Patent Grant
8807960
Not applicable.
Not applicable.
Not applicable.
Embodiments described herein relate to wellbore servicing equipment and methods of servicing a wellbore.
Servicing a wellbore may include delivering a wellbore servicing fluid downhole and/or into a wellbore. A plurality of pumps may be used to deliver wellbore servicing fluid at a predetermined combined fluid flowrate and/or pressure. However, the very combination of the output of the plurality of pumps sometimes interferes with the ability of the plurality of pumps to precisely and/or accurately deliver the wellbore servicing fluids at a desired combined flowrate, pressure, or other characteristic of fluid delivery. Further, the combination of the outputs of the plurality of pumps sometimes contributes to undesirable wear and tear to the pumps and other related wellbore servicing equipment. Accordingly, there exists a need for a wellbore servicing system and a method of servicing a wellbore that delivers wellbore servicing fluids in a desired manner and with reduced wear and tear on the plurality of pumps and other wellbore servicing equipment.
Disclosed herein is a method of servicing a wellbore, comprising establishing a pumping profile having a performance plan, operating a first pump according to a first pumping parameter value, and operating a second pump according to the second pumping parameter value. The second pumping parameter value is selected relative to the first pumping parameter value to improve a conformance of a phase sensitive combined pump effect operational characteristic to the performance plan.
Further disclosed herein is a wellbore servicing system, comprising a pump group comprising a plurality of plungers wherein at least some of the plurality of plungers are substantially configured according to an equal phase angle distribution arrangement.
Also disclosed herein is a wellbore servicing system, comprising a pump group comprising a plurality of pumps wherein the sum of the flowrates of the plurality of pumps is substantially equal to a combined pump group flowrate and wherein at least one pumping parameter of the at least one of the plurality of pumps is variable to improve a conformance of a phase sensitive combined pump effect operational characteristic to a pumping profile of the wellbore servicing system.
Further disclosed herein is a method of servicing a wellbore, comprising establishing a pumping profile having a performance plan, operating a first pump to provide pressure pulses according to a first frequency, operating a second pump to provide pressure pulses according to a multiple of the first frequency, and controlling a relative pressure pulse phase between a first pressure pulse provided by the first pump and a second pressure pulse provided by the second pump to improve a conformance of a phase sensitive combined pump effect operational characteristic to the performance plan.
For a more complete understanding of the present disclosure, and for further details and advantages thereof, reference is now made to the accompanying drawings, wherein:
This application discloses systems and methods for increasing wellbore servicing system conformance to desired pumping profiles (explained in greater detail below) even while a plurality of pump outputs are combined. In some wellbore servicing systems, the combination of the outputs of a plurality of pumps can lead to non-conformance with respect to a desired pumping profile because the plurality of pumps and/or a plurality of plungers of the plurality of pumps are operating substantially in-phase, as explained in greater detail below. It will be appreciated that operation of a plurality of pumps and/or plungers substantially in-phase can cause the plurality of pumps to fail to deliver fluids as desired (e.g., according to a pumping profile) and may also damage the pumps and/or other wellbore servicing equipment connected to the pumps.
While explained in greater detail below, the present disclosure provides two primary embodiments for preventing and/or reducing in-phase operation of pumps and/or plungers. A first embodiment for preventing in-phase operation of pumps and/or plungers is accomplished generally by monitoring and/or otherwise controlling a phase of one or more pumps and/or plungers relative to one or more other pumps and/or plungers while the pumps and/or plungers are operated at substantially the same speed and/or flowrate. A second embodiment for preventing in-phase operation of pumps and/or plungers is accomplished generally by monitoring and/or otherwise selectively individually controlling the speed and/or flowrate of operation of the pumps and/or plungers so that in-phase or near in-phase operation is minimized and/or prevented by operating the pumps and/or plungers at different speeds and/or flowrates.
Both of the above solutions provide for allowing an increased conformance to a pumping profile by reducing and/or eliminating substantially in-phase operation of pumps and/or plungers. Further, a wellbore servicing system may be operated according to either embodiment to control and improve the conformance of a wellbore servicing system performance to a pumping profile. Such systems and methods may be useful because many wellbore servicing jobs require substantially strict conformance to a performance plan (e.g., as described below, a performance plan that lays out a desired combined pump flowrate of a wellbore servicing fluid such as a fracturing fluid). In particular, fracturing jobs and gravel pack jobs sometimes require substantial adherence to desired combined pump flowrates. The present disclosure provides an improved system and method for closely conforming to such desired combined pump flowrates and other combined pump effect operational characteristics. Accordingly, a wellbore servicing system 100 is disclosed below that may be operated according to a variety of methods and embodiments described herein.
