US20210131410A1

US20210131410A1 - Mobile Pump System

Info

Publication number: US20210131410A1
Application number: US17/084,899
Authority: US
Inventors: Matthew Curry; Christopher Combs; Neal Jensen
Original assignee: Green Zone Technologies LLC
Current assignee: Green Zone Technologies LLC
Priority date: 2019-11-01
Filing date: 2020-10-30
Publication date: 2021-05-06
Also published as: CA3097652A1

Abstract

A mobile pump system includes: a trailer movable by a vehicle; a first pump and a second pump mounted to the trailer and in fluid communication with an outlet configured to flow a fluid to a destination and with a fluid source; a power source mounted to the trailer and directly coupled to the first pump and/or the second pump, where the power source includes a turbine and/or a natural gas fired reciprocating engine; and a control system configured to: activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point; in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump; and deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, where the second set point is greater than or equal to the first set point.

Description

BACKGROUND

1. Field

The present disclosure relates to a mobile pump system and a method for performing a pressure pumping application including the mobile pump system.

2. Technical Considerations

Pressure pumping includes a propagation of fractures through layers of rock using pressurized fluid and/or pumping cement into a wellbore to complete it.
In one non-limiting example of pressure pumping, to extract oil and/or gas trapped in formations beneath the Earth's surface, drilling of a wellbore is required, and the oil and/or gas may be recovered and extracted through the wellbore. Various pumps may be used during the drilling and oil and/or gas recovery process.
In some non-limiting oilfield applications, drilling may include forming horizontal laterals extending out from a vertical section of the wellbore. The formation defining the vertical or lateral section may be fractured in sections, such that a fracture stimulation treatment is completed in the first section before moving on to apply a fracture stimulation treatment on a second section. This may be performed using a plug-and-perf technique in which a perforating gun is used to initiate fractures in the formation in the section after a plug is positioned between the first section and the second section. The plug seals the first section of the lateral from the other sections. This plug-and-perf technique is repeated for each section of the lateral until all intended sections of the lateral are perforated and fracture stimulated.
The plug may be positioned at a predetermined location along the lateral by utilizing a pump system to pump a fluid into the wellbore, which exerts a pressure on the plug. The pressure on the plug moves the plug along the lateral to the desired position. Positioning the plug using the pump is considered an ancillary application, commonly referred to as “pumpdown”.
Existing pumps used in pressure pumping application, such as in ancillary pumpdown applications have numerous drawbacks. For example, existing pumps use an internal combustion engine driven by diesel fuel, which have high carbon footprints. In addition, these existing pumps are cumbersome and require considerable room at the well site. Further, these existing pumps do not allow for sufficiently precise control of flow rate, making it difficult to move the plug to the desired position. Existing pumps are expensive to acquire and maintain, and they create significant noise at a decibel level that is known to harm human hearing without adequate ear protection.
Further, existing pumping systems utilized in pressure pumping applications, including ancillary pressure pumping applications, are not capable of sufficiently low flow rates or precise control of the flow rate or pump pressure. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft. As a result, existing pressure pumping systems do not effectively remedy screen outs occurring during hydraulic fracturing applications.
Further, higher rates may oftentimes be required for certain pumping applications. Many existing single pump systems are required to be located at a well site which take up considerable room, thereby affecting the standards of safety with increased personnel and more treating equipment like hoses and high pressure treating irons, affecting the cost of the well pad and causing large expenditures in construction of the well pad to accommodate the multiple pumping systems, and requiring increased amounts of diesel fuel to be trucked to location and dispersed among the pumps as they are engaged in high pressure and/or high rate operations.
Further, existing pumping systems utilized in pressure pumping applications are costly to build and to operate. Traditional diesel-powered pumps require regular repair and maintenance which can inflate operational costs. Diesel is a comparatively expensive fuel and is a cause of a variety of pollutants and greenhouse gases when burned when compared to an alternate fuel source like natural gas, and diesel engines also require certain maintenance that leads to significant waste streams and monetary expenditure being required.
Therefore, a pump suitable for pressure pumping applications that overcomes some or all of the disadvantages of existing pumps is desired.

SUMMARY

The present disclosure is directed to a mobile pump system including: at least one trailer movable by a vehicle; a plurality of pumps including a first pump and a second pump, where the first pump and the second pump are each mounted to the at least one trailer, where the first pump and the second pump are each in fluid communication with an outlet configured to flow a fluid from the mobile pump system to a destination and with a fluid source configured to hold a pumping fluid; a power source mounted to the at least one trailer and directly coupled to the first pump and/or the second pump, where the power source includes a turbine and/or a natural gas fired reciprocating engine; and a control system configured to: activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the second pump to pump the pumping fluid; in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the first pump to pump the pumping fluid; and deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, where the second set point is greater than or equal to the first set point.
The first pump may configured to pump fluid at a flow rate as low as 2.5 bpm and at a flow rate of up to 30 bpm, and the second pump may be configured to pump fluid a flow rate as low as 0.1 bpm. The first pump may include a multi-stage centrifugal injection pump. The first pump may include a pressure-balanced pump. The second pump may include a positive displacement pump. The positive displacement pump may be a reciprocating triplex or quintuplex pump. The control system may include an electronic governor configured to control at least one of a rotational speed of the power source, a flow rate of the first pump and/or the second pump, and a pumping pressure of the first pump and/or the second pump. The electronic governor may be configured to adjust the flow rate of the first pump and/or the second pump by an incremental amount as low as 0.1 bpm. The power source may be directly coupled to the first pump, where the direct coupling may include a non-variable, fixed ratio direct-coupled connection or a direct-coupled gear connection including a speed reducer. The second pump may be powered by an electric motor receiving power generated by the power source. The control system may be configured to initiate a start-up protocol by: activating the second pump, with the first pump deactivated, until the flow rate of the mobile pump system is at least 1.5 bpm; and activating the first pump, while the second pump is still activated, once the flow rate of the mobile pump system is at the first set point, where the first set point is at least 1.5 bpm. The mobile pump system may not be permanently installed at a site for performing a pressure pumping application. The power source may be operated using field gas. The first pump and/or the second pump may be configured to pump fluid at a pressure of 15,000 psi or greater. The mobile pump system may include a fluid storage tank mounted to the at least one trailer and a third pump mounted to the at least one trailer and in fluid communication with the fluid storage tank, the first pump, and the second pump, where the third pump is configured to pump fluid from the fluid storage tank to the first pump and/or the second pump. The pumping fluid may be pumped to the outlet by the second pump and not the first pump with the flow rate of the mobile pump system below the first set point, and the pumping fluid may be pumped to the outlet by the first pump and optionally the second pump with the flow rate of the mobile pump system at or above the first set point.
The present disclosure is also directed to a method for performing a pressure pumping application, including positioning a mobile pump system on a pump site. The mobile pump system includes: at least one trailer movable by a vehicle; a plurality of pumps including a first pump and a second pump, where the first pump and the second pump are each mounted to the at least one trailer, where the first pump and the second pump are each in fluid communication with an outlet configured to flow a fluid from the mobile pump system to a destination and with a fluid source configured to hold a pumping fluid; a power source mounted to the at least one trailer and directly coupled to the first pump and/or the second pump, where the power source includes a turbine and/or a natural gas fired reciprocating engine; and a control system configured to: activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the second pump to pump the pumping fluid; in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the first pump to pump the pumping fluid; and deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, where the second set point is greater than or equal to the first set point.
The method may include activating the second pump, with the first pump deactivated, until the flow rate of the mobile pump system is at least 1.5 bpm; and activating the first pump, while the second pump is still activated, once the flow rate of the mobile pump system is at the first set point, where the first set point is at least 1.5 bpm. The method may include deactivating the second pump, while the first pump is still activated, once the flow rate flow rate of the mobile pump system is at the second set point. The method may include positioning a plug in a lateral of a wellbore using fluid pumped into the wellbore via the mobile pump system. The method may include performing, using the mobile pump system, a toe prep application, a drill-out application, an industrial purging application, a pipeline pressure testing application, and/or a hydro-blasting application.
Further embodiments are set forth in the following numbered clauses:
Clause 1: A mobile pump system, comprising: at least one trailer movable by a vehicle; a plurality of pumps comprising a first pump and a second pump, wherein the first pump and the second pump are each mounted to the at least one trailer, wherein the first pump and the second pump are each in fluid communication with an outlet configured to flow a fluid from the mobile pump system to a destination and with a fluid source configured to hold a pumping fluid; a power source mounted to the at least one trailer and directly coupled to the first pump and/or the second pump, wherein the power source comprises a turbine and/or a natural gas fired reciprocating engine; and a control system configured to: activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the second pump to pump the pumping fluid; in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the first pump to pump the pumping fluid; and deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, wherein the second set point is greater than or equal to the first set point.
Clause 2: The mobile pump system of clause 1, wherein the first pump is configured to pump fluid at a flow rate as low as 2.5 or 1.5 bpm and at a flow rate of up to 30 bpm, and wherein the second pump is configured to pump fluid a flow rate as low as 0.1 bpm.
Clause 3: The mobile pump system of clause 1 or 2, where the first pump comprises a multi-stage centrifugal injection pump.
Clause 4: The mobile pump system of any of clauses 1-3, wherein the first pump comprises a pressure-balanced pump.
Clause 5: The mobile pump system of any of clauses 1-4, wherein the second pump comprises a positive displacement pump.
Clause 6: The mobile pump system of clause 5, wherein the positive displacement pump is a reciprocating triplex or quintuplex pump.
Clause 7: The mobile pump system of any of clauses 1-6, wherein the control system comprises an electronic governor configured to control at least one of a rotational speed of the power source, a flow rate of the first pump and/or the second pump, and a pumping pressure of the first pump and/or the second pump.
Clause 8: The mobile pump system of clause 7, wherein the electronic governor is configured to adjust the flow rate of the first pump and/or the second pump by an incremental amount as low as 0.1 bpm.
Clause 9: The mobile pump system of any of clauses 1-8, wherein the power source is directly coupled to the first pump, wherein the direct coupling comprises a non-variable, fixed ratio direct-coupled connection or a direct-coupled gear connection including a speed reducer.
Clause 10: The mobile pump system of any of clauses 1-9, wherein the second pump is powered by an electric motor receiving power generated by the power source.
Clause 11: The mobile pump system of any of clauses 6-10, wherein the control system is configured to initiate a start-up protocol by: activating the second pump, with the first pump deactivated, until the flow rate of the mobile pump system is at least 1.5 bpm; and activating the first pump, while the second pump is still activated, once the flow rate of the mobile pump system is at the first set point, wherein the first set point is at least 1.5 bpm.
Clause 12: The mobile pump system of any of clauses 1-11, wherein the mobile pump system is not permanently installed at a site for performing a pressure pumping application.
Clause 13: The mobile pump system of any of clauses 1-12, wherein the power source is operated using field gas.
Clause 14: The mobile pump system of any of clauses 1-13, wherein the first pump and/or the second pump are configured to pump fluid at a pressure of 15,000 psi or greater.
Clause 15: The mobile pump system of any of clauses 1-14, further comprising a fluid storage tank mounted to the at least one trailer and a third pump mounted to the at least one trailer and in fluid communication with the fluid storage tank, the first pump, and the second pump, wherein the third pump is configured to pump fluid from the fluid storage tank to the first pump and/or the second pump.
Clause 16: The mobile pump system of any of clauses 1-15, wherein the pumping fluid is pumped to the outlet by the second pump and not the first pump with the flow rate of the mobile pump system below the first set point, and the pumping fluid is pumped to the outlet by the first pump and optionally the second pump with the flow rate of the mobile pump system at or above the first set point.
Clause 17: A method for performing a pressure pumping application, comprising: positioning the mobile pump system of any of clauses 1-16 on a pump site.
Clause 18: The method of clause 17, further comprising: activating the second pump, with the first pump deactivated, until the flow rate of the mobile pump system is at least 1.5 bpm; and activating the first pump, while the second pump is still activated, once the flow rate of the mobile pump system is at the first set point, wherein the first set point is at least 1.5 bpm.
Clause 19: The method of clause 18, further comprising: deactivating the second pump, while the first pump is still activated, once the flow rate flow rate of the mobile pump system is at the second set point.
Clause 20: The method of any of clauses 17-19, further comprising: positioning a plug in a lateral of a wellbore using fluid pumped into the wellbore via the mobile pump system.
Clause 21: The method of any of clauses 17-20, further comprising: performing, using the mobile pump system, a toe prep application, a drill-out application, an industrial purging application, a pipeline pressure testing application, and/or a hydro-blasting application.

