Patent Grant
10221856
In the drilling and completion industry, the formation of boreholes for the purpose of production or injection of fluid is common. Hydrocarbons such as oil and gas can be recovered from the subterranean formation using the boreholes. Various operations require the pumping of fluid into the borehole. In many instances, it is necessary to pump a large volume of fluid into the borehole. For example, hydraulic fracture stimulation operations often require the concurrent use of multiple fracturing fluid pumping units at a single well site in order to provide the desired quantity of fracturing fluid needed to fracture the earthen formation. Typically, multiple trailer or skid mounted hydraulic fracturing fluid pumping units, each including a single diesel motor, driveline and a single pump, are simultaneously used to provide the requisite demand of fracturing fluid into the borehole.
While the use of an electric motor in place of a diesel motor could reduce weight on the skid and create less undesirable exhaust emissions at the well site, large horsepower electric drives create large inrush starting currents (the maximum, instantaneous input current drawn by an electrical device when first turned on). The use of high capacity distribution wire and/or sub-station transformers forces higher watt-hour (“Wh”) utility rates and other associated costs. The normal operating power of large electric driven pumps and compressors is approximately 0.15-0.25 of locked rotor start inrush. Mitigation schemes include variable frequency drive (“VFD”) controls, soft-start devices, and reduced voltage operation. However, all of these starting methods are problematic in the harsh oilfield environment, with respect to one or more of size, weight, complexity, and cost.
Natural gas has also been employed to drive a dedicated on-site turbine generator to eliminate the need for a transmission in the production of electricity, to power the fracturing modules, blenders, and other on-site operations as necessary, including other local equipment, including coiled tubing systems and service rigs. The use of a dedicated power source has been preferred over grid power because during startup of a fracturing operation, massive amounts of power are required such that the use of grid power would be impractical. The potential for very large instantaneous adjustments in power drawn from the grid during a fracturing operation could jeopardize the stability and reliability of the grid power system, as well as result in increased costs passed on to the operator. Accordingly, a site-generated and dedicated source of electricity has provided a more feasible solution in powering an electric fracturing system. While providing an alternative to grid powered systems, the use of site-generated sources of electricity necessitates extra equipment at the well site.
The art would be receptive to alternative devices and methods useful in connection with enabling the use of electric motors in downhole fluid delivery operations without incurring the above-described problems.
A pump system positionable at a surface of a well site for downhole operations includes a pump assembly having a pump and a starting assist. The pump includes a crankshaft and is operable by a first motor. The starting assist includes a second motor and a gear system.
A method of starting a pump, operable by a first motor, in a pump system positionable at a surface of a well site for downhole operations, includes activating a second motor in a starting assist operatively connected to the pump, the starting assist rotating a crankshaft of the pump through a gear system; activating the first motor when the crankshaft rotates at a present frequency or a preset time has passed since the second motor was turned on; and deactivating the second motor while the first motor is rotating the crankshaft.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.
Referring initially to
An embodiment of the pump system 10 may be provided on a mobile chassis 16. The pump system 10 provides a high volume of fluid from the chassis 16 into an underground borehole. The chassis 16 may have any suitable form, configuration and operation. The illustrated chassis 16 is mounted on, or integral to, a carrier 24. As used herein, the terms “carrier” and variations thereof refers to any transportable or movable device, such as, for example, a skid or other frame, trailer, truck, automobile and other types of land-based equipment, a ship, barge and other types of waterborne vessels, etc. In some embodiments, the chassis 16 and carrier 24 may essentially be one in the same, such as in some instances when the chassis 16 is a skid. In one embodiment, for example, the carrier 24 may be an 18-wheel trailer 28, and the chassis 16 may include an elongated frame 20 that is mounted on, or integral to, the trailer 28. The chassis 16 is thus transportable between locations, such as between multiple well sites. It should be understood, however, that alternate types of chassis 16 and carriers 24 may be utilized with the pump system 10, or that the pump system 10 may be merely installed at a more permanent fixture at a well site.
The pump system 10 including the electric motor 34 and the pump assembly 56 are disposable upon the chassis 16. The motor 34 drives the pump 50, which pump (typically pressurized) fluid into the borehole, such as for hydraulic fracturing of the adjacent earthen formation, acid stimulation, work-over or remediation operations, as is and may become further known.