Referring to
The wellbore servicing system 100 comprises a blender 114 that is coupled to a wellbore services manifold trailer 118 via a flowline or flowlines 116. As used herein, the term “wellbore services manifold trailer” is meant to collectively comprise a truck and/or trailer comprising one or more manifolds for receiving, organizing, and/or distributing wellbore servicing fluids during wellbore servicing operations. In this embodiment, the wellbore services manifold trailer 118 is coupled via outlet flowlines 122 and inlet flowlines 124 to three positive displacement pumps 120, such as the pump shown in
The blender 114 mixes solid and fluid components to achieve a well-blended wellbore servicing fluid. As depicted, sand or proppant 102, water or other carrier fluid 106, and additives 110 are fed into the blender 114 via feedlines 104, 108, and 112, respectively. The fluid 106 may be potable water, non-potable water, untreated, or treated water, hydrocarbon based or other fluids. The mixing conditions of the blender 114, including time period, agitation method, pressure, and temperature of the blender 114, may be chosen by one of ordinary skill in the art with the aid of this disclosure to produce a homogeneous blend having a desirable composition, density, and viscosity. In alternative embodiments, however, sand or proppant, water, and additives may be premixed and/or stored in a storage tank before entering the wellbore services manifold trailer 118.
The wellbore servicing system 100 further comprises sensors 136 associated with the pumps 120 to sense and/or report operational information about the pumps 120. The wellbore servicing system 100 further comprises pump control inputs 138 associated with the pumps 120 to allow selective variation of the operation of the pumps 120 and/or components of the pumps 120. In this embodiment, operational information about the pumps 120 is generally communicated to a main controller 140 by the sensors 136. Further, the pump control inputs 138 are configured to receive signals, instructions, orders, states, and/or data sufficient to alter, vary, and/or maintain an operation of the pumps 120. The main controller 140, sensors 136, and pump control inputs 138 are configured so that each pump 120 and/or individual components of the pumps 120 may be independently monitored and are configured so that operations of each pump 120 and/or individual components of the pumps 120 may be independently altered, varied, and/or maintained. The wellbore servicing system 100 further comprises a combined pump output sensor 142. The combined pump output sensor 142 is shown as being associated with flowline 134 which carries a fluid flow that results from the combined pumping efforts of all three pumps 120. The combined pump output sensor is configured to monitor and/or report combined pump effect operational characteristic values (defined and explained infra) to the main controller 140. Alternatively, the combined output can be obtained by summing the output from individual sensors 136.
Pumps 120 may be positive displacement pumps, for example of the type shown in
In conjunction with a wellbore servicing operation or job, the wellbore servicing system 100 is operable to deliver wellbore servicing fluids to the wellhead 132 according to an established pumping profile 200, for example, as shown in
Examples of operational characteristics of a wellbore servicing system include, but are not limited to, a combined fluid flowrate of a pump group and a combined rate of change of a fluid flowrate of a pump group. Similarly, operational characteristics of a wellbore servicing system may include, but not be limited to, a combined fluid delivery pressure of a pump group and a combined rate of change of a fluid delivery pressure of a pump group. Similarly, operational characteristics of a wellbore servicing system may include a torque of a pump of a pump group, a rate of change of a torque of a pump of a pump group, a power consumption of a pump of a pump group, and/or a rate of change of power consumption of a pump of a pump group. It will be appreciated that operational characteristics of a wellbore servicing system that are at least partially defined by and/or affected by the combined nature of operation of a plurality of pumps in a pump group may herein be referred to as a combined pump effect operational characteristic. In other words, an operational characteristic of a wellbore servicing system that is impacted by the joinder of the fluid flow outputs of a plurality of pumps of a pump group is herein described as a combined pump effect operational characteristic.
An example of a combined pump effect operational characteristic is clearly represented by the combined fluid flowrate of a pump group because the combined fluid flowrate of a pump group is inextricably related to the sum of the individual fluid flow output rates of each of the pumps of the pump group. While perhaps less easily explained, a torque of a pump of a pump group and a power consumption of a pump of a pump group may also be considered combined pump effect operational characteristics. This is the case because each pump, absent countervailing system components, affects a downstream fluid system (relative to the other pumps of the pump group) that inherently contributes to the torque and power required to operate the other pumps of the pump group. In similar ways, many operational characteristics, including operational characteristics not laid out above, may be properly considered combined pump effect operational characteristics. It will be appreciated that while combined pump output sensor 142 is shown as being associated with flowline 134, it may alternatively be associated with any other component of wellbore servicing system 100 that may provide feedback for monitoring a combined pump effect operational characteristic.
