Set point control for fixed speed engine driven fracking pumps

Abstract

A system for injecting fracking fluid into a wellbore includes fracking pumps each having a fixed speed engine driven power train. The system further includes a controller configured to determine a combination of flow rate setpoints of the fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps, and transmit the flow rate setpoints to the fracking pumps. The fracking pumps are configured to inject fracking fluid into the wellbore according to the pump rate setpoints.

Description

BACKGROUND

[0001] Natural gas spark ignited engines may be used in direct mechanical drive application such as power for driving a fracturing pump. Some engines of this type are of a fixed speed (e.g., isochronous governor) control, meaning that only a single operating rotational speed is available. To achieve more than one operating speed, a multi-gear transmission may be used, which can provide different, but discreet, output shaft speeds which are determined by the gear ratios in the transmission and the driving single speed available from the engine. When one or more of the fixed speed / multi-gear transmission combinations are used in a pumping operation, selection and control of the proper gear and number of pumps can be challenging. For example, complexity of the pumping system, numerosity of pumps, and changing conditions may make it difficult to achieve a desired flow rate with a spread of fixed speed engines. The system and method of the present disclosure may address one or more of these issues.BRIEF DESCRIPTION OF THE DRAWINGS

[0002] For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.

[0003] FIG. 1 is a schematic diagram of an exemplary wellbore servicing system, according to an embodiment of the present disclosure;

[0004] FIG. 2 is a cut-away view of an exemplary hydraulic fracking pump, according to an embodiment;

[0005] FIG. 3 is a schematic diagram of an exemplary hydraulic fracking system, according to an embodiment;

[0006] FIG. 4 is a schematic diagram of an exemplary wellbore servicing system that includes clean side fracking pumps and dirty side fracking pumps;

[0007] FIG. 5 is a schematic diagram of a wellbore servicing system that includes pumps having fixed speed engine driven power trains and pumps having variable speed engine or motor driven power trains; and

[0008] FIG. 6 is a flow diagram of a method for injecting fracking fluid into a wellbore.DETAILED DESCRIPTION

[0009] It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For brevity, well-known steps, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.

[0010] A system and method for controlling hydraulic fracturing pumps having a fixed-speed power train is provided. A control scheme may be used (e.g., executed by a controller) to determine when and how to select the number of pumps to employ and which gears to utilize. This can achieve a greatly variable total flow rate. This can advantageously allow use of fixed-speed engine driven power trains in variable flow rate applications. A supervisory control algorithm (e.g., executed by the controller) may optimally select from a given number of pumping units and discreet individual pump gear ratios to provide a desired total job discharge rate or a total change desired in discharge rate. This can enable use of 100% natural gas fixed speed engines for mechanical (direct) drive pumping where variability in output is required. This may present advantages in terms of both cost and pump availability.

[0011] The controller may select pumps and set points according to an algorithm. The selection process may be explained mathematically. For example, let there be N pumps with a constant-speed engine in a hydraulic fracturing spread, and let the maximum allowed gear be M. The maximum allowed gear may be determined by operating conditions (e.g., expected treating pressure) or by operator's experience. Let the flow rate at i-th gear of j-th pump be qi,j, i=1, . . . , M, j=1, . . . , N. For j-th pump, the chosen pump rate setpoint Qj can only be in the set {0, q1,j, q2,j, . . . , qM,j}. That is, Qj∈{0, q1,j, q2,j, . . . , qM,j}.