BRIEF DESCRIPTION OF THE DRAWINGS

Additional advantages and details are explained in greater detail below with reference to the exemplary embodiments that are illustrated in the accompanying schematic figures, in which:

FIG. 1 shows a schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques;

FIG. 2 shows another schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques and a mobile pump system;

FIG. 3 shows a schematic aerial view of a well pad at an oil and/or gas production site, the well pad including a mobile pump system;

FIG. 4 shows a schematic side view of a mobile pump system including a trailer and a cab for moving the mobile pump system;

FIG. 5 shows a schematic top view of a mobile pump system including the trailer and the electrically-driven pump or turbine-driven pump;

FIG. 6 shows a schematic side view of an auger-style pump of a mobile pump system;

FIG. 7 shows a controller for controlling a mobile pump system;

FIG. 8 shows a schematic top view of a mobile pump system including a pump driven by an electric motor;

FIG. 9 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine and/or a natural gas fired reciprocating engine;

FIG. 10 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine and/or a natural gas fired reciprocating engine, with the trailer including a fuel tank;

FIG. 11 shows a schematic top view of a mobile pump system including a secondary pump;

FIG. 12 shows a schematic side view of a mobile pump system including multiple pumps and a turbine and/or a natural gas fired reciprocating engine;

FIG. 13 shows a schematic top view of a mobile pump system including multiple pumps and a turbine and/or a natural gas fired reciprocating engine;

FIG. 14 shows a cross-sectional view of a non-limiting example of the first pump being a multi-stage centrifugal injection pump;

FIG. 15 shows a cross-sectional view of a non-limiting example of the second pump being a positive displacement triplex or quintuplex pump;

FIG. 16 shows a cross-sectional view of a non-limiting example of the turbine and/or a natural gas fired reciprocating engine including a speed reducer; and

FIG. 17 shows a side view of a non-limiting example of the second pump being a positive displacement triplex or quintuplex pump.