Examples of pumping parameters that may vary operation of a pump of a pump group include, but are not limited to, changing a speed of operation of a pump, changing an upstream or downstream fluid pressure relative to a pump, changing a power consumption of a pump, and changing a torque and/or gearing associated with a pump. Further, the operation of a pump may be varied by changing an internal volume of a pump, changing a slip clutch setting (or similar device setting) of a pump, changing a composition of fluid fed to a pump (i.e., a viscosity or density of the fluid), and/or selectively operating a pump in on and off states. The operation of a pump may further be varied by changing other parameters of pump operation such as, but not limited to, changing an input and/or output fluid flowrate of a pump, changing the set-up of a pump component (e.g., changing a plunger stroke length of a positive displacement pump), or changing a location of a pump component (e.g., a plunger of a positive displacement pump such as a pump 120). Further, changing an electrical voltage supplied to a pump or changing a voltage and/or frequency waveform supplied to a pump (e.g., in a pump comprising a variable frequency drive motor) may vary the operation of a pump.
It will be appreciated that, in some cases, a change to one pumping parameter may in practice lead to a change in another pumping parameter. For example, in some embodiments, changing a speed of a pump may directly affect a flowrate of the same pump. Similarly, in some embodiments, a change in an electrical voltage supplied to a pump may directly affect a speed and a flowrate of the same pump. It will be appreciated that any of the above-listed and/or any other suitable pumping parameters may be used alone or in combination to maintain, change, or otherwise affect an operational characteristic of a wellbore servicing system. Accordingly, varying pumping parameters of a pump of a pump group selectively allows operation of a wellbore servicing system in a manner that conforms to a performance plan of a pumping profile. It will be appreciated that pumping parameters of pumps 120 may be varied by using the main controller 140 to send a signal or otherwise provide the pump control inputs 138 with an instruction to change a pumping parameter.
Referring now to
It will be appreciated that while the performance plan of pumping profile 200 represents a target plan for the combined flowrate delivered downhole over a period of time, the pump group 121 of the wellbore servicing system 100 typically cannot conform precisely, without error, to the performance plan of pumping profile 200. Instead, the pump group 121 is generally capable of conforming closely to the desired combined flowrate, but with short-term transient variability in the actual flowrate. In other words, while the pump group 121 can effectively approximate the desired combined flowrate, the pumps 120 of the pump group 121 and the related wellbore servicing equipment cause the flowrate of the pump group 121 to overshoot and undershoot the target flowrate laid out by the performance plan of the pumping profile 200 while substantially averaging the desired combined flowrate. In this embodiment, the above-described overshooting and undershooting may occur a plurality of times within a given timeframe (e.g., less than one second) of elapsed operation of the pump group 121. It will be appreciated that the above described overshooting and undershooting is attributable to, at least in part, the degree to which a plurality of pumps 120 and/or plungers 508 operate substantially in-phase (explained infra). Accordingly, the combined flowrate of the pump group 121 may be referred to as a phase sensitive combined flowrate operational characteristic.
Pumping profile 200 further comprises a performance plan 204 for a combined pump group pressure, the pressure at which fluids are delivered downhole by pump group 121. In this embodiment, and according to pumping profile 200, the pump group 121 is tasked with delivering wellbore servicing fluids downhole at a pressure of about 3500 psi over the entire about 200 minutes of operation. It will be appreciated that in other embodiments and in this embodiment when operated according to alternative pumping profiles, pump group 121 may be tasked with delivering wellbore servicing fluids downhole at various other pressures over the course of operation of the pump group 121. Pumping profile 200 is an example of a pumping profile that comprises a plurality of performance plans since pumping profile 200 comprises both the performance plan 202 for a combined pump group flowrate and the performance plan 204 for the combined pump group pressure. It will be appreciated that overshooting and undershooting of the desired pressure may occur and is attributable, at least in part, to a degree to which a plurality of pumps 120 and/or plungers 508 operate substantially in-phase (explained infra). Accordingly, the combined pump group pressure of the pump group 121 may also be referred to as a phase sensitive combined flowrate operational characteristic. Any combined pump effect operational characteristic that is affected by a relative phase angle between plungers 508 and/or pumps 120 may be referred to as a phase sensitive combined pump effect operational characteristic.
Referring now to
In this disclosure, when a group of plungers (e.g., all or some of the total plungers in a pump group) are evenly spread over the entire 360 degrees of movement, the arrangement for that group of plungers may be referred to as an “equal phase angle distribution.” For example, a wellbore servicing system may comprise three pumps having five plungers each, totaling fifteen plungers. The fifteen plungers may be operated out of phase where the fifteen plungers are configured to be phase-shifted by 24 degrees (according to the relationship of 360 degrees being separated evenly by the fifteen plungers). In some embodiments, the above equal phase angle distribution may be accomplished by first providing each pump with the five plungers being offset by 72 degrees, thereby spreading the five plungers of each pump over the entire 360 degrees. With the three pumps arranged as such, the equal phase angle distribution may be completely accomplished by maintaining a 24 degree offset between the otherwise identical pumps, thereby ensuring that during pumping, no two plungers are located at the same location along their respective stroke paths. In this disclosure, such reference to angularly offsetting pumps relative to each other may be referred to as establishing a relative phase angle between pumps.
