HIGH-PRESSURE FLUID ENDS FOR DRILLING AND FRACTURE APPLICATIONS

Abstract

A piston-style pump having a pressure rating of at least 8,500 psi is employed for pumping drilling fluid into a borehole during drilling operations. After the drilling operations, the same pump is employed for pumping fluid for fracturing operations into the borehole. The pump body is formed of a corrosion resistant material such as stainless steel. The gaskets employes on the pump are preferably R or BX gasket sand ring joints.

Description

CROSS-REFERENCE TO RELATED APPLICATION(S) AND CLAIM FOR PRIORITY

This application claims priority to U.S. Provisional Ser. No. 63/737,454 filed Dec. 20, 2024. The subject matter of the above-identified patent document(s) is incorporated herein by reference.

TECHNICAL FIELD

This disclosure relates generally to mud pumps used for well drilling. More specifically, this disclosure relates to improving the suitability of drilling mud pumps for use in other applications such as fracturing.

BACKGROUND

The fluid end for drilling (“mud”) pumps are typically rated for, at most, 7,500 pounds per square inch (psi). Drilling operators are limited by such relatively low pressures. As operators are pushing the limit of drilling rigs, the advances possible with currently available system have reached a technical limit.

SUMMARY

A piston-style pump having a fluid end with a pressure rating of at least 8,800 psi is employed for pumping drilling fluid into a borehole during drilling operations. After the drilling operations, the same pump is employed to fluid for fracturing operations into the borehole. The mono block body of the fluid end is formed of stainless steel or a material having similar characteristics with respect to strength, hardness, and corrosion resistance. The gaskets employes on the pump are preferably R or BX gasket sand ring joints.

In a first implementation, a pump fluid end includes a body have wall thickness selected for a pump pressure rating of at least 8,500 pounds per square inch (psi), at least a portion of the body made of material selected for corrosion resistance. The pump fluid end also includes gaskets at interfaces between the body selected for longer durability over rubber or plastic gaskets.

In a second implementation, a method includes utilizing a pump having a pump pressure rating of at least 8,500 pounds per square inch (psi) to pump drilling fluid into a borehole during drilling operations. The method further includes, after the drilling operations, utilizing the pump to pump fluid for fracturing operations into the borehole.

Other technical features may be readily apparent to one skilled in the art from the following figures, descriptions, and claims.

Unless defined otherwise herein, all technical and scientific terms used herein have the meaning as commonly understood by one of ordinary skill in the art within the context of the disclosure, and in the specific context where each term is used. It will further be understood that common terms and phrases, such as those defined in commonly-used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the relevant art and should not be interpreted in an idealized or overly formal sense unless expressly so defined here. However, so that the present disclosure may be more readily understood, before undertaking the DETAILED DESCRIPTION below, it may be advantageous to set forth definitions of certain words and phrases used throughout this patent document. Therefore, certain terms are first defined, and additional definitions are set forth throughout the document.

The terms “include” and “includes,” as well as derivatives thereof, mean inclusion without limitation. The term “or” is inclusive, meaning and/or. The phrase “associated with,” as well as derivatives thereof, means to include, be included within, interconnect with, contain, be contained within, connect to or with, couple to or with, be communicable with, cooperate with, interleave, juxtapose, be proximate to, be bound to or with, have, have a property of, have a relationship to or with, or the like.

As used here, terms and phrases such as “have,” “may have,” “include,” or “may include” a feature (like a number, function, operation, or component such as a part) indicate the existence of the feature and do not exclude the existence of other features. Also, as used here, the phrases “A or B,” “at least one of A and/or B,” or “one or more of A and/or B” may include all possible combinations of A and B. For example, “A or B,” “at least one of A and B,” and “at least one of A or B” may indicate all of (i) including at least one A, (ii) including at least one B, or (iii) including at least one A and at least one B. Further, as used here, the terms “first” and “second” may modify various components regardless of importance and do not limit the components. These terms are only used to distinguish one component from another. For example, a first user device and a second user device may indicate different user devices from each other, regardless of the order or importance of the devices. A first component may be denoted a second component and vice versa without departing from the scope of this disclosure.

It will be understood that, when an element (such as a first element) is referred to as being (operatively or communicatively) “coupled with/to” or “connected with/to” another element (such as a second element), it can be coupled or connected with/to the other element directly or via a third element. In contrast, it will be understood that, when an element (such as a first element) is referred to as being “directly coupled with/to” or “directly connected with/to” another element (such as a second element), no other element (such as a third element) intervenes between the element and the other element. The terms “connect,” “connected,” “contact,” “coupled,” and/or the like are broadly defined herein to encompass a variety of divergent arrangements and assembly techniques. These arrangements and techniques include, but are not limited to, (i) the direct joining of one component and another component with no intervening components therebetween (such as the components are in direct physical contact); and (ii) the joining of one component and another component with one or more components therebetween, provided that the one component being “connected to” or “contacting” or “coupled to” the other component is somehow in operative communication (such as electrically, fluidly, physically, optically, etc.) with the other component (notwithstanding the presence of one or more additional components therebetween). It is to be understood that some components that are in direct physical contact with one another may or may not be in electrical contact and/or fluid contact with one another. Moreover, two components that are electrically connected, electrically coupled, optically connected, optically coupled, fluidly connected, or fluidly coupled may or may not be in direct physical contact, and one or more other components may be positioned therebetween.