[0012] The controller may execute an algorithm according to the following steps: (1) Given a desired total pump rate Qtotal, the supervisory control algorithm determines at least one combination of Qj such that the sum of pump rates meets the desired total pump rate Qtotal; (2) if the number of combinations of Qj is more than one, then the control algorithm chooses one combination; and (3) the chosen rate setpoints are sent to individual pumps which performs necessary adjustments (e.g., gear shift) to track their setpoints. The following system of equations may be solved to determine the combination(s) of Qj in Step 1:Qj=∑izi,j⁢qi,j,j=1,… ,N(1)∑izi,j≤1,j=1,… ,N(2)zi,j=0⁢ or⁢ 1(3)∑jQj=Qtotal(4)where Qj is a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps. Equation 3 states that each available rate (e.g., based on gear) can be either chosen once or not chosen, while Equation 2 restricts the total number of choices for a specific pump can be no more than 1. The chosen rate for j-th pump may be calculated in Equation 1, and the sum of the chosen rates should be equal to (or approximately equal to and / or within a tolerance of) the desired rate as shown in Equation 4. The systems of equations may be solved, for example, by a greedy algorithm, heuristics, combinatorial optimization, search (e.g., breath-first search, depth-first search, brute-force search), or trial-and-error approach. It may not be required to obtain all possible combinations (or equivalently, all solutions to the system of equations) in order to achieve an acceptable total flow rate.In embodiments in which all pumps have the same engine, transmission, and fluid end, the set {0, q1,j, q2,j, . . . , qM,j} are the same for all j=1, . . . , N. This may be denoted as q1,j=q2,j= . . . =qM,j=qj. In this case, the problem can be reduced by solving the following Diophantine equation:N1⁢q1+N2⁢q2+⋯+Nj⁢qj=Qtotal(5)where Nj indicates how many pumps are using rate qj (i.e., shifted into j-th gear). The controller may solve for all possible combinations in polynomial time. Next, the controller may discard any combinations that requires a greater number of pumps than is available, i.e., ΣNj>N. Then, the controller may choose one combination and assign those rates to pumps. For example, let Qtotal=10 bpm, the pumps have two gears available with q1=2 bpm and q2=3 bpm, and there are five pumps available. In this example, solutions to Equation 5 are: (1) N1=5, N2=0; and (2) N1=2, N2=2. The controller may select the second solution considering that it uses fewer pumps. Then, controller may assign two pumps a rate setpoints q1=2 bpm, assign two pumps a rate setpoint of q2=3 bpm, and assign one pump to be idled. In some embodiments, selection of the combinations may be based on rules or may be selected to minimize a cost function. For example, selection criterion may be used to choose the combination using the least number of pumps. In some embodiments, selection of the combinations may be based on current operating points of pumps. For example, if all pumps are currently in Gear 1 (e.g., the rate being 2 bpm), the first solution may be chosen because there would be no gear shift required.In some embodiments, selection of the combinations may be based on pump dynamics in combination with current operating points of the pumps. A combination with least impact to the spread rate may be selected. Each gear shift may take two seconds regardless of upshift or downshift. In an example, there are two combinations available: (1) shift one pump from 2nd gear to 4th gear and shift one pump from 5th gear to 3rd gear; and (2) shift one pump from 2nd gear to 5th gear and shift one pump from 3rd gear to 1st gear. In this example, the first solution may be selected because the net change in gear is 0, while the net change in gear in the second solution is 1. Fewer net changes in gear shifts may generally indicate less impact to the spread rate, and the controller may select the combination on this basis.In some embodiments, the criteria for selection of the combinations may expedite Step 1 by eliminating possible combinations that are known to be less favorable. For example, in the example involving Equation 5 in which the solution is optimized for least number of pumps, if a brute force search method is used to list all the combinations and a combination has already been obtained for N1=2 and N2=3 assuming only two gears are allowed, then any combinations with N1≥6 may be ignored because regardless of the value of N2, the sum of N1 and N2 may be guaranteed to be greater than the sum of the current combination already obtained (N1+N2=5).

[0016] In some embodiments, given the criteria for selection of the combination, the processor may stop finding new combinations if there is at least one combination known to already meet the criteria. For example, if a pre-determined criteria says that the total number of pumps being used is in less than or equal to 5, then after the processor finds a solution N1=2 and N2=3, the processor may cease searching for new combinations.

[0017] In some embodiments, Step 1 (e.g., finding all the combinations) and Step 2 (e.g., selection of combinations) can be combined in one step by solving the following optimization problem:min⁢ ∑ i,j⁢wij⁢zij⁢qij(6)subject to Equations 1 through 4, where wij is the cost for the j-th pump to select the i-th gear. The cost function or cost term wij may be according to any of the examples described herein. The optimization problem above may be solved by the Hungarian algorithm, for example. In some embodiments, there may be a reward associated with each gear selection, and the goal of optimization may be to maximize total rewards. In such cases, the cost term wij may be the negative of reward if i-th gear is selected for the j-th pump.In some embodiments, for the optimization problem, one may use a heuristic based approach to find an optimal or suboptimal solution. For example, if one solution is found that satisfies all the constraints that generate a cost function value lower than a threshold, the search for an optimal or suboptimal solution may be stopped early.

[0019] In some embodiments, in Step 1, the sum of pump rates meets the desired total pump rate when the sum of pump rates EQ, is as close to Qtotal as possible while ΣQj≤Qtotal. In other embodiments, the controller may determine that the sum of pump rates meets the desired total pump rate when Qtotal−ΣQj is within a tolerance of [Qtol,min, Qtol,max].

[0020] In some embodiments, for example, in a split-flow operation, Step 1 may be applied to the clean side and the dirty side independently. That is, the controller may solve the system of equations to generate combinations of set points for the clean side and solve the system of equations to generate combinations of set points for the dirty side. In Step 2, combinations of both sides may be considered as a whole. That is, the controller may select a combination of the clean side and a combination of the dirty side from the generated combinations together (e.g., considering the combined flow rate output of both) according to any of the criteria disclosed herein.