The motor 34 includes the drive shaft 36 extending axially therethrough and outwardly at a first end 38 and coupled thereto to the drive shaft 52 of the rump 50 when rotating the drive shaft 52. In one embodiment, the motor 34 may be a single or multi speed fixed frequency induction motor. In one embodiment, the electric motor 34 may be, but is not limited to, a permanent magnet AC motor. The illustrated pump 50 may, for example, be high horsepower plunger-style, triplex or quintuplex, fluid pump, and may have a power rating dependent on the HP of the motor 34. However, the present disclosure is not limited to the above details or examples, and any suitable motor 34 and pump 50 may be used. The use of an electric motor 34 verses a conventional diesel motor has one or more advantages. For example, the electric motor 34 may require fewer related components (e.g. transmission, gear box) and thus have a lighter weight (and potentially smaller footprint). Reducing weight on the chassis 16 is beneficial, for example, in jurisdictions having weight limits on equipment transported to or located at a well site, allowing greater pumping capacity within strict weight requirements. For another example, reducing weight on the chassis 16 may enable inclusion of second or additional fluid rumps 50 and motors 34 on a single chassis 16, thus increasing pumping capacity. For another example, use of the electric motor 34 instead of one or more diesel motors may cause less undesirable exhaust emissions at the well site, reducing the need for on-site emissions control operations. For yet another example, the electric motor 34 may not produce as much heat as the diesel motor. Consequently, if desired, a second electric motor and second fluid pump may be stacked atop the first set of electric motor 34 and fluid pump 50 on the chassis 16. (The second set of an electric motor and pump may otherwise be configured and operate the same as described herein with respect to the electric motor 34 and pump 50.) Thus, the carrier 24 may have two sets of motors 34 and pumps 50, essentially doubling the fluid pumping capacity of the system 10 as compared to a conventional system.
In one embodiment, a flex coupling 70 may be engaged between the motor 34 and pump 50. The flex coupling 70 may be useful, for example, to allow the motor 34 and pump 50 to move relative to one another during operations without disturbing their interconnection and operation or any other suitable purpose. The flex coupling 70 may have any suitable form, configuration and operation. For example, the flex coupling 70 may be a commercially available high horsepower diaphragm, or elastic, coupling. Likewise, the flex coupling 70 may be engaged between the motor 34 and pump 50 in any suitable manner. For example, a flex coupling 70 may be disposed around the drive shaft 36 of the electric motor 34 at the end 38 thereof. At the end 38, the flex coupling 70 may be connected to and engaged between an oilfield drive-line flange (not shown) on the motor 34 and an oilfield drive-line flange (not shown) on the pump 50. It should be understood, however, any suitable coupling may be used to allow relative movement of the motor 34 and pump 50 without disturbing the operation thereof.
The electric motor 34 may be controlled in any suitable manner, after the rotation of the driveshaft 52 of the pump 50 by the starting assist 54 has reached a preset rotation speed that would effectively reduce the inrush current of the motor 34. In one embodiment, the speed of the electric motor 34 may be controllable by a variable frequency drive (“VFD”) 76 disposed upon the chassis 16. The VFD 76 may be included because it is simple and easy to use, inexpensive, contributes to energy savings, increases the efficiency and life of, reduces mechanical wear upon and the need for repair of the electric motor 34, and any other suitable purpose or a combination thereof. Further, positioning the VFD 76 on the chassis 16 eliminates the need for a separate trailer housing typically used to house the control system for conventional fracturing fluid pumping systems. The VFD 76 may have any suitable configuration, form and operation and may be connected with the motor 34 and at least one external electric power source 78 in any suitable manner. In the illustrated embodiment shown in
Further, in another embodiment, the VFD 76 may be remotely controllable via a remote control unit (not shown) located at a remote, or off-site, location, or via automatic control from an external process control signal. Remote control of the VFD 76 may be included for any suitable reason, such as to avoid the need for an on-site operator and/or to reduce cost. Any suitable technique may be used for remotely controlling the VFD 76, such as via wireless, fiber optics or cable connection. Alternately or additionally, the VFD 76 may include an operator interface (not shown) mounted on the chassis 16 to allow an on-site operator to control the VFD 76 (e.g. to start and stop the motor 34 and adjust its operating speed and other functions) or override the remote control functions.
The pump 50 of the pump assembly 56 is a positive displacement pump, in particular a reciprocating pump. The pump 50, in one embodiment, is usable for a fracturing application in which fracturing fluid, such as, but not limited to a proppant filled slurry, is pumped downhole into a borehole for creating and potentially propping fractures in a formation. While particularly suited for a fracturing application, the pump system 10 may be employed in other applications. Each pump 50 includes a power assembly, sometimes referred to as a power end, and a fluid assembly, sometimes referred to as a fluid end. The power assembly includes a crankshaft housing which houses the driveshaft 52 (crankshaft) as will be further described below with respect to
One embodiment of the internal mechanics of the pump 50 is shown in
The starting assist 54 includes both a motor 58 (
While any gear set 62 may be utilized in the starting assist 54 that provides the necessary gear ratio with gear reduction,
While use of a planetary gear system 170 offers compact size to the starting assist 54, other gear systems 62 are employable in the starting assist 54. In one embodiment, a two stage gear train of the gear system 172 includes a first stage 182 and a second stage 184. An input (drive shaft 60 of motor 58) is connected to a first gear 186 that engages with a second gear 188. The second gear 188 is rotatable on an intermediate shaft 190 and carries a smaller third gear 192 that engages with fourth gear 194. Rotation of the fourth gear 194 rotates the drive shaft 52 of the pump 50 accordingly. It should be understood that the gear system 172 is also illustrative only, and any variety of gear systems could be employed that provides the desired gear reduction.