As used here, the phrase “configured (or set) to” may be interchangeably used with the phrases “suitable for,” “having the capacity to,” “designed to,” “adapted to,” “made to,” or “capable of” depending on the circumstances. The phrase “configured (or set) to” does not essentially mean “specifically designed in hardware to.” Rather, the phrase “configured to” may mean that a device can perform an operation together with another device or parts. For example, the phrase “processor configured (or set) to perform A, B, and C” may mean a generic-purpose processor (such as a CPU or application processor) that may perform the operations by executing one or more software programs stored in a memory device or a dedicated processor (such as an embedded processor) for performing the operations.

The terms and phrases as used here are provided merely to describe some implementations of this disclosure but not to limit the scope of other implementations of this disclosure. It is to be understood that the singular forms “a,” “an,” and “the” include plural references unless the context clearly dictates otherwise. The term “plurality” refers to more than one element. That is, as used herein, the term “plurality” is intended to mean a population of two or more different members.

The terms “substantially,” “approximately,” “about,” “relatively,” or other such similar terms that may be used throughout this disclosure, including the claims, are used to describe and account for small fluctuations, such as due to variations in processing, from a reference or parameter. Such small fluctuations include a zero fluctuation from the reference or parameter as well. For example, fluctuations can refer to less than or equal to ±10%, such as less than or equal to ±5%, such as less than or equal to ±2%, such as less than or equal to ±1%, such as less than or equal to ±0.5%, such as less than or equal to ±0.2%, such as less than or equal to ±0.1%, such as less than or equal to ±0.05%.

Definitions for other certain words and phrases may be provided throughout this document. Those of ordinary skill in the art should understand that in many if not most instances, such definitions apply to prior as well as future uses of such defined words and phrases. In some cases, the terms and phrases defined here may be interpreted to exclude implementations of this disclosure.

None of the description in this application should be read as implying that any particular element, step, or function is an essential element that must be included in the claim scope. The scope of patented subject matter is defined only by the claims. Moreover, none of the claims is intended to invoke 35 U.S.C. § 112(f) unless the exact words “means for” are followed by a participle. Use of any other term, including without limitation “mechanism,” “module,” “device,” “unit,” “component,” “element,” “member,” “apparatus,” “machine,” “system,” “processor,” or “controller,” within a claim is understood to refer to structures known to those skilled in the relevant art and is not intended to invoke 35 U.S.C. § 112(f).

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of this disclosure and its advantages, reference is now made to the following description taken in conjunction with the accompanying drawings, in which like reference numerals represent like parts:

FIG. 1 is a schematic diagram illustrating one or more aspects of a drilling rig apparatus which may employ a pump having a high-pressure fluid end in accordance with the present disclosure;

FIG. 2 diagrammatically illustrates a pump having a high-pressure fluid end in accordance with the present disclosure;

FIGS. 3A through 3D are various views illustrating a pump having a high-pressure fluid end in accordance with the present disclosure;

FIGS. 4 and 4A through 4J illustrate a fluid end according to embodiments of the present disclosure; and

FIG. 5 illustrates an example process of employing a pump having a high-pressure fluid end in accordance with the present disclosure.

DETAILED DESCRIPTION

FIGS. 1 through 5, described below, and the various implementations used to describe the principles of the present disclosure are by way of illustration only and should not be construed in any way to limit the scope of this disclosure. Those skilled in the art will understand that the principles of the present disclosure may be implemented in any type of suitably arranged device or system.

The fluid end for a pump system disclosed herein can produce output pressure of at least 8,500 psi, preferably higher (e.g., up to or in excess of 10,000 psi). In one aspect of the present disclosure, the high-pressure output opens a capability for drilling rigs/mud pumps to be used for fracturing operations (“fracking”) as well as drilling. For pad drilling, for instance, as the rig completes the production section of the well and walks to next section, the previous well may be fractured using the drilling mud pumps. This brings production online sooner, reducing operator cost, environmental impact, and location footprint.

The design for the fluid end in the present disclosure may be a single “mono block” design either with or without an integral discharge manifold, as well as a combination of different materials selected for optimized application results. In some embodiments, stainless steel is utilized, which is atypical for drilling mud pumps but will increase the pump life and corrosion resistance capability of the mud pump.

In the present disclosure, L and Y shaped fluid end designs may be employed. Different sealing elements using a distinct philosophy may be employed. For example, for piston style pump designs in particular (preferable to plunger style designs for the purposes of the present disclosure), R or BX style sealing elements may be used between separate components.

FIG. 1 is a schematic diagram illustrating one or more aspects of a drilling rig apparatus which may employ a pump having a high-pressure fluid end in accordance with the present disclosure. The embodiment illustrated in FIG. 1 is for illustration and explanation only. FIG. 1 does not limit the scope of this disclosure to any particular implementation.