Further, alternative plunger phase shifting may be accomplished for any number of plungers of other alternative embodiments by dividing the full 360 degrees by the total number of plungers in the pump group. Equal phase angle distribution is particularly useful where a pump group comprises primarily a plurality of substantially similar pumps, each pump having the same number of plungers and each pump being capable of operating at the same speed as the speed of other pumps in the pump group.
A further approach to controlling a pump group is to consider the existence of pressure pulses that result from the stroking action of each of the individual plungers within a pump group. It will be appreciated that while the previously discussed equal phase angle distribution is beneficial to pump groups comprising substantially similar pumps (e.g., pumps that have the same number of plungers and are capable of running at substantially the same speeds), alternative embodiments of pump groups may comprise pumps with different numbers of plungers. For example, a pump group may comprise a Triplex pump (having three plungers) and a Quintuplex pump (having five plungers). It will be appreciated that if pressure pulsations produced by multiple plungers of the pump group occur substantially simultaneously or coincidentally, the ability of the pump group to conform to a performance plan of a pumping profile may be compromised.
Generally, if the pumps of a pump group are operated to meet two criteria described below, coincidental occurrences of pressure pulsations attributable to multiple plungers providing pressure pulses simultaneously can be prevented. First, the pumps may be operated so that the pumps each provide pressure pulsations at substantially the same frequency. In other words, each of the pumps may be operated to provide the same number of pressure pulsations per unit of time. Second, the pumps may be operated to ensure that the pressure pulsations of the pump group occur so that the pressure pulsations are alternatingly attributable to the pumps. In other words, a first pressure pulsation may be caused by a first pump, the following second pressure pulsation may be caused by a second pump, and the following third pressure pulsation may be caused by the first pump. Finally, the above operation may be further optimized by ensuring substantially equal time periods between adjacent pressure pulsations in time. For example, the time between the above-described first and second pressure pulsations may be substantially equal to the time between the above-described second and third pressure pulsations. If the two pumps are operated in the above-described manner, the pressure pulsations generated by the pump group will not coincide, thereby preventing undesirable higher pressures that would be attributable to the additive effects of coincidental pressure pulsations. It will be appreciated that controlling the previously described pump group 121 according to an equal phase angle distribution inherently achieves prevention of coincidental pressure pulsations.
In the case of a pump group comprising a Triplex pump and a Quintuplex pump, both pumps may generate the same pressure pulse frequencies and the same flow frequencies. As such, the pressure pulsations generated by the pumps may be managed and/or controlled to be time shifted to ensure that pressure pulsations of the pumps do not occur substantially simultaneously. Such management of the relative pressure pulsation timing of the different pumps may be referred to as relative pulse phase control. In some embodiments, the phase between pulses may be controlled by determining the time of a pressure pulsation caused by a first pump and by thereafter maintaining a second pump with a fixed time delay between the pressure pulsations caused by the second pump and the pressure pulsations caused by the first pump. The time delay corresponds to the maintenance of a phase shift between the pressure pulsations of the first pump and the pressure pulsations of the second pump.
Referring now to
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Referring now to
When operating pumps having different numbers of plungers, the pumps speeds to avoid may be avoided by preventing the speed of the pump with the larger number of plungers (e.g., Quintuplex pump) from being equal to any multiple of the number of plungers (e.g., three) in the pump with fewer plungers (e.g., Triplex) divided by the number of plungers (e.g., five) in the pump with more plungers (e.g., Quintuplex). In other words, with respect to a pump group comprising a Triplex pump and a Quintuplex pump, in phase operation of the pumps may be avoided by ensuring that the crankshaft speed of the Quintuplex pump is not ⅗ of the crankshaft speed of the Triplex pump, or any whole unit multiple thereof. Nonetheless, if the pumps are operated at the above-described undesirable speed ratios, phase shifting the pressure pulsation occurrences between the two pumps may be used minimize potential additive effects of coincidental pressure pulsations.
Referring to
Referring now to
The above describes systems and method for effectively controlling pump groups comprising pumps having the same number of plunger and pump groups comprising different numbers of plungers. Specifically, the pump groups comprising pumps with the same number of plungers may be controlled by monitoring and or controlling the pump group according to an equal phase angle distribution through the establishment of equal phase angle separation between the total number of plungers. However, the pump groups comprising pumps having different numbers of plungers and the pump groups comprising pumps having equal numbers of plungers may be controlled by monitoring and/or controlling the pressure pulsation timing of the various pumps to avoid coincidence of pressure pulsations and/or to evenly spread the pressure pulsations generated by the pump group over time. It will be appreciated that each of the above types of pump groups are therefore monitored and/or controlled to prevent or minimize pressure pulsation overlap and/or coincidence and that various pumping parameters may be used to control phase sensitive combined flowrate operational characteristics of the respective pump groups. It will further be appreciated that the systems and method of controlling the pump groups comprising pumps having different numbers of plungers may be used to control pump groups having pumps with the same number of plungers. Similarly, in some embodiments, the systems and methods of controlling the pump groups comprising pumps having the same number of plungers may be used to control pump groups having pumps with different numbers of plungers.