[0021] In some embodiments, pumps with fixed-speed engines may be used in conjunction with one or more variable-speed engines. The rates of the variable-speed engine(s) may be considered by revising the total pump rate in Step 1 according to: Qtotal,fix=Qtotal−Qtotal,var, where Qtotal, var is the total rate of pumps with variable-speed engines, and Qtotal, fix replaces Qtotal in Step 1. Since Qtotal,var may be continuous (or piecewise continuous) in value, a gradient-based method can be applied if a cost function is used to determine the combination of rates of pumps with fixed-speed engines. That is, an optimized solution to the cost function may be obtained by a gradient-based method. Alternatively, pumps with variable-speed engines may be used as trim pumps, e.g., Qtotal, var can be varied by manipulating rates of variable-speed engine pumps without shifting gears of these pumps. In some embodiments, the controller may determine a combination of gears of the fixed-speed engine driven pumps which most closely approximates and undershoots the desired total flow rate, then the controller may determine a rate of flow of one or more variable-speed engine driven pumps to add to the flow of the fixed-speed engine driven pumps to even more closely approximate the desired flow rate.

[0022] Referring to FIG. 1, an exemplary wellbore servicing system 100 is shown. The wellbore servicing system 100 may be configured for fracturing wells in low-permeability reservoirs, among other wellbore servicing jobs. In fracturing operations, wellbore servicing fluids, such as particle laden fluids, may be pumped at high pressure downhole into a wellbore. The wellbore servicing system 100 may introduce particle laden fluids into a portion of a subterranean hydrocarbon formation at a sufficient pressure and velocity to form and extend fractures within the subterranean hydrocarbon formation. Proppants, such as grains of sand, may be mixed with the wellbore servicing fluid to keep the fractures open so that hydrocarbons may be produced from the subterranean hydrocarbon formation and flow into the wellbore. Hydraulic fracturing may create high-conductivity fluid communication between the wellbore and the subterranean hydrocarbon formation.

[0023] The wellbore servicing system 100 may include a blender 114 that is coupled to a manifold 118 (e.g., wellbore services manifold trailer) via a flowline or flowlines 116. The wellbore services manifold trailer may comprise a truck and / or trailer comprising one or more manifolds for receiving, organizing, and / or distributing wellbore servicing fluids during wellbore servicing operations. The manifold 118 may be coupled via outlet flowlines 122 and inlet flowlines 124 to pumps 120 (e.g., pumps having fixed speed engine driven power trains and / or pumps having variable speed engine or motor driven power trains). Outlet flowlines 122 may supply fluid to the pumps 120 from the manifold 118. Inlet flowlines 124 may supply fluid to the manifold 118 from the pumps 120. The manifold 118 may have manifold outlets from which wellbore servicing fluids flow to a wellhead 132 via one or more flowlines 134. The blender 114 may mix solid and fluid components to achieve a well-blended wellbore servicing fluid. Sand or proppant 102, water or other carrier fluid 106, and additives 110 may be fed into the blender 114 via feedlines 104, 108, and 112, respectively.

[0024] The wellbore servicing system 100 may 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 may further comprise 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. Operational information about the pumps 120 may be communicated to a controller 140 by the sensors 136. Further, the pump control inputs 138 may be configured to receive signals, instructions, orders, states, and / or data sufficient to alter, vary, and / or maintain an operation of the pumps 120. The controller 140, sensors 136, and pump control inputs 138 may be configured so that each pump 120 and / or individual components of the pumps 120 are independently monitored and 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 may further comprise a combined pump output sensor 142. The combined pump output sensor 142 may be associated with a flowline 134 that carries a fluid flow that results from the combined pumping efforts of all pumps 120. The combined pump output sensor 142 may be configured to monitor and / or report combined pump effect operational characteristic values to the control system 140. Alternatively, the combined output can be obtained by summing the output from individual sensors 136.

[0025] Referring to FIG. 2, the pump 120 may comprise a power end 502 and a fluid end 504 attached to the power end 502. The power end 502 may comprise a crankshaft 506 that reciprocates a plunger 508 within a bore 516 of the fluid end 504. The fluid end 504 may further comprise a compression chamber 510 into which fluid flows through a suction valve 512. Fluid may be pumped out of the compression chamber 510 through a discharge valve 514 as the plunger 508 is moved toward the compression chamber 510. The crankshaft 506 may be mechanically coupled to a gearbox 3, which is shown schematically in FIG. 3.

[0026] Referring to FIG. 3, an exemplary pumping system 1 for hydraulic fracturing is shown. The pumping system 1 may comprise a pump 120; a gearbox 3 mechanically coupled to the pump 120; a driveline 4 mechanically coupled to the gearbox 3; and a power unit 5 mechanically coupled to the driveline 4. The power unit 5 may be a natural gas powered engine. The driveline 4 may rotate at a fixed speed. That is, the natural gas powered engine may be configured to turn the driveline 4 at only one rotational velocity. Stated another way, the natural gas engine may have only two modes of operation: idle and drive, and in the drive mode, the driveline 4 is driven at only one rotational velocity. In other embodiments, the power unit 5 may be a diesel engine or a motor. In such embodiments, the power unit 5 may be variable speed (e.g., the driveline 4 may be driven at multiple speeds).