DETAILED DESCRIPTION

For purposes of the description hereinafter, the terms “end,” “upper,” “lower,” “right,” “left,” “vertical,” “horizontal,” “top,” “bottom,” “lateral,” “longitudinal,” and derivatives thereof shall relate to the invention as it is oriented in the drawing figures. However, it is to be understood that the invention may assume various alternative variations and step sequences, except where expressly specified to the contrary. It is also to be understood that the specific devices and processes illustrated in the attached drawings, and described in the following specification, are simply exemplary embodiments or aspects of the invention. Hence, specific dimensions and other physical characteristics related to the embodiments or aspects disclosed herein are not to be considered as limiting.
No aspect, component, element, structure, act, step, function, instruction, and/or the like used herein should be construed as critical or essential unless explicitly described as such. Also, as used herein, the articles “a” and “an” are intended to include one or more items and may be used interchangeably with “one or more” and “at least one.”
The present disclosure is directed to a mobile pump system that includes: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer. The mobile pump system described herein may be suitable for pressure pumping applications.
The present disclosure is also directed to a mobile pump system, comprising: at least one trailer movable by a vehicle; a plurality of pumps comprising a first pump and a second pump, wherein the first pump and the second pump are each mounted to the at least one trailer, wherein the first pump and the second pump are each in fluid communication with an outlet configured to flow a fluid from the mobile pump system to a destination and with a fluid source configured to hold a pumping fluid; a power source mounted to the at least one trailer and directly coupled to the first pump and/or the second pump, wherein the power source comprises a turbine and/or a natural gas fired reciprocating engine; and a control system configured to: activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the second pump to pump the pumping fluid; in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the first pump to pump the pumping fluid; and deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, wherein the second set point is greater than or equal to the first set point.
Referring to FIG. 1, an oil and/or gas production site 10 is shown. At the production site 10, the surface 11 (Earth's surface) includes wellbore 12 created by drilling. The wellbore 12 includes a wellhead 13, which is a structural component at the surface 11 of the wellbore 12 which provides a structural and pressure-containing interface for various drilling and production equipment. The production site 10 may be a site for conducting hydraulic fracturing.
With continued reference to FIG. 1, the production site 10 may utilize a horizontal drilling technique in which at least one lateral 14 is used. For the horizontal drilling technique, the wellbore 12 may include a vertical region of 2,500 to 25,000, such as 6,000 to 15,000 or 6,000 to 10,000 feet in depth, although the length of this vertical region is not limited to this range. The wellbore 12 may include a leveling-off point 16 in which the vertical region ends and the lateral 14 is drilled horizontally in the Earth (the lateral 14 may have approximately the same depth from the surface 11 at all points). Each lateral 14 may have a length of 2,500-25,000, such as 3,000 to 10,000 feet, as measured from the leveling-off point 16 to an end 18 of the lateral 14, although the length of the lateral 14 is not limited to this range. It will be appreciated that FIG. 1 is not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal drilling.
The lateral 14 may include a plurality of regions, which are of a predetermined length. Hydraulic fracture stimulation treatment may be performed in the lateral 14 individually at each region. Hydraulic fracture stimulation treatment includes pumping a fracturing fluid into the formation. The lateral 14 of the schematic in FIG. 1 includes a first region 20, a second region 22, a third region 24, a fourth region 26, a fifth region 28, and a sixth region 30.
With continued reference to FIG. 1, the production site 10 may utilize a “plug-and-perf” method for hydraulic fracture stimulation treatment. In FIG. 1, hydraulic fracture stimulation treatment has been completed for the first region 20. A fractured first region 32 was created in the formation at the first region 20. After the hydraulic fracture stimulation treatment was completed in the first region 20, a first plug 34 was positioned at an end of the first region 20 closest to the wellhead 13 (a proximal end of the first region 20). Once in place, this first plug 34 may prevent fluid subsequently pumped into the wellbore 12 from entering the first region 20.
With continued reference to FIG. 1, hydraulic fracture stimulation treatment in the second region 22 of the formation may be initiated by lowering a perforating gun 36 (hereinafter “perf gun”) into the wellbore 12 and positioning the perf gun 36 in the second region 22. The perf gun 36 may be lowered into the wellbore 12 using a perf trailer 37. Once positioned correctly, charges of the perf gun 36 may be detonated so as to create multiple connection points from the wellbore 12 to the formation in the second region 22. Oil and/or gas may be extracted by escaping from fractures and extracted to the surface 11 via the wellbore 12.
Referring to FIG. 2, the production site 10 is shown at a time after that depicted in FIG. 1. The fractured second region 38 is shown, which was created by the perf gun 36 from FIG. 1. It will be appreciated that FIG. 2 is also not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal and/or vertical drilling.
In FIG. 2, a second plug 40 is being lowered into the wellbore 12 by a plug trailer 41 to be positioned at a proximal position of the second region 22 (on the end of the second region 22 closer to the wellhead 13). The second plug 40 is spaced apart from the first plug 34 by approximately the length of the second region 22. The second plug 40 may be positioned using positioning fluid 42 to provide pressure to the second plug 40 to move the second plug along the length of the wellbore 12 (including the lateral 14). The positioning fluid 42 may include water and/or a chemical additive. The chemical additive may include a friction reducer to reduce surface tension. The chemical additive may reduce tension or pipe friction along the wellbore 12 associated with positioning the second plug 40.
The second plug 40 may be positioned using the mobile pump system 44 of the present disclosure. The mobile pump system 44 may be used to position the second plug 40 as merely one non-limiting example of how the mobile pump system 44 may be used in a pressure pumping application. However, it will be appreciated that the mobile pump system 44 may be used to complete other pressure pumping applications using the components of the mobile pump system 44 described hereinafter.
The mobile pump system 44 may include a trailer 46 movable by a vehicle (e.g., a cab having a fifth wheel). The trailer 46 may be movable by a vehicle, such as a cab, to and from the production site 10. In this way, the mobile pump system 44 may be conveniently moved from location to location, such as to and from the production site 10, and the mobile pump system 44 does not need to be permanently installed at the production site 10. The trailer 46 may be separable/detachable from the vehicle such that the trailer 46 may be left at the production site 10 and the vehicle driven away, or the trailer 46 may be integrated with the vehicle, such that the vehicle remains at the production site 10 while the mobile pump system 44 is in use and drives away after use of the mobile pump system 44 is completed.
With continued reference to FIG. 2, the mobile pump system 44 may further include at least one pump 48 mounted to the trailer 46. The at least one pump 48 may be configured to pump the positioning fluid 42 into the wellbore 12. The at least one pump 48 may include an electric motor 50 mounted to the trailer 46 or may be powered by a turbine and/or a natural gas fired reciprocating engine 50 mounted to the trailer 46. The trailer 46 may include multiple pumps 48 in some embodiments and may include multiple electric motors and/or turbines and/or natural gas fired reciprocating engine 50 for driving the pumps 48. As used herein, the term “electric motor” or “electrically-driven motor” refers to a motor in which electrical energy is converted into mechanical energy. As used herein, the term “turbine” refers to a rotary mechanical device that extracts energy from a fluid (e.g., liquid and/or gas) flow and converts it into useful work. The trailer 46 may also include a power generator 52 in connection with the at least one pump 48 to fuel the electrically-driven motor or the turbine 50 of the at least one pump 48. The power generator 52 may be battery, natural gas, diesel fuel, or gasoline fueled. The at least one pump 48 may be driven by the electric motor or the turbine 50 and not by an internal combustion engine. The pump 48 may be driven by a natural gas fired reciprocating engine.
The at least one pump 48 may be configured to pump the positioning fluid 42, or any other fluid, at a flow rate of up to 30 barrels per minute (bpm), such as up to 60 bpm, up to 80 bpm, up to 100 bpm, up to 120 bpm, up to 140 bpm or higher. A barrel is defined as 42 US gallons, which is approximately 159 Liters. The at least one pump 48 may be configured to pump the positioning fluid 42 at far lower flow rates, and may pump the positioning fluid 42 at a flow rate as low as 0.1 bpm (when the pump is not turned off such that it's flow rate would be 0 bpm). The at least one pump 48 may be controlled such that its flow rate may be controlled within 0.1 bpm, resulting in a flow rate within 0.1 bpm compared to a predetermined flow rate. The pump may be configured to adjust the flow rate by 0.1 bpm (e.g., adjust the flow rate of the at least one pump 48 from 60.0 bpm to 59.9 bpm or from 0.2 bpm to 0.1 bpm). Existing pressure pumping systems, including ancillary pressure pumping applications, are not capable of such low flow rates or such precise control of the flow rate. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft.
The ability to pump at lower rates and to more precisely control the flow rate of the at least one pump 48 may be especially useful in post-occurrence remedying of “screen outs,” which are common in hydraulic fracturing applications. A screen out occurs when proppant and fluid (of the positioning fluid 42, for example) can no longer be injected into the formation. This may be due to resistant stresses of the formation becoming too excessive or surface-originated reasons resulting in loss of viscosity to carry proppant so that it falls out of suspension and plugs perforations in the wellbore 12. In this way, the wellbore 12 becomes “packed” with proppant, which does not allow any further operations to continue due to high pressures that cannot be overcome from these blockages.
In response to screen outs, the wellbore 12 may be opened at the surface 11 to relieve pressure and to carry at least some of the proppant out of the wellbore 12 and create a pathway to continue fluid injection to clear the wellbore 12 and allow operations to continue, which is a dangerous operation. An attempt to continue pumping operations at low rates to avoid reaching maximum pressure so that the proppant that is packed is forced through perforations and into the wellbore 12 may be attempted. However, due to the limitations of existing pumps with conventional engines and transmissions, the pump cannot pump at low enough rates to avoid again reaching maximum pressure. As a result, existing systems are often required to switch to a coiled tubing procedure to wash the proppant out and carry it back to the surface so that the wellbore 12 is finally clear. The coiled tubing procedure results in shutdown of operations for 3-4 days and is additionally expensive to complete.
In contrast to existing systems, the mobile pump system 44 is able to overcome these screen outs successfully without reverting to the coiled tubing procedure because the electric motor and/or the turbine and/or the natural gas fired reciprocating engine 50 of the at least one pump 48 allows the at least one pump 48 to inject fluid for displacement at lower rates (as low as 0.1 bpm) over the course of hours or days without the risks posed by existing systems.