The drilling rig apparatus 100 includes an elevated rig floor 112 and a derrick 114 extending above the rig floor 112. A supply reel 116 supplies drilling line 118 to a crown block 120 and traveling block 122 configured to hoist various types of drilling equipment above the rig floor 112. The drilling line 118 is secured to a deadline tiedown anchor 124, and a draw works 126 regulates the amount of drilling line 118 in use and, consequently, the height of the traveling block 122 at a given moment. Below the rig floor 112, a tubular string 128 extends downward into a wellbore 130 and can be held stationary with respect to the rig floor 112 by a rotary table 132 or slips 134. A portion of the tubular string 128 extends above the rig floor 112, forming a stickup (or stump) 136 to which another length of tubular 138 (shown in phantom) may be added.

When a new length of tubular 138 is added to the tubular string 128, a pipe handler (not shown) can position the tubular 138 over the stickup 136 in alignment with the center axis 148 of the tubular string 128 and connect the new tubular 138 to the stickup 136. A top drive 140, raised and lowered by a traveling block 122, can be lowered to engage with the top of the tubular 138. The top drive 140 can utilize a grabber system 154 to hold the tubular 138 while the top drive 140 is coupled to the tubular. The grabber system 154 may include a positioner 156 coupled to the top drive 140, a backup wrench 158 coupled to the end of the positioner 156 and configured to grab the tubular 138, and an instrumented sub support 159 configured to couple an instrumented sub 146 to the positioner 156.

A pivot joint 170 can be coupled to a running tool 171, which can be engaged with a tubular 138. The tubular 138 can then be lowered to engage the stickup 136 and the top drive 140 may rotate the tubular 138 to connect the tubular 138 to the tubular string 128 (e.g., a casing string). Specifically, the top drive 140 can include a quill 142, an instrumented sub 146, and a sub 144 (e.g., a crossover sub) to turn the pivot joint 170 and thus the tubular 138. The tubular 138 may be coupled to the pivot joint 170, which can be coupled to the sub 144 and the instrumented sub 146, which in turn can be coupled to the top drive 140 via the quill 142. In certain embodiments, the instrumented sub 146 may include threads on both axial ends to couple to the sub 144 and the quill 142.

Furthermore, the top drive 140 can couple with the tubular 138 in a manner that enables translation of motion to the tubular 138. Indeed, in the illustrated embodiment, the top drive 140 is configured to supply torque for making-up and breaking out a coupling between the tubular 138 and the stickup 136. However, torque for making-up and breaking out a coupling between the tubular 138 and the stickup 136 can alternatively, or in addition to, be supplied by other equipment, such as a pipe handler (not shown) or an iron roughneck (not shown).

To facilitate the circulation of mud or other drilling fluid within the wellbore 130, the drilling rig 110 includes a mud pump 149 configured to pump mud or drilling fluid up to the top drive 140 through a mud hose 150. In certain embodiments, the mud hose 150 may include a standpipe 151 coupled to the derrick 114 in a substantially vertical orientation to facilitate pumping of mud. The standpipe 151 provides a high-pressure path for mud to flow up the derrick 114 to the top drive 140. From the mud hose 150 (e.g., standpipe 151), the mud flows through a Kelly hose 153 to the top drive 140. From the top drive 140, the drilling mud will flow through internal passages of the instrumented sub 146 and the pivot joint, into internal passages of the tubular 138 and the tubular string 128, and into the wellbore 130 at the bottom of the well. The drilling mud flows within the wellbore 130 (e.g., in an annulus 131 between the tubular string 128 and the wellbore 130) and back to the surface where the drilling mud may be recycled (e.g., filtered, cleaned, and pumped back up to the top drive 140 by the mud pump 149).

When a new length of tubular 138 is to be added to the tubular string 128, mud flow from the mud pump 149 and the mud hose 150 can be stopped, and the top drive 140 decoupled from the tubular string 128 (i.e., the length of the tubular 138 that was most recently added to the tubular string 128). When the top drive 140 releases the tubular string 128, mud within the top drive 140 may run out of the top drive 140 and onto the rig floor 112. To avoid spilling mud onto the rig floor 112, the instrumented sub 146 can be included to block mud from inadvertently flowing out of the top drive 140 when the mud pump 149 is not pumping mud. When the top drive 140 is thereafter coupled to a new length of tubular 138 and the mud pump 149 resumes a pumping operation, the instrumented sub 146 may enable flow of mud through the instrumented sub 146 and the top drive 140 to the tubular 138 and tubular string 128. A rig controller 160 can be used to control the subterranean operation, by controlling mud flow through the top drive 140 and tubular string 128, controlling top drive operation, and receiving sensor data from various sensors. The tubular string 128 can include a bottom hole assembly (BHA) that can include a drill bit used to extend the wellbore 130 through the surface 106 and into the formation 108, or as in a casing string, the bottom hole assembly can include a float shoe 176 for cementing operations.

In a non-limiting embodiment, the rig 110 may be manipulating a casing string (e.g., the tubular string 128) with a running tool (RT) 171 to lift or lower a tubular 138 (or tubular string 128) during the subterranean operations (e.g., running a casing string). It should be understood that the running tool 171 can also be used for tubular strings 128 other than a casing string. A pair of links 162 can be used to suspend an elevator 164 from the top drive 140, but the elevator 164 (as shown) can be rotated out of the way from the tubular string when the pivot joint 170 is being used.