In some embodiments, the wellbore servicing system 100 may be operated to provide an improved conformance to a phase sensitive combined pump effect operational characteristic. For example, where the wellbore servicing system 100 is tasked with performing according to the pumping profile 200, it may be advantageous to monitor and/or control a phase angle of one or more plungers 508 and/or pumps 120 to limit, reduce, and/or eliminate in-phase operations of plungers 508 and or pumps 120, thereby increasing conformance to the pumping profile 200. For instance, for the wellbore servicing system 100 to more closely conform to the performance plan 202, the wellbore servicing system 100 may first select a first pump 120′ and operate the first pump 120′ according to a first pumping parameter value. For example, the main controller 140 may select the first pump 120′ and send a signal to the first pump 120′ via the pump control input 138′ so that the first pump 120′ operates at an output flowrate of 5 barrels per minute. The signal sent through the pump control input 138′ may represent a desired speed of the pump 120′ and/or a desired number of rotations per minute of crankshaft 506′.
The main controller 140 may monitor and/or otherwise manage the output flowrate of the pump 120′ using feedback from the sensor 136′. With the first pump 120′ operating at the desired flowrate of 10 barrels per minute, the main controller 140 may calculate that between the second pump 120″ the third pump 120′″, another 10 barrels per minute of output flowrate is necessary to meet the demands of pumping profile 200. Accordingly, the main controller 140 may select the second pump 120″ third pump 120′″ to each have output flowrates of 5 barrels per minute such that the combined total pump group 121 flowrate is substantially equal to the required 20 barrels per minute dictated by the pumping profile 200. To increase conformance to the pumping profile 200, the main controller 140 may monitor and/or select a phase angle for plungers 508′ of the first pump 120′ and thereafter monitor and/or select a phase angle for plungers 508″ of second pump 120″ as well as monitoring and/or selecting a phase angle for plungers 508′″ of the third pump 120′″ in a manner calculated to reduce and/or minimize in-phase operation amongst the various plungers 508.
It will be appreciated that such selection and management and/or adjustment of a phase angles for plungers 508″, 508′″ relative to the phase angle of plungers 508′ may, in some embodiments, be accomplished by momentarily increasing or decreasing a speeds of the pumps 120″, 120′″ and others. In that manner, the momentary increase or decrease in speed of pumps 120″, 120′″ can be managed to result in known and/or desired phase angle adjustments for plungers 508″, 508′″ relative to the phase angle of the plungers 508′. By reducing in-phase operation amongst the various plungers 508, phase sensitive combined pump effect operational characteristics exhibit less variation from and greater conformance to the pumping profile 200.
It will be appreciated that because each of the above-described pumps 120′, 120″, and 120′″ each comprise the same number of plungers and each comprise plungers having fixed relative angular offsets to the other plungers of the same pump, the pumps 120′, 120″, and 120′″ themselves may be conceptualized as having a single angular value. In other words, for example, a first plunger of pump 120′ may serve to indicate the overall phase angle of the pump 120′. In a similar manner, substantially similar first plungers of pumps 120″, 120′″ may serve to indicate the overall phase angle of the pumps 120″, 120′″, respectively. In using such a convention of overall pump phase angle definition, the pumps 120′, 120″, and 120′″ may be controlled to be out of phase with each other by monitoring and/or controlling only the similar first plungers of the pumps. Such a convention of controlling the pumps is enabled by the pumps each having the same number of plungers and the plungers of each of the pumps being equally angularly offset as described above.
It will further be appreciated that in alternative embodiments, pumps may comprise plungers and related mechanisms that allow selective adjustment of the location of plungers along the stroke path of the plunger relative to the crankshaft that otherwise normally moves the plunger along the stroke path. In other words, alternative embodiments may comprise plungers that can be individually adjusted relative to the crankshaft and/or relative to other plungers within the same pump. Such flexibility in selectively adjusting the phase angle of individual plungers may be used to control relative phase angles between plungers and pumps to reduce in phase operation amongst the various plungers and/or pumps, thereby enabling less variation in phase sensitive combined pump effect operational characteristics and stricter adherence to a performance plan of a pumping profile.