The ability to pump fluids at lower rates and to more precisely control the flow rate of the at least one pump 48 may be especially useful in prevention or mitigation of the adiabatic effect which can cause wireline cable melting and/or failure during pumpdown operations, which are common in hydraulic fracturing applications. On pumpdowns and related jobs involving wireline operations with pump assist, the wellhead is equipped with a lubricator and flow tubes to enable operations in a wellbore that can have pressure of several thousand pounds or more of pressure. The process of bringing the lubricator and the wellbore to the same pressure is known as “equalization.” When the air in the lubricator compresses faster than it can be evacuated, the adiabatic compression can cause the temperature to rise to as much as 1,200° F. (˜650° C.). At high temperatures, the insulating material of the cable would melt and the metallurgy of the steel in the cable would change, causing the actual wire in the wireline to become brittle and break, even to the point of severing the wireline within the lubricator. A common name for this condition is “wireline burn up” though other colloquialisms and phrases (such as “E-line burn”) describe the same condition.
In practice, to avoid wireline burn-up, the lubricator may first be filled with fluid prior to equalizing; this practice can mitigate much of the air and therefore most of the energy to cause damage. In order to fill the lubricator with fluid without inducing wireline burn-up, the fluid must be introduced at very low rates so that the air can be evacuated at an equivalent rate so as not to introduce temperature increases caused by compressing air rapidly. However, due to the limitations of existing pump systems with conventional engines and transmissions, the pump cannot pump at low enough rates to completely avoid against reaching damaging high temperatures. In contrast, the at least one pump 48 would be able to overcome this situation successfully because the electric motor and/or the turbine and/or the natural gas fired reciprocating engine 50 of the at least one pump 48 allows the at least one pump 48 to inject fluid for displacement of the air in the lubricator at lower rates (as low as approximately 0.1 bpm) without the risks posed by existing systems.
The at least one pump 48 may be configured to pump fluid at a pressure of up to 20,000 psi, such as up to 15,000 psi, up to 12,000 psi, up to 10,000 psi, up to 8,000 psi, or up to 6,000 psi, although higher pressures are also contemplated.
With continued reference to FIG. 2, a fluid tank 54 containing the positioning fluid 42 may be in fluid communication with the at least one pump 48. The at least one pump 48 may pump the positioning fluid 42 from the fluid tank 54 into the wellbore 12 to position the second plug 40 at a predetermined position in the wellbore 12.
With continued reference to FIG. 2, the mobile pump system 44 may position the second plug 40 at a predetermined position in the wellbore 12. The second plug 40 may be positioned in the wellbore by providing the previously-described mobile pump system 44. The at least one pump 48 of the mobile pump system 44 may be placed in fluid communication with the wellbore 12. The positioning fluid 42 may be pumped from the fluid tank 54 into the wellbore 12 using the at least one pump 48. The positioning fluid 42 pumped into the wellbore 12 may exert a pressure on the second plug 40 so as to move the second plug 40 along the lateral 14 and into the predetermined position. The position of the second plug 40 may be monitored from the surface by any means known in the art. The flow rate of the positioning fluid 42 pumped by the at least one pump 48 may be adjusted and controlled to position the second plug 40. The flow rate may be increased or decreased to adjust the rate at which the second plug 40 is moved. For example, when the second plug 40 is proximate the predetermined position, the flow rate of positioning fluid 42 may be lowered so that the position of the second plug 40 can be more precisely selected.
The mobile pump system 44 described herein may be used for any pressure pumping in which its characteristics are suitable and is not limited to the above-described application. For example, the mobile pump system 44 may be used in hydraulic fracturing applications. Hydraulic fracturing applications include any application associated with hydraulic fracturing performed at a production site. Hydraulic fracturing refers to fluid injected down the wellbore through perforations exceeding the minimum fracture pressure needed to fracture the rock in the formation. An example of a hydraulic fracturing application includes ancillary applications (“pumpdown”), such as positioning a plug (previously described), drillout applications, injecting acid into the formation, pressure testing casing, injecting diverter materials, “toe preps” involving initiating the first fracture network in a well, and the like. Drillout applications may include applications performed after the drilling and fracturing process has concluded and the well is being prepared to deliver hydrocarbon production. As one example, a drillout application may include milling or drilling out plugs previously positioned in the laterals and removing debris from the milled plugs by pumping the debris from the plug location to the surface.
The mobile pump system 44 allows for the reduction of capital costs compared to existing pump systems as the mobile pump system 44 requires less capital costs to build and operate. The mobile pump system 44 also significantly reduces repair and maintenance costs compared to existing systems. The use of the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 to drive the at least one pump 48 helps to reduce repair and maintenance costs. The electric motor and/or turbine and/or natural gas fired reciprocating engine 50 has a higher run time before requiring repairs compared to conventional internal combustion diesel engines (motors) used in existing pumps, which are diesel driven, for example. Keeping the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 cool and lubricated allows the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 to have a longer running life compared to the motors used in existing systems. The electric motor and/or turbine and/or natural gas fired reciprocating engine 50 also run more efficiently compared to the motors used in existing systems, such as in terms of emissions and consumption of fuel.
The mobile pump system 44 using the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 to drive the at least one pump 48 also requires significantly less fuel, monetary expenditure to maintain, and results in less environmental waste from maintenance, compared to existing systems. The electric motor and/or turbine and/or natural gas fired reciprocating engine 50 may utilize natural gas-powered electric generation, such as the field gas available at a production site. Thus, sulfur and other pollutants that arise from diesel combustion in conventional internal combustion motors are not present in the combustion of natural gas powered electric generation. The inclusion of the electric motor and/or the turbine and/or the natural gas fired reciprocating engine 50 in the mobile pump system 44 also reduces the noise associated with the mobile pump system 44 as pumps used in existing systems provide significant noise pollution and make it difficult to operate such pumps in residential areas (e.g., near housing plans, schools, hospitals, and the like).
The mobile pump system 44 includes a more compact design of the pumps 48 compared with existing systems. Multiple pumps 48 may be included on the trailer 46. The more compact system contributes to a safer production site 10 as there are less components at the production site 10 to cause a navigational and/or tripping hazard. This compact design also allows for the mobile pump system 44 to be set-up faster, resulting in less wasted time and faster time to production. Moreover, the mobile pump system 44 may include multiple of at least one component included in the system, such as multiple pumps 48, multiple electric motors and/or turbines and/or natural gas fired reciprocating engines 50, multiple controllers 80, and the like. The redundancy associated with certain of the components mounted on the trailer 46 of the mobile pump system 44 allows the system to avoid stopping operation of the pressure pumping application should one of the redundant components fail.
Referring to FIG. 3, an aerial view of the production site 10 is shown. The production site 10 includes a well pad 56. The well pad 56 includes six wellbores 12A-12F, each wellbore having a vertical region and at least one lateral traversing a direction different from the other wellbores of the well pad 56. In the schematic in FIG. 3, the non-limiting example of a pressure pumping application is being conducted at only the first wellbore 12A; however, multiple well heads may be in production (e.g., conducting oilfield activity) simultaneously.
The production site 10 may include at least one fracturing trailer 58A-58F, each including at least one fracturing pump 60A-60F. The production site 10 may further include sand and fracturing fluid storage tanks 62, which include sand and fracturing fluid used to keep fractures in the formation open. The production site 10 may further include a water tank 64 for pumping water into the first wellbore 12A. The water tank 64 may be in addition to or the same as the fluid tank 54 containing the positioning fluid 42. The production site 10 may further include a chemical storage tank 66, which may store any useful chemical, such as a friction reducer (e.g., polyacrylamide or a guar-based chemical). The fracturing pumps 60A-60F may be in fluid communication with at least one of the sand and fracturing fluid storage tanks 62, the water tank 64, and the chemical storage tank 66 to pump the various materials and/or fluids contained therein into the first wellbore 12A via piping 70. The piping 70 may include an isolation valve 72 for isolating the fracturing pumps 60A-60F from the first wellbore 12A when the fracturing pumps 60A-60F are not pumping fluid/material into the first wellbore 12A.
With continued reference to FIG. 3, the production site 10 may further include a data monitoring station 68, which may be used to monitor all operations conducted at the production site 10 and control those operations accordingly. In some non-limiting examples, the data monitoring station 68 may be remote from the production site 10.
With continued reference to FIG. 3, production site 10 may further include the mobile pump system 44A. The production site may include a single mobile pump system 44A or multiple mobile pump systems 44A-44B, as necessary. In the non-limiting example of FIG. 3, a first mobile pumping system 44A is used to pump positioning fluid 42 into the first wellbore 12A. The first mobile pumping system 44A may include a first trailer 46A, a first power generator 52A, and a first pump 48A having a first electric motor 50A. The production site 10 may utilize a second mobile pumping system 44B in addition to or in lieu of the first mobile pumping system 44A. The second mobile pumping system 44B may include a second trailer 46B, a second power generator 52B, and two pumps 48B, 48C, each having an electric motor and/or turbine and/or natural gas fired reciprocating engine 50B, 50C. The production site 10 may include the fluid tank 54 containing the positioning fluid 42, and the fluid tank 54 may be in fluid communication with the first pump 48A of the first mobile pumping system 44A. The first mobile pumping system 44A and the second mobile pumping system 44B may be moved to and from the production site 10 without being permanently installed at the pumping site 10.
With continued reference to FIG. 3, the first pump 48A may be in fluid communication with the first wellbore 12A so as to pump the positioning fluid 42 into the first wellbore 12A. The first pump 48A may be in fluid communication with the piping 70 so as to be in fluid communication with the first wellbore 12A, and the first pump 48A may intersect with the piping 70 at a tie-in point 74. The tie-in point 74 may be upstream of the wellhead of the first wellbore 12A (e.g., before the piping 70 reaches the wellhead of the first wellbore 12A).
Referring to FIG. 4, a non-limiting example of the mobile pump system 44 may include a cab 76. The cab 76 may be a truck capable of attaching the trailer 46 thereto (such as via a fifth wheel), so that the trailer 46 may be hauled to and from the production site 10. The trailer 46 may be detachable from the cab 76 so that it may be left at the job site, or the trailer 46 may be an integrated part of the cab 76 (not detachable therefrom). In some examples, the cab 76 is the power generator 52 because the cab may fuel the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 used to drive the at least one pump 48.