[0027] Referring to FIGS. 1 and 3, a system 100 for injecting fracking fluid into a wellbore may include fracking pumps 120 each comprising a fixed speed engine driven power train 6 (e.g., the power unit 5 is configured to turn a driveline4 of the power train 6 (which includes the gearbox 3) at a constant speed, e.g., the power unit 5 is a natural gas driven engine that has / consists of only two modes: a constant speed mode and an idle mode); and a controller 140 configured to determine a combination of flow rate setpoints (e.g., set points that are expected to result in certain flow rate outputs of the pumps 120, the flow rates being based on which gear in the gearbox 3 of the pumps 120 is selected, e.g., the setpoints may be an overall flow rate command or a gear selection command) of the fracking pumps corresponding to gears (e.g., of the gearbox 3) of the fracking pumps 120 such that a sum of the flow rate setpoints (e.g., each of the flow rate setpoints of the pumps being added together) meets a desired total flow rate of the fracking pumps 120 (e.g., the desired total flow rate may be set by an operator or automatically generated); and transmit the flow rate setpoints to the fracking pumps (e.g., via wired or wireless communication). The fracking pumps 120 may be configured to inject fracking fluid into the wellbore / wellhead 132 according to the pump rate setpoints. That is, the fracking pumps 120 may shift gears according to the setpoints to output a combined flow rate that better approximates the desired flow rate.

[0028] The setpoints may include a zero setpoint or an idle setpoint for one or more of the pumps. The controller 140 may be further configured to transmit the flow rate setpoints by transmitting one or more commands to shift one or more of the gears (e.g., in the gearbox 3 of one or more of the pumps 120) to achieve a state of the gears that corresponds to the combination of flow rate setpoints. Of the pumps 120 that are not set to idle, each pump 120 may have a certain gear selected so that the combined output of the pumps 120 achieves or approximates the desired flow rate setpoint. The command to shift the gear(s) may be received by a unit controller of the individual pump system 1, which may then control the gearbox 3 to shift gears. The command may also include a particular timing to make the shift. For example, if multiple pumps 120 need to have gears shifted to conform with the combination of setpoints, the controller 140 may time the gear shifts to be spaced out in time, which can be advantageous in that the asynchronous gear shifting may mitigate flow disturbances during transition to the combination of setpoints.

[0029] The controller 140 may be further configured to determine a plurality of combinations of flow rate setpoints, and select the combination of flow rate set points from among the plurality of combinations of flow rate setpoints. Each of the plurality of combinations of flow rate setpoints may include a distinct combination of gears selected or a distinct combination of gears that would be selected according to the setpoints in the combination. That is, in each combination, there may be a unique combination of gear selection and / or idle selection of the respective pumps 120. In each combination, or one more of the pumps 120 may have gears selected and one or more of the pumps 120 may be set to idle. Each combination may be unique (e.g., no two combinations of the plurality of combinations are the same).

[0030] The controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints of the combination. For example, after generating the plurality of combinations of flow rate setpoints, the controller 140 may compare the current state of gears of the pumps 120 with the state of gears of each of the plurality of combinations and determine which of the plurality of combinations would require the least number of gear shifts from the current state to the particular combination. Alternatively or additionally, the controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a number of the fracking pumps 120 used. For example, some of the combinations may have a greater number of pumps set to idle than others, and the controller may select the combination that has the greatest number of pumps being set to idle. Alternately or additionally, controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a cost function. The cost function may be based on an economic cost to run the pumps 120. For example, the cost function may take into consideration efficiency and / or energy demand of the pumps depending on which gear they are in.

[0031] The selection of the combination and / or the cost function may also take into consideration equipment limitations and / or equipment health. For example, the combination may be selected in consideration of information that at least some of the equipment cannot accept full power (e.g., due to maintenance issues). The controller may use a cost function that is in terms of the amount of natural gas expected to be consumed for running a given pump in a given gear. The cost function may take into account number of shifts required and may tend to minimize the number of shifts required. The controller may select the combination having the lowest combined expected natural gas consumption rate. In some embodiments, the selection of the combination may be based on inputs from the equipment (e.g., real time data). For example, the selection may be based on data regarding pump transmission, engine, cooling systems, air cleaner restrictions, and / or lube oil level / quality. In some embodiments, the controller is configured to exclude one or more pumps in response to the controller determining that the one or more pumps would be unable to achieve a particular flow rate based on one or more inputs from the equipment. In some embodiments, the cost function takes into account pumping efficiency associated with gears of the pumps. In some embodiments, the cost function is based on efficient loading of the pumps. In some embodiments, the cost function is based on emissions associated with the set points. In some embodiments, the cost function minimizes the number of variable speed engine driven pumps used.