Thus, the starting assist 54 includes a motor 58 that is geared down so that it overcomes the starting friction of the pump 50 before the motor 34 kicks on. The gear system 62 has a turn down ratio, of X:Y, with X>Y, where for every X revolutions of the driveshaft 60, there are Y revolutions of the driveshaft 52. By example only, if the turn down ratio is 100:1, for every 100 revolutions of the driveshaft 60, there is one revolution of the driveshaft 52, and while the number of revolutions goes down, the torque goes up. The gear ratio is the number of turns it takes on the input shaft to get one turn of the output shaft. Thus in a 100:1 gearbox, 100 turns of the input shaft are required to get a single turn of the output. That means the 100:1 gearbox will, in theory, generate on output torque 100 times as powerful as the input torque. In practice, this may not actually happen with such a high gear ratio, because of friction, but in general, a high gear ratio will give a high output torque multiple. In this embodiment, the driveshaft 60 of the motor 58 must spin relatively fast, even though the driveshaft 52 of the pump 50 is barely turning. The starting assist 54 gets the driveshaft 52 of the pump 50 turning so that the motor 34 doesn't have to, so as to avoid the big surge current. Also, the VFD 76 can be smaller for the motor 34 of the pump system 10, and the motor 34 itself can be smaller, as opposed to a motor 34 and VFD 76 used in a pump system without the starting assist 54. Thus, the pump system 50 having the starting assist 54 allows for low voltage AC induction motors 34 to be utilized where otherwise not technically feasible. Furthermore, by building the starting assist 54 into the pump 50, standard motors 34 can be chosen. Additionally, the use of an available grid power system as the electric power sources 78 and 82 is made possible since the inrush starting current for the motor 34 is substantially decreased and the motor 58 is small and substantially geared down.
In one embodiment, the pump system 10 includes, or is operatively communicable with, a controller 100. The controller 100 may control the motor 58 to turn on (and draw power from the electrical power source 82) or turn off, or to turn the shaft 60 at a particular speed if available. Thus, the controller 100 may activate the starting assist 54, or alternatively an operator may turn on the starting assist 54. The controller 100 may also control the motor 34 to turn on or off or turn the shaft 36 at a particular speed, or may alternatively control the motor 34 through the VFD 76. Prior to turning on the motor 34, the controller 100 may receive data from the pump 50 indicative of the rotation speed of the shaft 52. An algorithm within the controller 100 may utilize the data to determine when the initial starting friction of the pump 50 has been overcome and may then subsequently instruct the motor 34 to turn on and draw power from the electrical power source 78. Once the pump 50 has started to slowly turn, information may be sent to the controller 100 to indicate when the motor 34 should be started. For example, the motor 34 may be started when a target rotational speed of the drive shaft 52 has been reached, or may be started after a preset time in which the motor 58 has been run. Alternatively, the pump system 100 may include a display displaying information about the speed of the drive shaft 52 and an operator may then choose to turn on the motor 34. The pump system 10 may include any number of sensors within any of the components of the pump system 10 to communicate with the controller 100 to operate the pump system 10 using the starting assist 54. The operation of the pump system 10 may further include turning the starting assist 54 off after the target rotational speed of the drive shaft 52 has been reached. In one embodiment, a shaft position encoder 102 on the drive shaft 52 allows intelligent synchronization of the drive shaft 36 and rotor position of the drive shaft 52. This prevents an out of phase (short duration) misalignment. In one embodiment, turning on the motor 34 moves the drive shaft 36 into coupling engagement with the drive shaft 52.
When pumping against a closed valve, a pressure test must be performed before the job. Pressure testing is improved by using the pump system 10 with the above-described starting assist 54. Providing high torque, low speed control of the pump 50 using the starting assist 54 significantly assists in preventing over-pressuring of the iron (high pressure piping) and/or fluid ends of the pump 50. By utilizing the small motor 58 that is geared way down, an operator can slowly build up pressure because the driveshaft 52 of the pump 50 is barely turning with increased rotation of the driveshaft 60. For example, the iron may be compromised and need to be replaced if pressure from the pump 50 goes over 15,000 psi in the iron (piping). If just an eighth of a turn on the pump 50 results in a couple hundred or even 1,000 pounds of pressure increase, the gear reduction provides fine resolution for adjustment on pressure, especially when the pressure gets above 10,000 pounds. Likewise, in cementing operations, the pump system 50 having the starting assist 54 also allows precision cement delivery.
The methods that may be described above or claimed herein and any other methods which may fall within the scope of the appended claims can be performed in any desired suitable order and are not necessarily limited to any sequence described herein or as may be listed in the appended claims, unless otherwise stated. Further, the methods of the present invention do not necessarily require use of the particular embodiments shown and described herein, but are equally applicable with any other suitable structure, form and configuration of components.
The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.
While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited. Moreover, the use of the terms first, second, etc. do not denote any order or importance, but rather the terms first, second, etc. are used to distinguish one element from another. Furthermore, the use of the terms a, an, etc. do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced item.
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