to facilitate data exchange with external computing devices via a network (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, a coaxial cable, a cellular telephone network system, a satellite, etc.).

[00100] In some embodiments, the low-friction fracturing mixture, additional water, one or more additives 168, and other fluids may be transported from the centralized facility 66 to one or more fracturing sites 52 simultaneously via one or more fracturing mixture conduits 74. For example, in some embodiments, the one or more fracturing mixture conduits 74 may include a plurality of conduits 74 arranged in parallel with one another, wherein each of the conduits 74 transports a different fluid than the others.

[00101] As shown in Fig. 17, in some embodiments, a single conduit 74A may include an outer pipe 184 with an inner pipe 186 disposed concentrically within the outer pipe 184. Thus, the interior of the inner pipe 186 forms an inner volume 188, and the annular space between the outer pipe 184 and the inner pipe 186 forms an outer volume 190. In such an embodiment, a first fluid may be transported from the centralized facility 66 to one or more fracturing sites 52 through the inner volume 188 of the conduit 74A simultaneously with a second fluid being transported from the centralized facility 66 to the one or more fracturing sites 52 through the outer volume 190 of the conduit 74A. For example, in some embodiments, the low-friction fracturing mixture 90 may be transported from the centralized facility 66 to the one or more fracturing sites 52 through the internal volume 188 of the conduit 74A concurrently with additional water (e.g., non-friction-reduced water) transported from the centralized facility 66 to the one or more fracturing sites 52 through the external volume 190 of the conduit 74A. In other embodiments, additional water (e.g., non-friction-reduced water) may be transported from the centralized facility 66 to the one or more fracturing sites 52 through the internal volume 188 of the conduit 74A concurrently with the low-friction fracturing mixture 90 transported from the centralized facility 66 to the one or more fracturing sites 52 through the external volume 190 of the conduit 74A. In fact, any combinations of the low friction fracturing mixture 90, additional water, one or more additives 168, and other fluids may be transported from the centralized facility 66 to one or more fracturing sites 52 through various volumes 188, 190 of the pipeline 74A shown in Fig. 17.

[00102] as shown in Fig. 18, in other embodiments, a single conduit 74B may include an outer pipe 184 and a plurality of inner pipes 186A, 186B located within the outer pipe 184. Thus, the interiors of each of the inner pipes 186A, 186B form respective internal volumes 188A, 188B, and the annular space between the outer pipe 184 and the inner pipes 186A, 186B forms an outer volume 190. In such an embodiment, a first fluid may be transported from the centralized facility 66 to the one or more fracturing sites 52 through the first internal volume 188A of the conduit 74B simultaneously with a second fluid transported from the centralized facility 66 to the one or more fracturing sites 52 through the second internal volume 188B of the conduit 74B simultaneously with a third fluid transported from the centralized facility 66 to one or more fracturing sites 52 through the outer volume 190 of the conduit 74B. In particular, any combinations of the low-friction fracturing mixture 90, additional water, one or more additives 168 and other fluids can be transported from the centralized facility 66 to one or more fracturing sites 52 through various volumes 188, 190 of the conduit 74B shown in Fig. 18. Although in Fig. 18 the conduit 74B is illustrated as including two inner pipes 186A, 186B, in other embodiments it can include any number (e.g., two, three, four, five or even more) of inner pipes 186.

[00103] In some embodiments, the various volumes 188, 190 of the conduits 74A, 74B shown in FIG. 17 and 18, may be employed to facilitate multi-directional flow of fluids through volumes 188, 190. For example, while in some embodiments certain fluids may flow in a unidirectional manner from the centralized facility 66 to one or more fracturing sites 52 in respective volumes 188, 190 of conduits 74A, 74B, in other embodiments a first fluid may flow from the centralized facility 66 to the one or more fracturing sites 52 through one of volumes 188, 190, while a second fluid may flow in the opposite direction from the one or more fracturing sites 52 to the centralized facility 66 in another of volumes 188, 190. As just one non-limiting example, in an embodiment in which the fracturing site 52 also serves as the site 10 of a production well, produced water 88 from the site 52 hydraulic fracturing fluid may be transported to the centralized facility 66 through one of the volumes 188, 190 of the pipeline 74A, 74B, while the mixture 90 for hydraulic fracturing fluid may be transported from the centralized facility 66 to the hydraulic fracturing site 52 through another of the volumes 188, 190 of the pipeline 74, 74B.