[0032] The controller 140 may be configured to determine the plurality of combinations of flow rate setpoints by using (e.g., solving) Equations 1-4. The equations may be solved by any suitable method. The controller 140 may be configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps. That is, the controller 140 may generate a plurality of flow rate setpoint combinations, and determine that one of them “meets” the desired flow rate because that combination yields a combined flow rate that more closely approximates the desired flow rate than any other of the generated combinations. Additionally or alternatively, the controller 140 may be configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate. For example, the controller 140 may discard combinations that are expected to yield a combined flow rate outside of the tolerance and select a combination expected to yield a combined flow rate that is inside the tolerance. If multiple combinations are expected to yield a combined flow rate that is inside the tolerance, the controller 140 may select the combination that would be expected to yield a flow rate closest to the desired flow rate and / or select the combination based on other factors, for example, the number of pumps at idle in the combination, the combination that minimizes the cost function, and / or any other suitable factors.

[0033] Referring to FIG. 4, the system 100 may include one or more clean side fracking pumps 120A and one or more dirty side fracking pumps 120B. The fracking pumps 120A, 120B may be fluidly coupled to a wellbore / wellhead 132 (e.g., via a manifold). The controller 140 may be configured to determine the desired total flow rate of the clean side fracking pumps 120A and a desired total flow rate of the dirty side fracking pumps 120B to meet a combined total flow rate of the clean side fracking pumps 120A and the dirty side fracking pumps 120B. These desired total flow rates may be based on a desired concentration of proppant to be pumped into the wellbore / wellhead 132. The controller 140 may then determine a combination of flow rate setpoints of the clean side fracking pumps 120A corresponding to gears of the clean side fracking pumps such that a sum of the flow rate setpoints of the clean side fracking pumps 120A meets the desired total flow rate of the clean side fracking pumps, and determine a combination of flow rate setpoints of the dirty side frack pumps 120B corresponding to gears of the dirty side fracking pumps 120B such that a sum of the flow rate setpoints of the dirty side fracking pumps 120B meets the desired total flow rate of the dirty side fracking pumps 120B. The determination of the combinations of flow rate setpoints can be achieved by any of the methods disclosed herein.

[0034] Referring to FIG. 5, a system 100 for injecting fracking fluid into a wellbore may include first fracking pumps 120C each comprising a fixed speed engine driven power train; and second fracking pumps 120D each comprising a variable speed engine driven power train. The first fracking pumps 120C and the second fracking pumps 120D may be fluidly coupled to a wellbore / wellhead 132. The system 100 may further include controller 140 configured to determine a combination of first flow rate setpoints of the first fracking pumps 120C corresponding to gears of the first fracking pumps 120C and a combination of second flow rate setpoints of the second fracking pumps 120D such that a sum of the first flow rate setpoints plus a sum of the second flow rate setpoints meets a desired total flow rate of the first fracking pumps 120C and the second fracking pumps 120D. For example, the controller 140 may first determine a plurality of combinations of first flow rate setpoints, select a combination from the plurality of combinations of first flow rate setpoints, then generate the plurality of second flow rate setpoints to approximate a difference between the combined flow rate of the selected combination of first flow rates and the desired flow rate, and select a combination of second flow rate setpoints from the plurality of second flow rate setpoints such that a total combined flow rate of the first combination of flow rates and the second combination of flow rates approximates the desired total flow rate. Additional methods such as using a cost function and / or minimizing the number of active pumps may be used to select the combinations.

[0035] The combination of first flow rate setpoints may be determined by any of the methods disclosed herein. The combination of second flow rate setpoints may also be determined based on gear usage but the gears may allow for continuous or piece-wise continuous possibilities for the setpoints. The controller may generate the combinations of second flow rate setpoints based on efficient engine / motor speed and gear selection combinations.

[0036] The controller 140 may transmit the first flow rate setpoints to the first fracking pumps 120C, and transmit the second flow rate setpoints to the second fracking pumps 120D. The first fracking pumps 120C may inject fracking fluid into the wellbore / wellhead 132 according to the first pump rate setpoints, and the second fracking pumps 120D may inject fracking fluid into the wellbore / wellhead 132 according to the second pump rate setpoints. In some embodiments, the first fracking pumps 120C are all natural gas driven (fixed engine speed) pumps, and the second fracking pumps 120D are diesel driven pumps, electrically driven pumps, or a combination of diesel driven pumps and electrically driven pumps. The flow rate of the electrically driven pumps may be controlled by a variable frequency drive.