In some other embodiments, the wellbore servicing system 100 may be operated to provide an improved conformance to a performance plan that dictates target values for a phase sensitive combined pump effect operational characteristic. For example, to prevent in-phase operation of plungers 508 and/or pumps 120, the main controller 140 may directly manage speeds of the plungers 508 and/or pumps 120. More specifically, since operating plungers 508 and/or pumps 120 at substantially different speeds acts to prevent and/or minimize prolonged in-phase operation of the plungers 508 and/or pumps 120, the main controller 140 may be configured to provide different operating speeds of plungers 508 and/or pumps 120. In some embodiments, the main controller 140 may calculate appropriate speeds for the plungers 508 and/or pumps 120 so that in-phase operation is reduced, minimized, and/or eliminated while still allowing the pumps 120 to provide the phase sensitive combined pump effect operational characteristic value required by the pumping profile 200. It will be appreciated that the main controller 140 may by configured to prevent operation of plungers 508 and/or pumps 120 at speeds representing harmonic intervals of the speeds of other plungers 508 and/or pumps 120 (e.g., speeds that are substantially ½, ¼, ⅛, 1/16, etc. of another operating speed). While in those embodiments, plungers 508 and/or pumps 120 may be managed to operate at substantially constant speeds, in other embodiments, one or more plungers 508 and/or pumps 120 may be managed by the main controller 140 to be operated with a rate of change of speed (e.g., an inherent or built-in drift in speed). While an example is provided below that embodies a linear rate of change of speed for plungers 508 and/or pumps 120, this disclosure expressly contemplates the main controller 140 managing one or more plungers 508 and/or pumps 120 to have a non-linear rate of change of speed. As previously noted, when running pumps with different numbers of plungers, the speeds can be different yet still be in phase. Most generally, a total number of plunger pulsations are controlled to be at different speeds while substantially restricting occurrences of the plunger pulsations being at multiples of the speeds of other plunger pulsations.
It will be appreciated that selection of a speed for one or more plungers 508 and/or one or more pumps 120 may be at least partially randomly selected. Similarly, it will be appreciated that the selection of a rate of change of speed for one or more plungers 508 and/or one or more pumps 120 may be at least partially randomly selected. Still further, it will be appreciated that speeds and/or rates of change of speeds may be selected according to a predetermined time schedule, or alternatively, may be selected according to an at least partially random time schedule.
Similarly, while the above-described control of plungers 508 and/or pumps 120 refers to controlling a speed, other pump parameters described herein may be managed to have linear and/or non-linear rates of change while still providing a phase sensitive combined pump effect operational characteristic performance that exhibits less transient variation from the performance plan 202 of the pumping profile 200.
It will also be appreciated that main controller 140 may be configured as a linear or non-linear controller. Without being limited to these controller types, linear controllers may comprise proportional, proportional-integral and/or proportional-integral-derivative controllers. Without being limited to these controller types, non-linear controllers may comprise fuzzy logic, sliding mode, artificial intelligence based controllers. The controller is programmed to (1) sense information about the operation of pumps 120 and/or sense information about a phase sensitive combined pump effect operational characteristic value and (2) based on the sensed information, control the plungers 508 and/or pumps 120 according to a set of control parameters (e.g., by altering one or more pump parameters such as speed, etc.).
Referring now to
In other embodiments, the phase control system 518 may be used to control a speed of the pump 500, a flowrate of the pump 500, or any other operational characteristic of the pump 500 that may be deduced and/or subsequently controlled by monitoring and/or managing the speed of the crankshaft 506 as reported by sensor 520. Of course, in alternative embodiments, the phase control system 518 may be self-contained and may comprise other systems or components for managing, monitoring, reporting, and/or altering a phase and/or speed of the plunger 508. It will be appreciated that while pump 500 comprises only one phase control system 518, each of the other two plungers of the pump 500 may be associated with an independent phase control system 518. It will further be appreciated that instead of a sensor 520 that senses crankshaft 506 information, in alternative embodiments, a sensor may be provided in the phase control system 518 that directly or indirectly measures and/or reports the location and/or phase of the plunger 508, for example as shown in
Referring now to
Referring now to
It will be appreciated that any of the above combinations of sensors, controllers, and/or pump control inputs may be configured to work together according to any number of feedback control system schemes. For example, the phase control systems 518 may be configured as a proportional-integral-derivative control system (PID controller), thereby allowing selective control over the speed, location, phase, and/or direction of plungers 508. It will further be appreciated that the control principles disclosed herein may be implemented to control, one or more plungers individually, one or more pumps 120 individually, one or more pump groups 121, or any combination thereof. Allowing such control provides complete control over all plunger speed, location, direction, and/or phase within a wellbore servicing system. Further, any combination of the disclosed pumps, sensors, controllers, and/or pump control inputs may be used to control a pump group according to an equal phase angle distribution and/or by controlling relative pulse phase between pressure pulses.