Referring to FIG. 5, a top view of a non-limiting example of the mobile pump system 44 is shown, with the mobile pump system 44 including the trailer 46, the at least one pump 48 having the electric motor and/or turbine and/or natural gas fired reciprocating engine 50, and the power generator 52. The power generator 52 may be connected to the at least one pump 48 (e.g., the electric motor 50) to fuel the electric motor and/or turbine and/or natural gas fired reciprocating engine 50, such that the electric motor and/or turbine and/or natural gas fired reciprocating engine 50 may drive the at least one pump 48.
Referring to FIG. 6, a non-limiting example of the at least one pump 48 is shown. The at least one pump 48 may be any pump suitable for pumping the positioning fluid 42 as previously described. In one example, the at least one pump 48 may be an auger-style pump that includes an auger or impeller 78 driven by the electric motor and/or the turbine and/or natural gas fired reciprocating engine 50 to move the positioning fluid 42 into the wellbore 12. The auger-style pump may provide certain advantages, including allowing for a more precise control of flow rate, reduced maintenance, and ease of maintenance (based on the reduced number and simplicity of components).
Referring to FIG. 7, the at least one pump 48, the electric motor and/or the turbine and/or natural gas fired reciprocating engine 50, the generator 52, and/or other components (“controllable components”) of the mobile pump system 44 may be controlled remotely by a controller 80. As used herein, “remotely” refers to a geographic location separate from the controllable component. The at least one pump 48 may be controlled from the data monitoring station 68 or other location at the production site 10 (shown in FIG. 3), or the at least one pump 48 may be controlled off-site (not at the production site 10). The at least one pump 48 may be controlled by the controller 80 that is a portable computing device, such that the portable computing device may be moved between locations and is still able to control the at least one pump 48. The portable computing device may be, for instance, a laptop computer, a tablet computer, or a smartphone. Thus, relevant data associated with the mobile pump system 44 may be communicated to the controller 80 remote from the controllable component(s).
An exemplary graphical user interface (GUI) displayed on the controller 80 is shown in FIG. 7, and a user may control the controllable components by interacting with the GUI on the controller 80. The GUI may allow the user to control various features of the controllable components. Non-limiting examples include controlling the pump's 48 flow rate or the pressure of the at least one pump 48. The GUI may display the flow rate and pressure of the at least one pump 48. The GUI may allow the user to turn the at least one pump 48 on or off. The GUI may display the fill level of the fluid tank 54 or provide a status of the electric motor and/or the turbine and/or natural gas fired reciprocating engine 50, such as whether any issues are identified with the electric motor and/or the turbine and/or natural gas fired reciprocating engine 50. It will be appreciated that other aspects of the mobile pump system 44 may be controlled by interacting with the GUI, and any suitable layout of the GUI may be used. Multiple controllable components (e.g., multiple pumps) may be controllable from the same controller 80.
Beyond providing the capability to adjust certain parameters of the system, the GUI may display on the controller various diagnostic and monitoring information. As non-limiting examples, the GUI may display electric motor and/or the turbine and/or the natural gas fired reciprocating engine temperature, fluid levels, and pump revolutions per minute.
Referring to FIG. 8, a mobile pump system 82 is shown. The mobile pump system 82 may include a trailer 84 attachable to a vehicle for moving the trailer 84 to various locations. The mobile pump system 82 may include a controller 86 mounted on the trailer 84, the controller 86 in electrical communication with other components of the mobile pump system 82 (e.g., an electrical transformer 88, a variable frequency drive 90, a heat exchanger 92, an electric motor 94, a pump 96, a secondary pump 98, and a secondary electric motor 100). The controller 86 may communicate control signals to the other components to cause the other components to perform a predetermined action (e.g., activating or deactivating a component, changing a pump rate, changing a heat exchanger temperature, and the like).
The mobile pump system 82 may include an electrical transformer 88 mounted on the trailer 84. The electrical transformer 88 may increase or decrease a voltage from an external power source for use by one of the components of the mobile pump system 82. This may allow components of the mobile pump system 82 to be powered by an external power source not included on the trailer 84 by electrically connecting the external power source to the transformer 88, which may be electrically connected to the other components.
The mobile pump system 82 may include the variable frequency drive 90 mounted on the trailer 84. The variable frequency drive 90 may include an electro-mechanical drive system to control motor speed and/or torque of the electric motor 94 by varying motor input frequency and/or voltage.
The mobile pump system 82 may include the heat exchanger 92 mounted on the trailer 84 to regulate temperature of at least one of the other components (e.g., the electric motor 94 and/or the pump 96), such that the component can operate more efficiently. The heat exchanger 92 may function as a cooler to prevent a component of the mobile pump system 82 from overheating.
The mobile pump system 82 may include the electric motor 94 mounted on the trailer 84, the electric motor 94 as previously described herein. The mobile pump system 82 may also include the pump 96 a, 96 b (a single or multiple pumps may be included) mounted on the trailer 84. The pump 96 a, 96 b may include the features previously described herein in connection with at least one pump 48. The pump 96 a, 96 b may be driven by the electric motor 94.
With continued reference to FIG. 8 and referring to FIG. 11, the mobile pump system 82 may include a secondary pump 98 and/or a secondary motor 100 (e.g., an electric motor) mounted on the trailer 84. The secondary pump 98 may include a triplex or quintuplex pump. The secondary pump 98 may be configured for pumping fluid at higher pressure compared to the pump 96 a, 96 b of the mobile pump system 82. The secondary pump 98 may be selectively activated in situations in which the mobile pump system 82 is required to operate at a higher pressure. The secondary pump 98 may be isolated from the pump 96 a, 96 b of the mobile pump system. The secondary motor 100 may drive the secondary pump 98. The pump 96 a, 96 b and/or the secondary pump 98 may be in fluid communication with the wellbore 12 (see FIG. 2).
Referring to FIG. 9, a mobile pump system 102 may include any of the components discussed in connection with the mobile pump system 82 from FIG. 8 and may include any additional or alternative components as hereinafter described. The trailer 84 may include a connection portion 104 configured to engage with an engagement portion of a cab (e.g., a fifth wheel). The connection portion 104 may engage with a cab, such that the mobile pump system 102 may be transported by the cab to various locations, such as to and from a production site.
The mobile pump system 102 may include an inlet filter silencer 106 mounted on the trailer 84 to reduce noise emitted by any of the components included in the mobile pump system 102.
The mobile pump system 102 may include a turbine and/or a natural gas fired reciprocating engine 108 a, 108 b (a single or multiple turbines and/or natural gas fired reciprocating engines may be included) mounted on the trailer 84 and connected to the pump 96 a, 96 b. The turbine and/or natural gas fired reciprocating engine 108 a, 108 b may be enclosed in a housing. The turbine and/or natural gas fired reciprocating engine 108 a, 108 b may be an on-board (on the trailer 84) turbine and/or natural gas fired reciprocating engine to generate power on the trailer 84 for driving the pumps 96 a, 96 b. The turbine and/or natural gas fired reciprocating engine 108 a, 108 b may be directly coupled to the pump 96 a, 96 b via a gearbox 110 a, 110 b (a speed reduction mechanism may be included), which may include gear reduction components. The turbine and/or natural gas fired reciprocating engine 108 a, 108 b may be powered by using field gas (e.g., natural gas) e.g., introduced to the turbine to spin the turbine blades to create power to rotate the pump 96 a, 96 b. The power generated by the turbine and/or the natural gas fired reciprocating engine 108 a, 108 b may drive the pump 96 a, 96 b. The turbine and/or natural gas fired reciprocating engine 108 a, 108 b may be included in the mobile pump system 102 in addition to or in lieu of the electric motor 94 a, 94 b shown in the mobile pump system 82 shown in FIG. 8.
Referring to FIG. 10, a mobile pump system 112 may include all of the components from the mobile pump system 102 of FIG. 9 with the following additions or alterations. The mobile pump system 112 may include a fuel tank 114 (or multiple fuel tanks) mounted on the trailer. The fuel tank 114 may include any type of fuel suitable to fuel any of the components of the mobile pump system 112. Non-limiting examples of suitable fuels for the fuel tank 114 include compressed natural gas (CNG), liquefied natural gas (LNG), diesel fuel, gasoline, propane, butane, and other suitable hydrocarbons and the like. The fuel tank 114 may be in fluid communication with any of the components of the mobile pump system 112 capable of being fueled by the fuel contained in the fuel tank 114. The fuel tank 114 may include any pumps, pipes, hoses, and/or valves required to carry the fuel to the relevant components of the mobile pump system 112.
The fuel tank 114 may be used as a backup fuel supply in the event of a fuel supply interruption. A fuel supply interruption may include the interruption of field gas (e.g., natural gas supplied directly from the production site at which the mobile pump system 112 is located) to the mobile pump system 112. Inclusion of the fuel tank 114 on the trailer 84 allows the mobile pump system 112 to continue operation even in the event of such a fuel supply interruption, without the deployment of an emergency backup power supply to the production site.
The mobile pump system 112 may include a conditioning system 116 configured to condition the gas from the fuel tank 114 or the field gas supplied to the mobile pump system 112. The conditioning system 116 may include a gas heater to drop out solids and/or water from the gas and return it to the supply line. The conditioning system 116 may include at least one filter to filter out impurities in the fuel that could cause the system to malfunction.
Referring to FIGS. 12 and 13, another non-limiting example of a mobile pump system 200 is shown. The mobile pump system 200 may include at least one trailer 202 movable by a vehicle, such as a truck. The mobile pump system 200 may include a single trailer, as shown, but a mobile pump system including a plurality of trailers to mount the plurality of pumps and the turbine and/or natural gas fired reciprocating engine (as described hereinafter) is also contemplated. Certain components (e.g., the pumps) of the mobile pump system described herein may be mounted to a first trailer while other of the components (e.g., the turbine and/or natural gas fired reciprocating engine) of the mobile pump system may be mounted to a second trailer. As such, the mobile pump system 200 may be positioned at a site for performing a pressure pumping application without permanently installing the mobile pump system 200 at the site. A turbine and/or natural gas fired reciprocating engine 204 may be mounted to the trailer 202. The mobile pump system 200 may include a plurality of pumps 206 a, 206 b, 208, 218, each mounted to the trailer 202. The pumps may be in fluid communication with one another by a conduit 214. The conduit 214 may be configured to be placed in fluid communication with an outlet, which is in fluid communication with the intended destination of the fluid being pumped by the mobile pump system 200. For example, the conduit 214 may be configured to be placed in fluid communication with a wellbore in non-limiting scenarios in which fluid is being pumped into the wellbore by the mobile pump system 200.