The pivot joint 170 can be used, along with the running tool 171 to collect a tubular 138 from a pipe handler (e.g., a catwalk) and lift the tubular 138 to be vertically positioned over the stickup 136. The top drive 140 (via the traveling block) can be lowered to lower the tubular 138 onto the stickup 136. The top drive 140 can operate the running tool 171 to engage the tubular 138, such as by sending hydraulic or electrical signals to the running tool 171 to radially expand the running tool 171 within the tubular 138. The running tool 171 can then rotate the tubular 138 to couple the tubular 138 to the stickup 136. The top drive 140 can then be lowered to lower the tubular string 128 further into the wellbore 130 until the tubular string 128 is at the correct stickup height. The top drive 140 can then disengage the running tool 171 from the tubular 138 and engage a new tubular 138 (e.g., from the catwalk). The top drive 140 can then be raised to an appropriate height to repeat the process to add the new tubular 138 to the tubular string 128.

The mud pump 149 is part of a mud pump system and receives the drilling fluid, or mud, from a mud tank assembly 172, delivering the mud to the tubular string 128 through the mud hose 150 or other conduit, which may be fluidically and/or actually connected to the top drive 140. As more mud is pushed through the tubular string 128, the mud flows through the bottom hole assembly and fills the annulus 131 that is formed between the tubular string 128 and the inside of the wellbore 130, and is pushed to the surface. At the surface the mud tank assembly 172 recovers the mud from the annulus and separates out the cuttings. The mud tank assembly 172 may include a boiler, one or more mud mixer(s), a mud elevator, and one or more mud storage tank(s). After cleaning the mud, the mud is transferred from the mud tank assembly 172 to the mud pump 149 via a conduit 173, which may be a single conduit or a plurality of conduits. When the circulation of the mud is no longer needed, the mud pump 149 may be removed from the drill site and transferred to another drill site. The mud pump 149 includes a power end and a fluid end.

Those skilled in the art will understand that all details of the full structure of the drilling rig apparatus 100 are not depicted in the schematic diagram of FIG. 1, and that all details for a complete description of the operation of the drilling rig apparatus 100 are not provided herein. Instead, for simplicity and clarity, only so much of the structure and operation of the drilling rig apparatus 100 as is necessary for an understanding of the present disclosure is provided.

FIG. 2 diagrammatically illustrates a pump having a high-pressure fluid end in accordance with the present disclosure. The embodiment illustrated in FIG. 2 is for illustration and explanation only. FIG. 2 does not limit the scope of this disclosure to any particular implementation.

The pump 200 of FIG. 2 may be the mud pump 149 within the drilling rig apparatus 100 of FIG. 1. The pump 200 in the example shown is a multi-cylinder reciprocating pump that includes a power end 201 (a/k/a “motor end”) and a fluid end 202. On a reciprocating pump such as a mud pump used for oil and gas drilling, the power end 201 is constructed and operates as disclosed in, for example, U.S. Patent Application Publication No. 2018/0355862, which is incorporated herein by reference. FIG. 2 is a simplified diagram illustrating construction of the power end 201, with fluid flow through the fluid end 202 depicted diagrammatically.

As depicted in FIG. 2, the power end 201 of a reciprocating mud pump includes a housing 203 within which are disposed cylinders 204 each positioned to receive piston 205. In some embodiments, each of the cylinders 204 may include liner 206 positioned between inner surface 207 of each of the cylinders 204 and piston 205. In some embodiments, piston 205 may be formed from a polymer such as an elastomer. In some embodiments, liner 206 may be formed from a metal such as steel. In some embodiments, liner 206 may include an inner sleeve made of, for example and without limitation, chrome iron or ceramic. Each of pistons 205 and corresponding liner 206 may form a fluid seal. In some embodiments, each piston 205 may be driven in a reciprocating motion within the respective liner 206 by rotation of crankshaft 208. Crankshaft 208 may rotate concentrically within the housing 203. Crankshaft 208 may include connecting rod journals 209 corresponding to each piston 205. Each connecting rod journal 209 may be offset from the axis of rotation of crankshaft 208. Each piston 205 may be mechanically coupled to crankshaft 208 by a corresponding connecting rod 210. Each connecting rod 210 may translate eccentric rotation of a corresponding connecting rod journal 209 part of crankshaft 208 to a linear reciprocating motion of the corresponding piston 205. Crankshaft 208 may be driven by motor 211, which may be, for example and without limitation, an electric motor, gasoline motor, or any other rotational input.

Each piston 205 may define a corresponding pumping chamber 212 within the respective cylinder 204. Pumping chamber 212 may be fluidly coupled to fluid inlet 213 (depicted schematically) through intake valve 214 (a/k/a “suction valve”) and to fluid outlet 215 (also depicted schematically) through discharge valve 216. Each intake valve 214 and discharge valve 216 may be check valves positioned to allow fluid flow into pumping chamber 212 from fluid inlet 213 and fluid flow out of pumping chamber 212 to fluid outlet 215. As each piston 205 reciprocates within the respective cylinder 204, the volume of the corresponding pumping chamber 212 repeatedly increases and decreases. As pumping chamber 212 increases in volume, fluid enters the pumping chamber 212 through suction valve 214 from fluid inlet 213. As pumping chamber 212 decreases in volume, fluid leaves pumping chamber 212 through discharge valve 216 to fluid outlet 215. Continued operation of power end 201 therefore causes fluid to be pumped from fluid inlet 213 to fluid outlet 215.