[0037] Referring to FIG. 6, a method 600 for injecting fracking fluid into a wellbore may include the step 610 of determining, by a controller, a combination of flow rate setpoints of fracking pumps corresponding to gears of the fracking pumps (e.g., the flow rate setpoints could be the gear settings themselves or a flow rate setting which would require a certain gear setting) such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps (e.g., expected flow rates from each of the respective pumps having their respective flow rate setpoints when summed approximate the total desired total flow rate), wherein the fracking pumps each comprising a fixed speed engine driven power train (e.g., the engine turns a driveline at a fixed rate, e.g., the driveline speed is not adjustable, e.g., the engine is only capable of idling and running at a fixed speed); the step 620 of transmitting, by the controller, the flow rate setpoints to the fracking pumps (e.g., by wired or wireless transmission); and the step 630 of injecting, by the fracking pumps, fracking fluid into the wellbore according to the pump rate setpoints (e.g., the fracking pumps respectively receive the flow rate setpoints from the controller, and based on the flow rate setpoints, each of the fracturing pumps either has no change, increases a rate of pumping by changing gears, decreases a rate of pumping by changing gears, shifts into idle, or shifts out of idle into a particular gear).

[0038] The fracking pumps may be natural gas driven. The transmitting of the flow rate setpoints may include transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints. This may also include commanding one or more pumps to shift into idle and / or commanding one or more pumps to shift out of idle to a particular gear.

[0039] The method 600 may further include determining a plurality of combinations of flow rate setpoints, and selecting the combination of flow rate set points from among the plurality of combinations of flow rate setpoints. The plurality of combinations of flow rate setpoints may be generated according to any of the methods described herein. For example, the controller may generate multiple combinations that would achieve a flow rate within a tolerance of the desired flow rate. The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a total number of gear shifts (e.g., from the current gear configuration to the gear configuration that would occur as a result of the setpoints in the particular combination) required to achieve the flow rate setpoints. The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a number of the fracking pumps used (e.g., maximize the number of fracking pumps that would idle as a result of the setpoints in the particular combination). The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a cost function (e.g., selecting the combination that would result in least natural gas consumption or maximum profit considering natural gas expenditures and / or fracking efficiency). The determining of the plurality of combinations of flow rate setpoints may include determining the plurality of combinations of flow rate setpoints by using (e.g., solving) Equations 1-4 (e.g., using numerical methods).

[0040] The determining of the combination of flow rate setpoints may include determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with sums of other combinations of flow rate setpoints of the fracking pumps. That is, the controller may generate a plurality of combinations of flow rate setpoints and select the one that is predicted to result in the closest flow rate to the desired flow rate. This prediction may be based on quality of the natural gas. The determining and / or the selecting of the combination of flow rate setpoints may include determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0041] The method 600 may further include determining the desired total flow rate of clean side fracking pumps and a desired total flow rate of dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps (e.g., also to achieve a desired proppant concentration), and determining a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps (e.g., each flow rate setpoint would result in a certain gear of a particular fracking pump being used or would result in the fracking pump being idle) such that a sum of the flow rate setpoints of the dirty side fracking pumps meets (e.g., is within a tolerance of) the desired total flow rate of the dirty side fracking pumps. The method 600 may further include controlling, by the controller, one or more additional pumps (e.g., one or more diesel pumps and / or one or more electric pumps) to achieve the desired total flow rate while maintaining the flow rate setpoints. Any of the method steps ay be performed by the controller and / or a processor.

[0042] The system and method of the present disclosure may improve control of the overall flow rate into a well. Unlike the conventional art, where operators or automated control systems may struggle to manually control set points of multiple natural-gas driven pumps with a fixed speed engine in rapidly changing conditions, the system and method of the present disclosure may quickly and efficiently determine a flow rate setpoint that would achieve a desired flow rate. Advantageously, the system and method of the present disclosure can also optimize for efficiency and / or effectiveness.ADDITIONAL DISCLOSURE

[0043] The following are non-limiting, specific embodiments in accordance with the present disclosure:

[0044] In a first embodiment, a system for injecting fracking fluid into a wellbore comprises fracking pumps each comprising a fixed speed engine driven power train; and a controller configured to: determine a combination of flow rate setpoints of the fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps; and transmit the flow rate setpoints to the fracking pumps, wherein the fracking pumps are configured to inject fracking fluid into the wellbore according to the pump rate setpoints.

[0045] A second embodiment can include the system of the first embodiment, wherein the fracking pumps are natural gas driven.

[0046] A third embodiment can include the system of the first or second embodiments, wherein the controller is further configured to transmit the flow rate setpoints by transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints.

[0047] A fourth embodiment can include the system of any of the first through third embodiments, wherein the controller is further configured to determine a plurality of combinations of flow rate setpoints, and select the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

[0048] A fifth embodiment can include the system of any of the first through fourth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints.

[0049] A sixth embodiment can include the system of any of the first through fifth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a number of the fracking pumps used.

[0050] A seventh embodiment can include the system of any of the first through sixth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a cost function.