[00104] Referring now to Figs. 6, 13, and 16, as described in greater detail herein, one or more process control systems 94 may be configured to control any and all operating parameters of the centralized facility 66 and/or one or more drilling sites 10 and/or one or more fracturing sites 52. For example, in some embodiments, one or more process control systems 94 may be configured to control flow rates of a plurality of fluids transported via the conduits 74 shown in Fig. 17 and 18, wherein the mixing ratios between the fluids transported therein are adjusted to achieve a desired final state or final concentration at one or more fracturing sites 52 to achieve optimal friction reduction for specific operating conditions of one or more fracturing wells 48 at one or more fracturing sites 52 (e.g., determined by one or more process control systems 94 based on real-time measurement data collected by sensors at the centralized facility 66 and/or one or more fracturing sites 52 and/or one or more drilling sites 10). For example, in some embodiments, one or more process control systems 94 may be configured to manipulate valves associated with respective volumes 188, 190 of conduits 74 to achieve appropriate mixing ratios between fluids transported via volumes 188, 190 to produce a final fracturing mixture 90 with reduced friction based on specific operating conditions of one or more fracturing wells 48 at one or more fracturing sites 52.

[00105] Similarly, in some embodiments, one or more process control systems 94 may be configured to select a particular friction reducing additive 142 (e.g., from a plurality of friction reducing additives 142) to add to water in a low-shear addition system 140 at a centralized facility 66 to produce a reduced-friction fracturing mixture 90 based on specific operating conditions of one or more fracturing wells 48 at one or more fracturing sites 52. For example, in some embodiments, one or more process control systems 94 may analyze the compositions of the fluid 144 to which the friction reducing additive 142 is added and, based on the particular operating conditions of the one or more fracturing wells 48 at one or more fracturing sites 52, may determine that a particular friction reducing additive 142 (e.g., from a plurality of friction reducing additives 142) and/or a particular concentration of the friction reducing additive 142 may be ideally suited to convert the fluid 144 into a fracturing mixture 90 with reduced friction that will meet the particular operating conditions of the one or more fracturing wells 48 at one or more fracturing sites 52. In addition, in some embodiments, the selection of a particular friction reducing additive 142 (e.g., from a plurality of friction reducing additives 142) and/or a particular concentration of the friction reducing additive 142 may be determined by one or more process control systems 94 based at least in part on performance parameters of one or more wells 22 at one or more wellsites 10, such as may be derived by one or more process control systems 94 from archived performance measurement data of one or more wells 22 (e.g., archived in cloud storage 180).

[00106] The specific embodiments described above have been presented by way of example, and it should be understood that these embodiments may be subject to various modifications and may have alternative forms. Furthermore, it should be understood that the claims are not intended to be limited to the specific forms disclosed, but rather are provided to cover all modifications, equivalents and alternatives that fall within the spirit and scope of the present invention.

Claims (31)