The plurality of pumps 206 a, 206 b, 208, 218 may include at least one first pump 206 a, 206 b. In the non-limiting example of the mobile pump system 200 shown in FIGS. 12 and 13, two first pumps 206 a, 206 b are included; however, the mobile pump system 200 may include a single first pump or three or more first pumps. The first pump 206 a may be a multi-stage centrifugal injection pump (one example of which is shown in FIG. 14), each stage allowing for an increase in the flow rate and/or the pressure pumped. The first pump 206 a may be a pressure-balanced pump, so as to reduce the torque loading on the first pump 206 a, 206 b. In one non-limiting example of a pressure-balanced pump, a twelve stage pump may include a fluid inlet or suction port, such that when the fluid enters the fluid inlet or suction port, the fluid is flowed to stages 1-6. Before entering stages 7-12, the fluid may redirect around stages 7-12 and enter stage 12, followed by stage 11, stage 10, stage 9, stage 8, and stage 7, in that order, and discharge the fluid proximate to where the fluid inlet or suction port is located. Such an arrangement may create a more pressure load balanced pump, such that the torque from operation of the pumps is reduced. The reduced torque means that the system is not required to withstand high torques, leading to reduced design and maintenance costs. The first pump 206 a may be configured to pump fluid at a flow rate as low as 1.5 bpm or as low as 2.5 bpm or as low as 3.5 bpm. The first pump 206 a may be configured to pump fluid at a flow rate of up to 25 bpm, up to 30 bpm, up to 40 bpm, up to 50 bpm, up to 60 bpm, up to 70 bpm, or up to 80 bpm. The first pump 206 a may be configured to pump fluid at a flow rate of from 1.5-30 bpm, such as 2.5-30 bpm or from 1.5-60 bpm, such as from 2.5-60 bpm. The first pump 206 a may be configured to pump fluid at a pressure of 15,000 psi or greater, such as 16,000 psi or greater, or 20,000 psi or greater.
The inclusion of the first pump 206 a as a multi-stage centrifugal injection pump in combination with the positive displacement second pump 208 (described hereinafter) allows for costs of including a multiple high-cost pressure displacement pumps capable of operating at relatively higher flow rates (those flow rates associated with the first pump 206 a ) to be avoided.
The plurality of pumps 206 a, 206 b, 208, 218 may include at least one second pump 208. In the non-limiting example of the mobile pump system 200 shown in FIGS. 12 and 13, one second pump 208 is included; however, the mobile pump system 200 may include multiple second pumps. The second pump 208 may be a positive displacement pump. The positive displacement pump may be a reciprocating triplex or quintuplex pump (non-limiting examples of which are shown in FIGS. 15 and 17). The second pump 208 may be configured to pump fluid at a flow rate as low as 0.1 bpm. The second pump 208 may be configured to pump fluid at a flow rate at or below 2.5 bpm or below 1.5 bpm. The second pump 208 may be configured to pump fluid at a flow rate of from 0.1-2.5 bpm or from 0.1-1.5 bpm. The second pump 208 may be configured to pump fluid at a pressure of up to 15,000 psi.
The first pump 206 a may have a higher flow rate capability and/or a higher pumping pressure capability compared to the second pump 208. The second pump 208 may have a lower flow rate capability and/or a lower pumping pressure capability compared to the first pump 206 a . The flow rate capability and/or the pumping pressure capability of the first pump 206 a and the second pump 208 may include an overlap. The first set point and/or the second set point (described hereinafter) may fall within the overlap.
With continued reference to FIGS. 12 and 13, the turbine and/or the natural gas fired reciprocating engine 204 may be directly coupled to the first pump 206 a, 206 b and/or the second pump 208. In some non-limiting examples, the turbine and/or the natural gas fired reciprocating engine 204 may be directly coupled to the first pump 206 a, 206 b. The turbine and/or the natural gas fired reciprocating engine 204 may be directly coupled to the first pump 206 a, 206 b and/or the second pump 208 by a non-variable fixed ratio direct-coupled connection. The turbine and/or the natural gas fired reciprocating engine 204 may be directly coupled to the first pump 206 a, 206 b and/or the second pump 208 by a direct-coupled gear connection including a speed reducer 210. The direct coupling eliminates the need for a transmission, thus eliminating moving parts that may require maintenance or result in additional operating costs. In some non-limiting examples, the turbine and/or the natural gas fired reciprocating engine 204 is connected to the speed reducer 210, which is connected to a plurality of first pumps 206 a, 206 b. The turbine and/or the natural gas fired reciprocating engine 204 may be powered using field gas, such that the mobile pump system 200 has a lower carbon footprint compared to systems using diesel engines, for example. The use of a turbine and/or natural gas fired reciprocating engine 204 on the mobile pump system 200 (as opposed to, for example, a diesel engine) allows the mobile pump system 200 to operate at lower decibels. The mobile pump system 200, when in operation, may emit less than 85 decibels, less than 80 decibels, less than 75 decibels, less than 70 decibels, or less than 65 decibels (compared to the at least 115 decibels emitted by certain existing systems utilizing a diesel engine.)
With continued reference to FIGS. 12 and 13, the mobile pump system 200 may include an electric motor 212. The electric motor 212 may be in electrical communication with the turbine and/or the natural gas fired reciprocating engine 204, such that that the turbine and/or the natural gas fired reciprocating engine 204 provides electrical energy to the electric motor 212. The electric motor 212 may be connected to the second pump 208 to power the second pump 208.
With continued reference to FIGS. 12 and 13, the mobile pump system 200 may include a fluid storage tank mounted on the trailer 202, and the fluid storage tank may be filled with a fluid to be pumped by the mobile pumping system 200. In some non-limiting examples, a fluid storage tank may be positioned at the site off of the trailer 202, in addition to or in lieu of the fluid storage tank mounted on the trailer 202.
The mobile pump system 200 may include a third pump 218 mounted on the trailer 202. The third pump 218 may be in fluid communication with at least one of the fluid storage tank, the first pump 206 a, 206 b, and the second pump 208 by the conduit 214. The third pump 218 may be configured to pump fluid from the fluid storage tank to at least one of the first pump 206 a, 206 b and the second pump 208. The third pump 218 may be a volute-type centrifugal pump and may pump fluid from the at least one of the fluid storage tank to the first pump 206 a, 206 b and/or the second pump 208 by the conduit 214 at a flow rate of from 0-3.5 bpm, such as 0-2.5 bpm and at a pressure of up to 15,000 psi.
With continued reference to FIGS. 12 and 13, the mobile pump system 200 may include a control system 216 comprising at least one processor programmed or configured to control at least one of the components of the mobile pump system 200 (and may be in electrical communication therewith). The control system 216 may receive input data from a user, such as via a graphical user interface, or may collect data from other sources, such at least one pressure sensor, flow sensor, temperature sensor, and the like, to communicate instructions to the components of the mobile pump system 200 (e.g., the first pump 206 a, 206 b, the second pump 208, and/or the turbine and/or the natural gas fired reciprocating engine 204). The control system 216 may communicate with the components of the mobile pump system 200 to control, for example, a rotational speed of the turbine and/or the natural gas fired reciprocating engine 204, a flow rate of the first pump 206 a, 206 b and/or the second pump 208, and a pumping pressure of the first pump 206 a, 206 b and/or the second pump 208. The control system 216 may use an advanced control algorithm to generate instructions to control the components of the mobile pump system 200. The advanced control algorithm may consider at least one of the following: pump properties, fluid properties, on-site atmospheric properties, and the like, to enable the control system 216 to generate the instructions to control the components of the mobile pump system 200.
The control system 216 may include an electronic governor configured to control at least one of the rotational speed of the turbine and/or the natural gas fired reciprocating engine 204, the flow rate of the first pump 206 a, 206 b and/or the second pump 208, and the pumping pressure of the first pump 206 a, 206 b and/or the second pump 208. The control system 216 may communicate the instructions for the components of the mobile pump system 200 to the electronic governor to cause the electronic governor to communicate with the components to cause the instructions to be effected by the components. The control system 216 enables the mobile pump system 200 to control small incremental adjustments in the rotational speed of the turbine and/or the natural gas fired reciprocating engine 204, the flow rate of the first pump 206 a, 206 b and/or the second pump 208, and the pumping pressure of the first pump 206 a, 206 b and/or the second pump 208 without transmission or gear-based controls, which lack the capability for the highly precise controls of the mobile pump system 200.
The control system 216 may receive set point data from a user that specifies a desired a rotational speed of the turbine and/or the natural gas fired reciprocating engine 204, a flow rate of the first pump 206 a, 206 b and/or the second pump 208, and/or a pumping pressure of the first pump 206 a, 206 b and/or the second pump 208, such as by the user entering the set point data into a graphical user interface. Based on the user specifying a desired rotational speed of the turbine and/or the natural gas fired reciprocating engine 204, the control system 216 may automatically generate instructions (based on the advanced control algorithm, for example) to cause the first pump 206 a, 206 b and/or the second pump 208 to operate at a flow rate and/or a pumping pressure, such that the desired rotational speed may be changed or maintained. Based on the user specifying a flow rate of the first pump 206 a, 206 b and/or the second pump 208, the control system 216 may automatically generate instructions (based on the advanced control algorithm, for example) to cause the first pump 206 a, 206 b and/or the second pump 208 to operate at a pumping pressure and/or the turbine and/or the natural gas fired reciprocating engine 204 to operate a rotational speed, such that the desired flow rate may be maintained. Based on the user specifying a pumping pressure of the first pump 206 a, 206 b and/or the second pump 208, the control system 216 may automatically generate instructions (based on the advanced control algorithm, for example) to cause the first pump 206 a, 206 b and/or the second pump 208 to operate at a flow rate and/or the turbine and/or the natural gas fired reciprocating engine 204 to operate a rotational speed, such that the desired pumping pressure may be maintained. Therefore, a deviation of the actual data value from the set point data value may cause the control system 216 to generate instructions to the relevant components to cause the components of the mobile pump system 200 to automatically adjust to return to the set point value.
The control system 216 may be configured to communicate (e.g., via the electronic governor) with the turbine and/or the natural gas fired reciprocating engine 204 to control the rotational speed of the turbine and/or the natural gas fired reciprocating engine 204. The control system 216 may adjust the rotational speed of the turbine and/or the natural gas fired reciprocating engine 204 by an incremental amount as low as the rpm required to change the flow rate by 0.1 bpm.
The control system 216 may be configured to communicate (e.g., via the electronic governor) with the first pump 206 a, 206 b and/or the second pump 208 to control the flow rate thereof. The control system 216 may adjust the flow rate of the first pump 206 a, 206 b and/or the second pump 208 by an incremental value as low as 0.1 bpm. In some non-limiting examples, the control system 216 may automatically adjust the flow rate of the first pump 206 a, 206 b and/or the second pump 208 to reach or maintain a pressure pumping set point value specified by the user for the first pump 206 a, 206 b and/or the second pump 208.
The control system 216 may be configured to communicate (e.g., via the electronic governor) with the first pump 206 a, 206 b and/or the second pump 208 to control the pumping pressure thereof. In some non-limiting examples, the control system 216 may automatically adjust the pumping pressure of the first pump 206 a, 206 b and/or the second pump 208 to reach or maintain a flow rate set point value specified by the user for the first pump 206 a, 206 b and/or the second pump 208.