In some embodiments, the distance that each piston 205 reciprocates defines a stroke length L. With a full rotation of crankshaft 208, each piston 205 travels two stroke lengths, defining a piston cycle distance. In some embodiments, a pressure transducer 217 may be fluidly coupled to fluid outlet 215 to measure the pressure of fluid discharged from flow end of the mud pump 200. In other embodiments, the discharge pressure may be measured using strain gauges or any other suitable pressure measurement systems. In some embodiments, the cycle rate of crankshaft 208, and therefore the average velocity of each piston 205 during pumping, may be determined from the rotation rate of or measured by motor 211 as measured by a sensor at the motor output or at the pump input. In other embodiments, the rotation rate of crankshaft 208 may be determined by a rotation sensor 218, which may be positioned to determine the number of revolutions of crankshaft 208 for use in determining the rotation rate thereof. Rotation sensor 218 may include, without limitation, one or more of a hall sensor, optical sensor, mechanical sensor, encoder, or other useful sensor.

FIGS. 3A through 3D are various views illustrating a pump system having a high-pressure fluid end in accordance with the present disclosure. FIG. 3A is a top plan view, FIGS. 3B and 3C are opposing side elevation views, and FIG. 3D is an end view of the pump system. The embodiment illustrated in FIGS. 3A through 3D are for illustration and explanation only. FIGS. 3A through 3D do not limit the scope of this disclosure to any particular implementation. It should be noted that FIGS. 3A through 3D depict a mono block fluid end design. However, a split block (a/k/a modular) fluid end design may alternatively be implemented, and benefits associated with the fluid end designs described herein may be achieved with either a mono block or split block design.

As noted above, the pump 200 of FIGS. 3A through 3D may be the mud pump 149 within the drilling rig apparatus 100 of FIG. 1. The fluid end 202 depicted in FIGS. 3A through 3D is one design for the fluid end of pump 200. In the example shown, fluid end 202 includes a body and three substantially identical instances of a fluid intake connections and corresponding fluid intake valve cover assemblies. The fluid end 202 also includes at least one fluid discharge connection, and three fluid discharge valve cover assemblies. In the exemplary embodiment, however, fluid discharge is integrated with the body, rather than a separate (generally removable) module (a/k/a “discharge header”). In addition, although an L-shaped fluid end is described herein, those skilled in the art will understand that the principles described may be readily applied to a Y-shaped fluid end.

FIGS. 4 and 4A through 4J illustrate a fluid end according to embodiments of the present disclosure. FIG. 4 is a perspective view of the fluid end 402 with an attached strainer cross. FIG. 4A is a front elevation view, FIG. 4B is a top plan view, and FIG. 4C is an end view of the fluid end 402 shown in FIG. 4A. FIG. 4D is a front elevation view of the body 401 (alone) of the fluid end 402. FIG. 4E is a top plan view, FIG. 4F is a bottom plan view, FIG. 4G is an end view, and FIG. 4H is a rear elevation view, all corresponding views to the fluid end body 401 shown in FIGS. 4A through 4D. FIG. 4I is a sectional view taken at section line J-J in FIG. 4G. FIG. 4J is a sectional view taken at section line K-K in FIG. 4A. The embodiment illustrated in FIGS. 4 and 4A through 4J is for illustration and explanation only. FIGS. 4 and 4A through 4J do not limit the scope of this disclosure to any particular implementation.

The fluid end 402 illustrated by FIGS. 4 and 4A through 4J is one design for the fluid end 202 of the triplex pump 200. In the example shown, fluid end 402 includes a body 401 of a mono block design—that is, valves for both fluid intake and fluid discharge are integrated into the body 401 rather than implemented within removable modules secured to the body. The fluid end 402 still includes fluid intake valve cover assemblies 404 and fluid discharge valve cover assemblies 406 (analogous to the counterpart assemblies in FIGS. 3A through 3D). The fluid end 402 is depicted in FIGS. 4 and 4A-4B with a strainer cross 405 attached, connected to the fluid discharge bore opening 403 (best seen in the end views of FIGS. 4C and 4G). FIG. 4C shows the fluid end 402 without the strainer cross 405.

The exemplary fluid end 402 is for a piston-style pump, but alternative embodiments may operate in conjunction with a plunger-style pump. The mono block body 401 may be stainless steel, a strong and corrosion resistant material, such as (for example) 4130 or 4140 steel. That construction may render the fluid end 402 relatively heavy (e.g., about 7,000 to 8,000 pounds), possibly implicating special handling requirements in the field for some applications. However, the pump 200 including the fluid end 402 is preferably rated for at least, 500 psi and therefore may be reliably employed for both drilling and fracking.

Since the exemplary fluid end 402 is intended for use with a triplex power end 201, the body includes three fluid intake bore openings 407a, 407b, and 407c. which are located on the bottom of the body 401 (see FIG. 4F) in the exemplary embodiment. The exemplary fluid end 402 also includes three fluid intake valve plug bore openings 408a, 408b, and 408c, which are located on the front of the body 401 (see FIG. 4D) in the exemplary embodiment, and three fluid discharge valve plug bore openings 409a, 409b, and 409c, which are located on the top of the body 401 (see FIG. 4E) in the exemplary embodiment. The exemplary fluid end 402 further includes three power end interface bore openings 410a, 410b, and 410c, which are located on the rear of the body 401 (see FIG. 4H) in the exemplary embodiment. In the exemplary fluid end 402, the fluid discharge bore opening 403 is located on an end of the body 401 (see FIG. 4G). In alternative embodiments, a second fluid discharge bore opening may be located on an opposite end of the body 401. The fluid passage (described in further detail below) in the body 401 may include the second fluid discharge bore opening, which is simply sealed and not utilized.