Further, it will be appreciated that while pumps 120 are disclosed as positive displacement pumps generally having fixed plunger 508 locations and/or phases relative to the crankshafts 506, alternative embodiments of pumps may comprise mechanical systems for adjusting plunger 508 position relative to a crankshaft 506. For example, systems may be incorporated that alter a stroke length of a plunger and/or allow controlled slippage in the linkages between the plunger 508 and the crankshaft 506. Such systems may be provided with sensors and/or other control inputs which further allow control over relative phase angles between various plungers, even where the plungers are within a single positive displacement pump and/or coupled to a common crankshaft. It will further be appreciated that alternative embodiments may comprise intensifier pumps or hydraulic drive pumps suitable for individually adjusting plunger phase angles. Still further, it will be appreciated that any of the above-described sensors, controllers, and/or pump control inputs may be used to control pump group performance of pump groups having pumps with different numbers of plungers.
It will be appreciated that the wellbore servicing systems and the methods disclosed herein can be used for any purpose. In an embodiment, the wellbore servicing systems and methods disclosed herein are used to service a wellbore that penetrates a subterranean formation by pumping a wellbore servicing fluid into the wellbore and/or subterranean formation. As used herein, a “servicing fluid” refers to a fluid used to drill, complete, work over, fracture, repair, or in any way prepare a well bore for the recovery of materials residing in a subterranean formation penetrated by the well bore. It is to be understood that “subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water. Examples of servicing fluids include, but are not limited to, cement slurries, drilling fluids or muds, spacer fluids, fracturing fluids or completion fluids, and gravel pack fluids, all of which are well known in the art. Without limitation, servicing the well bore includes: positioning the wellbore servicing composition in the wellbore to isolate the subterranean formation from a portion of the wellbore; to support a conduit in the wellbore; to plug a void or crack in the conduit; to plug a void or crack in a cement sheath disposed in an annulus of the wellbore; to plug a perforation; to plug an opening between the cement sheath and the conduit; to prevent the loss of aqueous or nonaqueous drilling fluids into loss circulation zones such as a void, vugular zone, or fracture; to plug a well for abandonment purposes; to divert treatment fluids; and to seal an annulus between the wellbore and an expandable pipe or pipe string. In another embodiment, the wellbore servicing systems and methods may be employed in well completion operations such as primary and secondary cementing operation to isolate the subterranean formation from a different portion of the wellbore.
Referring now to
Still referring to
The plot 304 demonstrates that this embodiment can conform to a desired performance plan (e.g., a desired combined pump flowrate of 23 barrels per minute) within only about 2-3%, alternatively about 2.1%, or alternatively about 2.17% transient variation from the desired performance plan value. The plot 302 shows about a 28% transient variation from the desired performance plan. Accordingly, this embodiment demonstrates that a transient variation from a desired performance plan may be reduced by about 80-90%, alternatively by about 90%, alternatively by about 92%, or alternatively by about 92.2%, or alternatively by about 92.25% simply by operating the system out of phase in the manner described rather than in-phase. Accordingly, this example shows that by altering a pumping parameter (in this case a phase angle of a plunger) a resultant phase sensitive combined pump effect operational characteristic (in this case a combined pump group flowrate) can be caused to conform more closely to a pumping profile.
Referring now to
Still referring to
The plot 404 demonstrates that this embodiment can conform to a desired performance plan (e.g., a desired pump inlet pressure of 50 psi) within only about 30-50% or alternatively about 40% transient variation from the desired performance plan value. The plot 402 shows about a 120% transient variation from the desired performance plan. Accordingly, this embodiment demonstrates that a transient variation from a desired performance plan may be reduced by about 60-70%, alternatively by about 66%, or alternatively by about 66.6% simply by operating the system out of phase in the manner described rather than in-phase. Accordingly, this example shows that by altering a pumping parameter (in this case a phase angle of a plunger) a resultant phase sensitive combined pump effect operational characteristic (in this case a combined pump group inlet pressure) can be caused to conform more closely to a pumping profile.
Further, the higher rate of change illustrated by plots 302 and 402 indicate that higher boost pump pressure requirement at a blender of a wellbore servicing system may be required to prevent the pumps from cavitating as compared to a lower boost pump pressure requirement when the pumps are operated in-phase as represented by plots 304 and 404. It will be appreciated that this difference in boost pump pressure requirement is ruled by the associated pressure drop over the hoses connected to the suction which can be expressed as
This relationship clearly indicates that an increase in the rate of change of flowrate results in an increase in pressure drop over the length of the suction hose.
Referring now to
At the beginning of operation of the first and second pumps, the pumps were substantially in-phase with each other. This in phase operation resulted in an initial transient flowrate variation of about 6.5 barrels per minute at about second 0. However, considering that the plungers of the different pumps are traveling through their strokes at different rates, the phase difference between the first pump plungers and the second pump plungers gradually changes until after about 2.5 seconds of operation, the plungers of the two pumps are substantially out of phase with each other by about 180 degrees. This out of phase operation results in a reduced transient flowrate variation of about 3 barrels per minute at about second 2.5. Between about second 2.5 and about second 5, the phase difference between the first pump plungers and the second pump plungers gradually changes until the first pump plungers and the second pump plungers are substantially in-phase, again resulting in the larger 6.5 barrels per minute transient flowrate variation. This example demonstrates that when conformance to a performance plan requires that flowrate variations be minimized, it is clear that time spent operating the two pumps in the in-phase arrangement is less beneficial due to larger variations in flowrate. Accordingly, this example shows that a pumping parameter (in this case a speed of a pump) can affect a resultant phase sensitive combined pump effect operational characteristic (in this case a combined pump group flowrate).