With continued reference to FIGS. 12 and 13, the control system 216 may be configured to perform a “hand-off” operation. The hand-off operation may include the control system 216 being configured to activate the second pump 208, with the first pump 206 a, 206 b deactivated, with a flow rate of the mobile pump system 200 below a first set point to cause the second pump 208 to pump a pumping fluid from the fluid storage tank to the outlet. The control system 216 may be configured to, in response to the flow rate of the mobile pump system 200 reaching the first set point, activate the first pump 206 a, 206 b to cause the first pump 206 a, 206 b to pump the pumping fluid. The control system 216 may be configured to deactivate the second pump 208, with the first pump 206 a, 206 b still activated, in response to the flow rate of the mobile pump system 200 reaching a second set point, with the second set point greater than or equal to the first set point. In some non-limiting examples, the control system 216 may cause the pumping fluid to be pumped to the outlet by the second pump 208 and not the first pump 206 a, 206 b with the flow rate of the mobile pump system 200 below the first set point, and the pumping fluid to be pumped to the outlet by the first pump 206 a, 206 b and optionally the second pump 208 with the flow rate of the mobile pump system at or above the first set point.
In one non-limiting illustrative example, the mobile pump system 200 may initially be deactivated, having a flow rate associated therewith of 0 bpm. The mobile pump system 200 may be activated to begin pumping the pumping fluid, and the control system 216 may activate the second pump 208 to begin the pumping application. The second pump 208 may pump the pumping fluid with the first pump 206 a, 206 b deactivated at lower flow rates (below the first set point and/or below the minimum flow rate pumping capability of the first pump 206 a, 206 b). Thus, the third pump 218 may flow the pumping fluid from the fluid storage tank to the second pump 208 when the flow rate of the mobile pump system 200 is below the first set point, such that the second pump 208 moves the pumping fluid to the outlet. Upon the flow rate of the mobile pump system 200 reaching the first set point, the control system 216 may activate the first pump 206 a, 206 b to cause the first pump 206 a, 206 b to pump pumping fluid. Thus, the third pump 218 may flow the pumping fluid from the fluid storage tank to the first pump 206 a, 206 b when the flow rate of the mobile pump system 200 reaches the first set point, such that the first pump 206 a, 206 b moves the pumping fluid to the outlet. At a second set point equal to or higher than the first set point, the control system 216 may deactivate the second pump 208 so that only the first pump 206 a, 206 b (of the first 206 a, 206 b and second pumps 208) is moving pumping fluid to the outlet. The first pump 206 a, 206 b may pump the pumping fluid at a flow rate above the capabilities of the second pump 208. In some non-limiting examples, the first set point is equal to the second set point, such that as the control system 216 activates the first pump 206 a, 206 b, the second pump 208 is deactivated (at the same set point). In some non-limiting examples, the second set point is higher than the first set point such as between the first set point and the second set point, the first pump 206 a, 206 b and the second pump 208 work in tandem to flow pumping fluid to the outlet.
With continued reference to FIGS. 12 and 13, the control system 216 may be configured to initiate a start-up protocol to run the mobile pump system 200. The start-up protocol may include the control system 216 causing the second pump 208 to be activated, while the first pump 206 a, 206 b remains deactivated, until a flow rate effected by the mobile pump system 200 is at least 1.5 bpm. The control system 216 may be configured to activate the first pump 206 a, 206 b, while the second pump 208 is still activated, once the flow rate effected by the mobile pump system 200 is at a first set point. The first set point may be at least 1.5 bpm, such as at least 2.5 bpm. The first set point may range from 1.5-3.5 bpm, such as from 1.5-2.5 bpm or 2.5-3.5 bpm. Further, the control system 216 may be configured to deactivate the second pump 208, while the first pump 206 a, 206 b is still activated, once the flow rate effected by the mobile pump system is at a second set point. The second set point may range from 1.5-3.5 bpm, such as from 1.5-2.5 bpm. The second set point may be equal to or higher than the first set point. The flow rate associated with the second pump 208 may be phased out as the flow rate associated with the first pump 206 a, 206 b increases.
As illustrated by the above-described operation of the control system 216 controlling activation and deactivation of the first pump 206 a, 206 b and the second pump 208, the mobile pump system 200 has been designed to handle ancillary pressure pumping applications associated with hydraulic fracturing, which often require the full range of low rate/high pressure pumping applications to high rate/high pressure pumping applications. The combination of the first pump 206 a, 206 b and the second pump 208 on the mobile pump system 200 enables these pumping parameters to be achieved using a mobile system with lower capital costs. Further, the above-described activation and deactivation of the first pump 206 a, 208 and the second pump 208 (e.g., in the operating order described) allows for the second pump 208 capable of operating at lower flow rates to hand-off the pumping application to the first pump 206 a, 206 b, which is capable of operating at higher flow rates.
The utilization of the first pump 206 a, 206 b in the mobile pump system 200, which may be a multi-stage centrifugal injection pump, at pump rates above 1.5 bpm, such as above 2.5 bpm, above 3.5 bpm, or above 5 bpm allows for fracture propagation to occur more efficiently compared to a pumping system only including a positive displacement pump. The multi-stage centrifugal injection pump allows for an almost instantaneous response to formation breakdown and is capable of increasing flow rate relatively more seamlessly to achieve a target pressure. Thus the combination of the first pump 206 a, 206 b with the second pump 208 of a different style on the trailer 202 allow for the pump more suitable for the particular pumping application (or stage thereof) to be seamlessly used on the mobile pumping system 200.
The mobile pump system 200 may include a fuel buffering system, which may be positioned to remove undesired liquids, solids, and other debris from the chamber of the turbine 204 and/or the natural gas fired reciprocating engine and/or to prevent such products from entering the chamber of the turbine and/or the natural gas fired reciprocating engine 204.
The turbine and/or natural gas fired reciprocating engine 204 may generate excess power, in excess of the power needed to power the mobile pump system 200, such that the excess power may be transferred to other on-site locations to power other on-site components. For example, the excess power may be directed to other on-site needs, such as wireline needs, water transfer needs, and the like. The turbine 204 may include a shaft on a side opposing the side of the mobile pump system 200 which may rotate a standard electric motor and/or generator and send the excess power (at a specified wattage) through a cable to the other on-site components to provide the necessary power requirement.
The mobile pump system 200, may be positioned on a pump site to perform a pressure pumping application thereon. The pressure pumping application may be an oil/gas-field or non-oil/gas-field-related application.
The mobile pump system 200 positioned on a pump site may be used to perform the previously-described “plug-and-perf” method in which a plug is positioned in a lateral of a wellbore using the fluid pumped into the wellbore by the mobile pump system 200.
The mobile pump system 200 positioned on a pump site may be used to perform a toe prep application. Toe prep applications prepare the well for the commencement of fracture stimulation operations. Toe preps involve establishing an initial pathway for fracture propagation into the reservoir from the well, thereby allowing fluid communication from inside the wellbore into the target formation. Toe preps may involve shifting casing sleeves through building pressure using fluid pumped by the mobile pump system 200 to provide the pathway for fluid to exit the casing into the formation. Toe preps may also involve tubing-conveyed perforating (TCP) and other wireline conveyed perforating, for example, in conjunction with the fluid pumped by the mobile pump system 200. Injection tests, like Diagnostic Fracture Injection Tests (DFIT), are commonly performed at the beginning of fracture stimulation operations and can be designed for low-rate/high pressure and/or high-rate/high pressure through the range of capabilities of the mobile pump system 200.
The mobile pump system 200 may be positioned at an agricultural site to move water or other fluid for an agricultural application. The mobile pump system 200 may be positioned at a mining site to move water or other fluid for a mining application, such as dewatering and or supplying water in coal and/or precious metal mining operations.
The mobile pump system 200 positioned on a pump site may be used to perform a drill-out application. Drill-out applications are performed after a well is fracture stimulated. During multi-stage fracture stimulation operations, plugs are placed in the lateral for zonal isolation prior to the performance of additional fracture stimulation stages. Typically plugs are spaced 150 ft to 300 ft apart in a wellbore but are not limited to those distances. At a time after fracture stimulations have been completed, these plugs are drilled out. A bit or mill is commonly placed at the end of a tubing string or coiled tubing, for instance, and is rotated to drill up each plug in succession. During drill-out operations, fluid may be circulated to keep the wellbore clean and to carry cuttings and debris out of the wellbore. This fluid is circulated by the mobile pump system 200 at potentially very low rates, such as 1-2 bpm (or lower), and higher rates, such as 8-9 bpm (or higher), depending on tubing and casing sizes, for instance, or condition of the well as regards sand from fracture stimulation operations and debris.
The mobile pump system 200 positioned on a pump site may be used to perform an industrial purging application. In industrial purging, piping associated with plant or factory operations, for instance, may require treatments that can include flushing debris, cleansing the system, or clearing blockages utilizing a fluid pumped by the mobile pump system 200.
The mobile pump system 200 positioned on a pump site may be used to perform a pipeline pressure testing application. Before pipelines are placed into service, pipeline pressure testing operations are utilized to assure that the system safely meets the maximum allowable operating pressures (MAOP). Additionally, pipelines are tested at regular intervals to assure safe operations with regard to pressure. Fluid is pumped into the pipeline(s) by the mobile pump system 200 and held at a designated pressure for a determined period of time. The mobile pump system's 200 precise controls can achieve designed pressures more accurately than conventional pumps, as in those involving diesel engines and transmissions.
The mobile pump system 200 positioned on a pump site may be used to perform a hydro-blasting application. Whereas sand blasting and dry blasting introduces particulate matter into the air, hydro-blasting utilizes no abrasives but utilizes fluid pressure (as in pressure washing) instead. Fluid pumped at a variety of pressures by the mobile pump system 200 with its precise controls can be utilized in a variety of applications, such as stripping old paint from metal surfaces, for example.
The mobile pump system 200 may perform a pressure pumping application by activating the second pump 208, with the first pump 206 a, 206 b deactivated, until a flow rate effected by the mobile pump system 200 is at least 1.5 bpm; and activating the first pump 206 a, 206 b, while the second pump 208 is still activated, once the flow rate effected by the mobile pump system 200 is at a first set point, the first set point being at least 1.5 bpm. Performing the pressure pumping application may further include deactivating the second pump 208, while the first pump 206 a, 206 b is still activated, once the flow rate effected by the mobile pump system 200 is at a second set point, the second set point being equal to or higher than the first set point.
Although the invention has been described in detail for the purpose of illustration based on what is currently considered to be the most practical and preferred embodiments, it is to be understood that such detail is solely for that purpose and that the invention is not limited to the disclosed embodiments, but, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present invention contemplates that, to the extent possible, one or more features of any embodiment can be combined with one or more features of any other embodiment.