As shown in FIG. 4I, the body 401 includes a fluid passage between the three fluid intake bore openings 407a, 407b, and 407c and the fluid discharge bore opening 403. The fluid passage includes a fluid discharge bore 411 extending longitudinally through the body 401 and ending at the fluid discharge bore opening 403. The fluid passage also includes three fluid intake bores 412a, 412b, and 412c extending vertically within the body 401 and respectively connecting the three fluid intake bore openings 407a, 407b, and 407c to the fluid discharge bore 411. The fluid passage further includes discharge valve regions 413a, 413b, and 413c at the intersections of the fluid discharge bore 411 with the fluid intake bores 412a, 412b, and 412c, respectively. The fluid passage still further includes intake valve regions 414a, 414b, and 414c along the fluid intake bores 412a, 412b, and 412c, respectively connected at openings 415a, 415b and 415c. The openings 415a, 415b and 415c represent the intersection of fluid intake plug bores extending transversely through the body from the fluid intake valve plug bore openings 408a, 408b, and 408c to the respective intake valve regions 414a, 414b, and 414c on the fluid intake bores 412a, 412b, and 412c. Fluid discharge valve plug bores 416a, 416b, and 416c extend from the discharge valve regions 413a, 413b, and 413c to the fluid discharge valve bore openings 409a, 409b, and 409c.

As noted, FIG. 4J is a sectional view illustrating a high-pressure fluid end 402 for a pump 200 in accordance with the present disclosure, taken at section line K-K in FIG. 4A. As will be understood by those skilled in the art, the cross-section of FIG. 4J is transverse to the cross-section of FIG. 4I, and FIG. 4J illustrates components associated with one of three instances of the structures depicted. The components illustrated are disposed withing the portion of the fluid passage between the fluid intake bore opening 407a, the power end interface bore opening 410a, the fluid intake valve plug bore opening 408a, and the fluid discharge valve plug bore opening 409a. The other instances of the structures depicted in FIG. 4J have substantially identical form and operation.

The fluid discharge region of the body 401 may include a valve service 417 within the discharge valve region 413a at the intersection of the fluid intake bore 412a and the fluid discharge bore 411. The valve service 417 is in fluid communication with the power end interface bore opening 410a (and therefore in fluid communication with, e.g., the suction valve 212 and the discharge valve 214 for a pumping chamber 212). The power end interface, which includes the power end interface bore opening 410a, also includes a wear plate 418 and a wear plate seal 419 over a power end interface bore 420 for suctioning fluid such as drilling mud into the fluid passage through the fluid end 402. As shown in FIG. 4I, the fluid discharge bore 411 extends transversely through the discharge valve region 413a within the fluid passage through the body 401, such that valve service 417 controls movement of fluid between the fluid intake bore 412a and the fluid discharge bore 411.

The valve service 417 may include, for example, a valve, a valve seat, and a spring. The valve of valve service 417 may, in operation, open in response to an increase in fluid pressure within the power end interface bore 420 as a result of compression movement by the power end (at the power end interface), allowing fluid within the fluid intake bore 412a to pass through the valve into the fluid discharge bore 411, and on through the fluid discharge bore opening 403 and the strainer cross 405 to the conduit for mud hose 150 in FIG. 1. The valve of valve service 417 may, in operation, close in response to a decrease in fluid pressure within the power end interface bore 420 as a result of an expansion movement by the power end (e.g., an axial motion of a piston in fluid communication at the power end interface) in a direction away from the fluid end 402 that expands the volume of the area in the power end interface bore 420. The fluid passage through the body 401 includes the fluid discharge valve plug bore opening 416a extending beyond the region in which the valve service 417 is installed, in which the valve plug 421 is placed (covered by the remainder of the valve cover assembly 406) so that, during operation (the compression and expansion), the high-pressure drilling fluid is contained within the fluid end 402.

The fluid intake region of the body 401 may include a valve service 422 within the fluid passage through the fluid end 402. Similar to valve service 417, valve service 422 may include a valve, valve seat, and spring. Valve service 422 may also include a lower valve stop 423, as in the example shown. The fluid intake region of the body 401 also includes a fluid intake bore 412a with fluid intake bore opening 407a, forming a portion of the fluid passage through the fluid end 402. The fluid intake bore opening 407a of the fluid intake region may be coupled to a fluid passageway (e.g., suction valve 214, fluid inlet 213, and conduit 173) that is in turn coupled to mud tank assembly of FIG. 1, operating as a fluid source to the fluid end 402. The valve of valve service 422 may, in operation, close in response to an increase in fluid pressure within the power end interface bore 420 as a result of the compression movement at the power end (that causes the valve of valve service 417 to open in the discharge valve region 413a), preventing fluid in the fluid intake bore 412a from being forced back into the conduit 173 via the fluid intake bore opening 407a. Further, the valve of valve service 422 may, in operation, open in response to a decrease in fluid pressure within the power end interface bore 420 as a result of the expansion movement by the motor at the power end interface, allowing new fluid to enter the fluid intake bore 412a.