[0051] An eighth embodiment can include the system of any of the first through seventh embodiments, wherein the controller is further configured to determine the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj is a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.A ninth embodiment can include the system of any of the first through eight embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0053] A tenth embodiment can include the system of any of the first through ninth embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0054] An eleventh embodiment can include the system of any of the first through tenth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the system further comprises dirty side fracking pumps, and wherein the controller is further configured to determine the desired total flow rate of the clean side fracking pumps and a desired total flow rate of the dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps, and determine a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps such that a sum of the flow rate setpoints of the dirty side fracking pumps meets the desired total flow rate of the dirty side fracking pumps.

[0055] A twelfth embodiment can include the system of any of the first through eleventh embodiments, further comprising additional pumps each comprising a variable speed engine driven power train, wherein the controller is further configured to control the additional pumps to achieve the desired total flow rate while maintaining the flow rate setpoints.

[0056] In a thirteenth embodiment, a system for injecting fracking fluid into a wellbore comprises first fracking pumps each comprising a fixed speed engine driven power train; second fracking pumps each comprising a variable speed engine driven power train; and a controller configured to: determine a combination of first flow rate setpoints of the first fracking pumps corresponding to gears of the first fracking pumps and a combination of second flow rate setpoints of the second fracking pumps such that a sum of the first flow rate setpoints plus a sum of the second flow rate setpoints meets a desired total flow rate of the first fracking pumps and the second fracking pumps; and transmit the first flow rate setpoints to the first fracking pumps, and transmit the second flow rate setpoints to the second fracking pumps, wherein the first fracking pumps are configured to inject fracking fluid into the wellbore according to the first pump rate setpoints, and the second fracking pumps are configured to inject fracking fluid into the wellbore according to the second pump rate setpoints.

[0057] A fourteenth embodiment can include the system of the thirteenth embodiment, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are diesel driven.

[0058] A fifteenth embodiment can include the system of the thirteenth or fourteenth embodiments, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are electrically driven.

[0059] In a sixteenth embodiment, method for injecting fracking fluid into a wellbore comprises determining, by a controller, a combination of flow rate setpoints of fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps; transmitting, by the controller, the flow rate setpoints to the fracking pumps; and injecting, by the fracking pumps, fracking fluid into the wellbore according to the pump rate setpoints, wherein the fracking pumps each comprising a fixed speed engine driven power train.

[0060] A seventeenth embodiment can include the method of the sixteenth embodiment, wherein the fracking pumps are natural gas driven.

[0061] An eighteenth embodiment can include the method of the sixteenth or seventeenth embodiments, wherein the transmitting of the flow rate setpoints comprises transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints.

[0062] A nineteenth embodiment can include the method of any of the sixteenth through eighteenth embodiments, further comprising determining a plurality of combinations of flow rate setpoints, and selecting the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

[0063] A twentieth embodiment can include the method of any of the sixteenth through nineteenth embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints.

[0064] A twenty-first embodiment can include the method of any of the sixteenth through twentieth embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a number of the fracking pumps used.

[0065] A twenty-second embodiment can include the method of any of the sixteenth through twenty-first embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a cost function.

[0066] A twenty-third embodiment can include the method of any of the sixteenth through twenty-second embodiments, wherein the determining of the plurality of combinations of flow rate setpoints comprises determining the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.A twenty-fourth embodiment can include the method of any of the sixteenth through twenty-third embodiments, wherein the determining of the combination of flow rate setpoints comprises determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0068] A twenty-fifth embodiment can include the method of any of the sixteenth through twenty-fourth embodiments, wherein the determining of the combination of flow rate setpoints comprises determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0069] A twenty-sixth embodiment can include the method of any of the sixteenth through twenty-fifth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the method further comprises determining the desired total flow rate of the clean side fracking pumps and a desired total flow rate of dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps, and determining a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps such that a sum of the flow rate setpoints of the dirty side fracking pumps meets the desired total flow rate of the dirty side fracking pumps.

[0070] A twenty-seventh embodiment can include the method of any of the sixteenth through twenty-sixth embodiments, further comprising controlling, by the controller, additional pumps to achieve the desired total flow rate while maintaining the flow rate setpoints.

[0071] While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. For example, the various elements or components may be combined or integrated in another system or certain features may be omitted or not implemented. Also, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other techniques, systems, subsystems, or methods without departing from the scope of this disclosure. Other items shown or discussed as directly coupled or connected or communicating with each other may be indirectly coupled, connected, or communicated with. Method or process steps set forth may be performed in a different order. The use of terms, such as “first,”“second,”“third” or “fourth” to describe various processes or structures is only used as a shorthand reference to such steps / structures and does not necessarily imply that such steps / structures are performed / formed in that ordered sequence (unless such requirement is clearly stated explicitly in the specification).

[0072] 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. 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. Language of degree used herein, such as “approximately,”“about,”“generally,” and “substantially,” represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the language of degree may mean a range of values as understood by a person of skill or, otherwise, an amount that is + / −10%.