Claims

The invention claimed is

1. A mobile pump system, comprising:

at least one trailer movable by a vehicle;

a plurality of pumps comprising a first pump and a second pump, wherein the first pump and the second pump are each mounted to the at least one trailer, wherein the first pump and the second pump are each in fluid communication with an outlet configured to flow a fluid from the mobile pump system to a destination and with a fluid source configured to hold a pumping fluid;

a power source mounted to the at least one trailer and directly coupled to the first pump and/or the second pump, wherein the power source comprises a turbine and/or a natural gas fired reciprocating engine; and

a control system configured to:

activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the second pump to pump the pumping fluid;

in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the first pump to pump the pumping fluid; and

deactivate the second pump, with the first pump activated, in response to the flow rate of the mobile pump system reaching a second set point, wherein the second set point is greater than or equal to the first set point.

2. The mobile pump system of claim 1, wherein the first pump is configured to pump fluid at a flow rate as low as 1.5 bpm and at a flow rate of up to 30 bpm, and

wherein the second pump is configured to pump fluid a flow rate as low as 0.1 bpm.

3. The mobile pump system of claim 1, wherein the first pump comprises a multi-stage centrifugal injection pump.

4. The mobile pump system of claim 1, wherein the first pump comprises a pressure-balanced pump.

5. The mobile pump system of claim 1, wherein the second pump comprises a positive displacement pump.

6. The mobile pump system of claim 5, wherein the positive displacement pump is a reciprocating triplex or quintuplex pump.

7. The mobile pump system of claim 1, wherein the control system comprises an electronic governor configured to control at least one of a rotational speed of the power source, a flow rate of the first pump and/or the second pump, and a pumping pressure of the first pump and/or the second pump.

8. The mobile pump system of claim 7, wherein the electronic governor is configured to adjust the flow rate of the first pump and/or the second pump by an incremental amount as low as 0.1 bpm.

9. The mobile pump system of claim 1, wherein the power source is directly coupled to the first pump, wherein the direct coupling comprises a non-variable, fixed ratio direct-coupled connection or a direct-coupled gear connection including a speed reducer.

10. The mobile pump system of claim 1, wherein the second pump is powered by an electric motor receiving power generated by the power source.

11. The mobile pump system of claim 6, wherein the control system is configured to initiate a start-up protocol by:

activating the second pump, with the first pump deactivated, until the flow rate of the mobile pump system is at least 1.5 bpm; and

activating the first pump, while the second pump is still activated, once the flow rate of the mobile pump system is at the first set point, wherein the first set point is at least 1.5 bpm.

12. The mobile pump system of claim 1, wherein the mobile pump system is not permanently installed at a site for performing a pressure pumping application.

13. The mobile pump system of claim 1, wherein the power source is operated using field gas.

14. The mobile pump system of claim 1, wherein the first pump and/or the second pump are configured to pump fluid at a pressure of 15,000 psi or greater.

15. The mobile pump system of claim 1, further comprising a fluid storage tank mounted to the at least one trailer and a third pump mounted to the at least one trailer and in fluid communication with the fluid storage tank, the first pump, and the second pump, wherein the third pump is configured to pump fluid from the fluid storage tank to the first pump and/or the second pump.

16. The mobile pump system of claim 1, wherein the pumping fluid is pumped to the outlet by the second pump and not the first pump with the flow rate of the mobile pump system below the first set point, and the pumping fluid is pumped to the outlet by the first pump and optionally the second pump with the flow rate of the mobile pump system at or above the first set point.

17. A method for performing a pressure pumping application, comprising:

positioning the mobile pump system of claim 1 on a pump site.

18. The method of claim 17, further comprising:

19. The method of claim 18, further comprising:

deactivating the second pump, while the first pump is still activated, once the flow rate flow rate of the mobile pump system is at the second set point.

20. A mobile pump system, comprising:

a trailer movable by a vehicle;

a plurality of pumps comprising a first pump and a second pump, wherein the first pump and the second pump are each mounted to the trailer, wherein the first pump and the second pump are each in fluid communication with an outlet configured to flow a pumping fluid from the mobile pump system to a destination and configured to be in fluid communication with a fluid storage tank configured to hold the pumping fluid, wherein the first pump comprises a pressure-balanced multi-stage centrifugal injection pump, wherein the second pump comprises a reciprocating triplex or quintuplex positive displacement pump;

a power source mounted to the trailer and directly coupled to the first pump, wherein the power source comprises a turbine and/or a natural gas fired reciprocating engine, wherein the direct coupling comprises a non-variable, fixed ratio direct-coupled connection or a direct-coupled gear connection including a speed reducer;

a third pump mounted to the trailer and configured to be placed in fluid communication with the fluid storage tank, wherein the third pump is in fluid communication with the first pump and the second pump, wherein the third pump is configured to pump the pumping fluid from the fluid storage tank to the first pump and/or the second pump and

a control system configured to:

activate the second pump, with the first pump deactivated, with a flow rate of the mobile pump system below a first set point to cause the third pump to pump the pumping fluid from the fluid storage tank to the second pump which is configured to pump the pumping fluid to the outlet;

in response to the flow rate of the mobile pump system reaching the first set point, activate the first pump to cause the third pump to pump the pumping fluid from the fluid storage tank to the first pump which is configured to pump the pumping fluid to the outlet; and