Within a bore from the intake valve region 414a occupied by the valve service 422 (i.e., the bore extending between the fluid intake valve plug bore opening 408a and the opening 415a into the intake valve region 414a), a valve plug 424 is installed (covered by the remainder of the valve cover assembly 404) so that, during operation (the compression and expansion) the high-pressure drilling fluid is contained within the fluid end 402. The valve plug 424 and the valve plug 421 are both sealed by a respective valve cover gasket 425. The valve cover assemblies 404, 406 are coupled to the body 401 of the fluid end 402 over the valve plug 424 and the valve plug 421, respectively. The valve cover assemblies 404, 406 may be attached to the body 401 by one or more studs fitting into corresponding holes in the body 401. In an embodiment, the one or more studs are stud-and-nut configurations, while in other embodiments the one or more studs may be cap screws (e.g., 12-point caps crews). The valve cover assemblies may be designed with the one or more studs so as to be compatible with existing fluid end module configurations. The valve cover assembly 404 and the valve cover assembly 406 each include a valve cover gland 426 sealing the respective valve cover assembly to prevent fluid leakage. The valve cover glands 426 each include an eyebolt therein to facilitate handling of the fluid end 402 during installation, repair, or maintenance.

A single line may be connected to each of the three fluid intake bore openings (e.g., fluid intake bore opening 407a in FIG. 4J) under the mono block body 401 of the fluid end 402. FIGS. 4 and 4A through 4J depict the fluid end with a single fluid outlet bore opening 403 at one end of the mono block body 401, connected by the fluid passage through the mono block body 401 to the three fluid intake bore openings 407a, 407b, and 407c. As noted above, however, outlet bore openings may be provided at both ends of the mono block body 401. A pulsation dampener (PD) is preferably coupled to the fluid outlet bore opening(s) to suppress harmonics.

The dimensions—specifically, the wall thicknesses—for the mono block body 401 of the fluid end 402 are selected for a fluid pressure rating of at least 8,500 psi, based on the strength and hardness of the material from which mono block body 401 is formed. For example, for stainless steel, the overall dimensions of the exemplary mono block body 401 depicted in FIGS. 4D through 4H may be 64 inches in length, 32 inches in height, and 20 inches in width. The fluid passage illustrated in FIG. 4I may have a minimum diameter of approximately 4 inches (e.g., for the fluid discharge bore 411) and a maximum diameter of approximately 8 inches (e.g., at the intake valve regions 414a, 414b, and 414c or the discharge valve regions 413a, 413b, and 413c).

The same overall mono block design of the exemplary fluid end 402 in FIGS. 4 and 4A through 4J may also be employed for pumps rated at lower operating pressures (e.g., 7,500 psi), facilitating part design and interchangeability of replacement components, as well as installation, repair, and maintenance of both high-pressure fluid ends and lower pressure fluid ends. The differences in the overall design of the fluid end 402 required to meet the desired pressure requirements relate primarily to material selecting and sizing. For example, the difference between a design rated for 7,500 psi and a design rated for 8,500 psi may include one or both of use of stainless steel (versus another material for lower pressure designs) and wall thicknesses within the body 401, to account for the pressure requirements. The applications for drilling pumps (typically piston-style pumps) for which the fluid end 402 will be employed are differentiated by being able to handle larger pressure requirements with no change to the overall fluid end design as single unit. It should be noted that, conventionally, mono block designs are not commercially utilized in high-pressure fracking pumps (which typically are plunger-style pumps). Even with the L/Y style fluid ends, the ability to output the same higher fluid pressures as a piston-style pump using a design that is shared with pumps having lower pressure ratings is not currently available.

The mono block design has the ability to reduce components on the mud pump by mechanically linking the three suctions and discharge(s) together. Fluid intake and discharge may be integrated in the mono block design as shown, or intake and/or discharge headers could be separate component(s) secured to the remainder of the body. Each alternative has benefits and drawbacks.

Corrosion resistance to the fluid being pumped may be a consideration, with stainless steel being more resistive to corrosive fluid applications even though other materials have increased life for the flow rates and pressures involved.

Whereas conventional mud pump fluid ends use standard rubber/plastic gaskets and seals, the present design introduces a more robust solution for R or BX gasket sand ring joints, allowing for longer lasting components and reduced opportunities for wash outs due to more robust components. These gaskets may be employed for the wear plate seal 419, a gasket (not shown) around the fluid intake bore openings 407a, 407b, and 407c and the fluid discharge bore opening 403, and/or valve cover gaskets 425 around the valve plug 424 and the valve plug 421.

FIG. 5 illustrates an example process 500 of employing a pump having a high-pressure fluid end in accordance with the present disclosure. For ease of explanation, the process 500 of FIG. 5 is described as being performed using the pump 200 of FIG. 2 with the fluid end 402 of FIGS. 4 and 4A through 4J, in the drilling rig apparatus 100 of FIG. 1. However, the process 500 may be performed using any other suitable device(s) and in any other suitable system(s).