Referring now to
At the start of operation, a first pump 706, a second pump 708, and a third pump 710 operate at about 10, 5, and 5 barrels per minute, respectively, totaling the required 20 barrels per minute required by the performance plan 702. However, unlike the previously discussed embodiments, the flowrate and/or speed of the first, second, and third pumps 706, 708, 710 are operated with substantially constantly changing flowrates and/or speeds. In this embodiment, during about the first 50 minute of operation, the first, second, and third pumps 706, 708, 710 gradually change flowrate and/or speed until they operate at about 5, 7, and 8 barrels per minute, respectively. In this embodiment, the pumps 706, 708, 710 reach the new operating flowrates and/or speeds through linear progressions and substantially maintain the required 20 barrels per minute of the performance plan 702. From about minute 50 of operation to about minute 100 of operation, the first, second, and third pumps 706, 708, 710 gradually change flowrate and/or speed until they operate at about 10, 5, and 5 barrels per minute, respectively. Next, from about minute 100 to about minute 110 of operation, the first, second, and third pumps 706, 708, 710 gradually change flowrate and/or speed until they operate at about 10, 10, and 10 barrels per minute, respectively, thereby meeting the 30 barrels per minute flowrate required by the performance plan 702.
It will be appreciated that the pumps 706, 708, 710 even conformed to providing the sharply increasing flowrate required by performance plan 702 between about minutes 100 and 110 of operation. From about minute 110 to about minute 150 of operation, the second and third pumps 708, 710 gradually change flowrate and/or speed until they operated at about 12 and 8 barrels per minute, respectively, while the flowrate and/or speed of the first pump remained at about 10 barrels per minute. Finally, from about minute 150 to about minute 200 of operation, the first, second, and third pumps 706, 708, 710 gradually changed flowrate and/or speed until they operate at about 8, 12, and 10 barrels per minute, respectively, and then cease operation. While operating the first, second, and third pumps 706, 708, 710 may induce some decreased conformance to the performance plan 702 for a combined pump effect operational characteristic, i.e., the combined flowrate 712 of pumps 706, 708, 710, cyclical occurrences shown in
While pumps 706, 708, 710 may be operated according to a pumping profile having a performance plan such as performance plan 702, other methods of operating the pumps 706, 708, 710 may be used in alternative embodiments. For example, in one alternative embodiment, pumps 706, 708, 710 may be operated, managed, and/or controlled by a linear or non-linear controller that uses logical parameters to maintain the flowrate, speed, and/or other control of the pumps 706, 708, 710 so that undesirably high non-conformance to a pumping profile is avoided. For example, a controller may be programmed to control the pumps 706, 708, 710 so that if an undesirable degree of variation from a pumping profile occurs, the flowrates and/or speeds of the pumps 706, 708, 710 are either immediately set to new values and/or are set to operate according to a new rate of change of flowrate.
In another alternative embodiment, pumps 706, 708, 710 may be periodically and/or randomly set to new values and/or set to operate according to a new rate of change of flowrate. In this embodiment, the controller does not wait to sense feedback that induces a change in pump operation, but rather, is programmed to change pump operation according to randomly generated value for at least one of the three pump flowrates. Of course, where one or more pump flowrates and/or speeds is randomly determined (within a range of achievable values), at least the last remaining undefined pump flowrate and/or speed will be restricted to those values that allow the combined total flowrate and/or speed to conform to a performance plan of a pumping profile. While operating the first, second, and third pumps 706, 708, 710 in this manner may induce some decreased conformance to a performance plan for a combined pump effect operational characteristic, i.e., the combined flowrate of pumps 706, 708, 710, the cyclical occurrences shown in
At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention. The discussion of a reference in the disclosure is not an admission that it is prior art, especially any reference that has a publication date after the priority date of this application. The disclosure of all patents, patent applications, and publications cited in the disclosure are hereby incorporated by reference, to the extent that they provide exemplary, procedural or other details supplementary to the disclosure.
| Number | Name | Date | Kind |
|---|---|---|---|
| 6742441 | Surjaatmadja et al. | Jun 2004 | B1 |
| 7409901 | Lucas et al. | Aug 2008 | B2 |
| 7563076 | Brunet et al. | Jul 2009 | B2 |
| Number | Date | Country | |
|---|---|---|---|
| 20100310384 A1 | Dec 2010 | US |