1. A method of hydraulic fracturing, including: dewatering the fracturing mixture at a centralized facility, wherein the dewatering comprises removing at least a portion of the water from the fracturing mixture; using a low shear addition system at a centralized facility to add a friction reducing additive to a fracturing mixture to produce a fracturing mixture with reduced friction, wherein the low shear addition system comprises at least one ejector or at least one auger; transporting the low friction fracturing mixture from the centralized facility to at least one fracturing pad via at least one pipeline; and injecting a low friction fracturing fluid into a reservoir to stimulate at least one well at said at least one fracturing site. 2. The method of claim 1, wherein the centralized facility is located outside of said at least one hydraulic fracturing site, and said at least one pipeline has a length of at least two miles. 3. The method according to claim 1, characterized in that transporting the low-friction hydraulic fracturing mixture from a centralized facility to said at least one hydraulic fracturing site includes using at least one transfer pump for pumping the low-friction hydraulic fracturing mixture through said at least one pipeline. 4. The method according to claim 3, characterized in that said at least one pipeline comprises an outer pipe and one or more inner pipes located inside the outer pipe, wherein the inner parts of one or more inner pipes form a corresponding one or more internal volumes, and the annular space between the outer pipe and one or more inner pipes forms an outer volume. 5. The method of claim 4, further comprising transporting the low-friction fracturing mixture from the centralized facility to said at least one fracturing site via one of the one or more internal volumes and the external volume and transporting another fluid from said at least one fracturing site to the centralized facility via the other one of the one or more internal volumes and the external volume. 6. The method according to claim 1, characterized in that the low-shear addition system comprises said at least one ejector, including a gravity-fed ejector configured to feed a friction-reducing additive into the fracturing mixture by gravity. 7. The method according to claim 1, characterized in that the low-shear addition system comprises said at least one ejector, including a pneumatic ejector, configured to pneumatically disperse the friction-reducing additive into the mixture for hydraulic fracturing. 8. The method according to claim 1, characterized in that the low-shear addition system comprises said at least one auger, including a gravity-fed auger system. 9. The method of claim 1, further comprising adding an additive to the low-friction fracturing mixture at a centralized facility prior to transporting the low-friction fracturing mixture to said at least one fracturing site. 10. The method of claim 9, wherein the additive comprises at least one of a biocide, a flowback surfactant, an acid, a clay stabilizer, a marker element, a scale inhibitor, an oxygen scavenger, a hydrogen sulfide scavenger, a reducing agent, a chelating agent, an iron control agent, an anti-emulsifying agent, a demulsifier, a thinner, a corrosion inhibitor, a pipeline cleaner, or a gel plug. 11. The method according to claim 1, characterized in that the friction-reducing additive comprises at least one of polyacrylamide, partially hydrolyzed polyacrylamide, cross-linked polyacrylamide, polymethacrylamide, partially hydrolyzed polymethacrylamide, or cross-linked polymethacrylamide. 12. The method according to claim 1, characterized in that the friction-reducing additive comprises a copolymer of at least one of polyacrylamide, partially hydrolyzed polyacrylamide, cross-linked polyacrylamide, polymethacrylamide, partially hydrolyzed polymethacrylamide, or cross-linked polymethacrylamide. 13. A system for hydraulic fracturing, comprising: a dewatering system located at a centralized facility and configured to remove at least a portion of the water from the fracturing mixture; a low shear addition system located at a centralized facility and configured to add a friction reducing additive to the fracturing mixture to produce a fracturing mixture with reduced friction, wherein the low shear addition system comprises at least one ejector or at least one auger; and at least one transfer pump configured to pump the fracturing mixture with reduced friction through at least one pipeline to at least one fracturing site. 14. The system according to item 13, characterized in that the mixture for hydraulic fracturing contains water received at a centralized facility. 15. The system according to claim 13, characterized in that said at least one pipeline comprises an outer pipe and one or more inner pipes located inside the outer pipe, wherein the inner parts of one or more inner pipes form corresponding internal volumes, and the annular space between the outer pipe and one or more inner pipes forms the external volume. 16. The system of claim 13, wherein the low shear addition system comprises said at least one ejector, including a gravity-fed ejector configured to supply a friction-reducing additive to the fracturing mixture by gravity. 17. The system of claim 13, wherein the low shear addition system comprises said at least one ejector comprising a pneumatic ejector configured to pneumatically disperse the friction reducing additive into the fracturing mixture. 18. The system of claim 13, wherein the low shear addition system comprises said at least one auger, including a gravity fed auger system. 19. A method of hydraulic fracturing, comprising: adding a friction reducing additive to a fluid to form a low friction fracturing mixture using a low shear addition system at a centralized facility, wherein the low shear addition system comprises at least one ejector or at least one auger configured to disperse the friction reducing additive into the fluid; transporting the low friction fracturing mixture from the centralized facility to at least one fracturing pad in a first direction through a first passage of a first pipe located inside the outer pipe; injecting a low friction fracturing fluid into the reservoir to stimulate at least one well at said at least one fracturing pad; and transporting water from said at least one hydraulic fracturing site to a centralized facility in a second direction through a second passage, wherein the second passage is an annular space between the outer portion of the first pipe and the inner portion of the outer pipe, wherein the first and second directions are opposite to each other. 20. The method according to claim 19, characterized in that transporting the low-friction fracturing mixture from a centralized facility to said at least one fracturing site includes using at least one transfer pump for pumping the low-friction fracturing mixture through at least one pipeline.