As shown in FIG. 5, the process 500 begins with commencing drilling operations in a borehole (step 501). The drilling operations necessitate provision of drilling fluid into the borehole. A pump system having a fluid end rated for fluid pressures of at least 8,500 psi is utilized to pump such drilling fluid into the borehole (step 502). Drilling operations proceed, using the pump system to deliver drilling fluid, until the production zone(s) have been reached and all casing, etc. has been installed. Drilling operations are then completed (step 503). Equipment specific to drilling operations may be removed from the rig location, but the pump system remains at the rig. The same pump system employed for pumping drilling fluids into the borehole is also utilized for fracturing operations relating to the borehole (step 504).

Although FIG. 5 illustrates one example of a process 500 of employing a pump having a high-pressure fluid end, various changes may be made to FIG. 5. For example, while shown as a series of steps, various steps in FIG. 5 could overlap, occur in parallel, occur in a different order, or occur any number of times (including zero times).

Although this disclosure has been described with reference to various example implementations, various changes and modifications may be suggested to one skilled in the art. It is intended that this disclosure encompass such changes and modifications as fall within the scope of the appended claims.

Claims

1. A fluid end for a mud pump in a drilling system, the fluid end comprising:

a mono block body formed of stainless steel, the mono block body including: three fluid intake openings connected by a fluid passage to at least one fluid discharge bore opening; three power end interface openings each for connection to a pumping chamber of a pump power end, each power end interface opening coupled to the fluid passage; three discharge valve services each disposed within one intersection of the fluid passage in fluid communication with one of the fluid intake openings and the at least one fluid discharge bore opening; and three intake valve services each disposed within one intersection of the fluid passage in fluid communication with one of the fluid intake openings and power end interface openings,

wherein dimensions of the body are sized for a pump pressure rating of at least 8,500 pounds per square inch (psi) during drilling operations.

2. A pump system including the fluid end of claim 1, the pump system further comprising:

a pump power end,

wherein the pump system is configured to pump drilling fluid into a borehole and for fracturing operations relating to the borehole.

3. The fluid end of claim 1, wherein the mono block body comprises a material selected for corrosion resistance.

4. The fluid end of claim 1, further comprising:

gaskets at the one or more fluid intake openings, the at least one fluid discharge bore opening, and the power end interface openings selected for longer durability over rubber or plastic gaskets.

5. The fluid end of claim 1, wherein the pump pressure rating is sufficient for fracturing operations.

6. A mud pump fluid end on a mud pump system configured for use in drilling operations, the mud pump fluid end comprising:

a mono block body including: a fluid passage between one or more fluid intake bore openings and at least one fluid discharge bore opening; one or more power end interfaces each for connection to a pumping chamber of a pump power end, each power end interface fluidly connected to the fluid passage; one or more discharge valve services each disposed within an extension of the fluid passage that is in fluid communication with one of the power end interfaces; and one or more intake valve services each disposed within a portion of the fluid passage between one of the one or more fluid intake bore openings and a corresponding one of the one or more power end interfaces,

wherein the body is formed of a material selected and sized for a pump pressure rating of at least 8,500 pounds per square inch (psi).

7. The mud pump system including the mud pump fluid end of claim 6, the mud pump system further comprising:

a mud pump power end including the one or more power end interfaces, wherein the mud pump power end is a piston-style triplex pump,

wherein the mud pump system is configured to pump drilling fluid into a borehole.

8. The mud pump fluid end of claim 6, wherein the mono block body comprises a material selected for corrosion resistance.

9. The mud pump fluid end of claim 8, wherein the material selected for corrosion resistance is stainless steel.

10. The mud pump fluid end of claim 6, wherein a thickness of walls for the mono block body are selected based on the pump pressure rating of at least 8,500 psi.

11. The mud pump fluid end of claim 6, further comprising:

gaskets at the one or more fluid intake bore openings, the at least one fluid discharge bore opening, and the one or more power end interfaces selected for longer durability over rubber or plastic gaskets.

12. The mud pump fluid end of claim 11, wherein the gaskets are one of R or BX gasket sand ring joints.

13. The mud pump fluid end of claim 11, wherein the material and a size of the body selected, and the gaskets are configured, to allow re-use of the mud pump fluid end in fracturing operations.

14. A method, comprising:

utilizing a pump system having a fluid end with a pressure rating of at least 8,500 pounds per square inch (psi) to pump drilling fluid into a borehole during drilling operations; and

after the drilling operations, utilizing the pump for fracturing operations relating to the borehole.

15. The method of claim 14, wherein the fluid end has a mono block body formed of a material selected and sized for a pump pressure rating of at least 8,500 psi, and wherein the material is selected for corrosion resistance.

16. The method of claim 15, wherein the material of the fluid end is stainless steel.

17. The method of claim 15, wherein a thickness of walls for the mono block body are selected based on the pump pressure rating of at least 8,500 psi.

18. The method of claim 14, further comprising:

gaskets at one or more fluid intake bore openings in the fluid end, at least one fluid discharge bore opening in the fluid end, and at one or more power end interfaces, wherein the gaskets selected for longer durability over rubber or plastic gaskets.

19. The method of claim 18, wherein the gaskets are one of R or BX gasket sand ring joints.

20. The method of claim 14, wherein the fracturing operations are commenced without moving the pump system off a rig used for the drilling operations following completion of the drilling operations.