[0073] Disclosure of a singular element should be understood to provide support for a plurality of the element. It is contemplated that elements of the present disclosure may be duplicated in any suitable quantity.

[0074] Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc. The use of terms such as “high-pressure” and “low-pressure” is intended to only be descriptive of the component and their position within the systems disclosed herein. That is, the use of such terms should not be understood to imply that there is a specific operating pressure or pressure rating for such components. For example, the term “high-pressure” describing a manifold should be understood to refer to a manifold that receives pressurized fluid that has been discharged from a pump irrespective of the actual pressure of the fluid as it leaves the pump or enters the manifold. Similarly, the term “low-pressure” describing a manifold should be understood to refer to a manifold that receives fluid and supplies that fluid to the suction side of the pump irrespective of the actual pressure of the fluid within the low-pressure manifold.

[0075] Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as embodiments of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. Any discussion of a reference herein is not an admission that it is prior art. Any disclosures of all patents, patent applications, and / or publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.

[0076] As used herein, terms such as parallel, perpendicular, vertical, horizontal, and coincident are not intended to necessarily mean exactly parallel, exactly perpendicular, exactly vertical, exactly horizontal, and exactly coincident. Rather, those terms are intended to mean what those of ordinary skill in the art would recognize as parallel, perpendicular, vertical, horizontal, and coincident. In other words, those and similar terms may cover a structural configuration even when there is some imperfection, variation, or deviation from an exact relationship.

[0077] As used herein, the term “or” does not require selection of only one element. Thus, the phrase “A or B” is satisfied by either one or both elements from the set {A, B}. A clause that recites “A or B” can be infringed with only one of the listed items, both of the listed items, multiples of the listed items, and one or both of the listed items and another item not listed. The phrase “A, B, or C” is satisfied by any one or any combination of any two or more from the set {A, B, C}. A clause that recites “A, B, or C” can be infringed with only one of the listed items, multiples of the listed items, and one or more of the items from the list and another item not listed.

[0078] As used herein, the article “a” means “one or more.” As used herein, the article “an” means “one or more.” As used herein, the article “the” when referring to a singular noun means “the one or more.” Thus, the phrase “an element” means “one or more elements;” and the phrase “the element” means “the one or more elements.”

[0079] As used herein, the term “and / or” includes any combination of the elements associated with the “and / or” term. Thus, the phrase “A, B, and / or C” includes any of A alone, B alone, C alone, A and B together, B and C together, A and C together, or A, B, and C together.

Examples

ninth embodiment

A ninth embodiment can include the system of any of the first through eight embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0053]A tenth embodiment can include the system of any of the first through ninth embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0054]An eleventh embodiment can include the system of any of the first through tenth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the system further comprises dirty side fracking pumps, and wherein the controller is further configured to determine the desired ...

BACKGROUND

[0001] Natural gas spark ignited engines may be used in direct mechanical drive application such as power for driving a fracturing pump. Some engines of this type are of a fixed speed (e.g., isochronous governor) control, meaning that only a single operating rotational speed is available. To achieve more than one operating speed, a multi-gear transmission may be used, which can provide different, but discreet, output shaft speeds which are determined by the gear ratios in the transmission and the driving single speed available from the engine. When one or more of the fixed speed / multi-gear transmission combinations are used in a pumping operation, selection and control of the proper gear and number of pumps can be challenging. For example, complexity of the pumping system, numerosity of pumps, and changing conditions may make it difficult to achieve a desired flow rate with a spread of fixed speed engines. The system and method of the present disclosure may address one or more of these issues.BRIEF DESCRIPTION OF THE DRAWINGS

[0002] For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.

[0003] FIG. 1 is a schematic diagram of an exemplary wellbore servicing system, according to an embodiment of the present disclosure;

[0004] FIG. 2 is a cut-away view of an exemplary hydraulic fracking pump, according to an embodiment;

[0005] FIG. 3 is a schematic diagram of an exemplary hydraulic fracking system, according to an embodiment;

[0006] FIG. 4 is a schematic diagram of an exemplary wellbore servicing system that includes clean side fracking pumps and dirty side fracking pumps;

[0007] FIG. 5 is a schematic diagram of a wellbore servicing system that includes pumps having fixed speed engine driven power trains and pumps having variable speed engine or motor driven power trains; and

[0008] FIG. 6 is a flow diagram of a method for injecting fracking fluid into a wellbore.DETAILED DESCRIPTION

[0009] It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For brevity, well-known steps, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.

[0010] A system and method for controlling hydraulic fracturing pumps having a fixed-speed power train is provided. A control scheme may be used (e.g., executed by a controller) to determine when and how to select the number of pumps to employ and which gears to utilize. This can achieve a greatly variable total flow rate. This can advantageously allow use of fixed-speed engine driven power trains in variable flow rate applications. A supervisory control algorithm (e.g., executed by the controller) may optimally select from a given number of pumping units and discreet individual pump gear ratios to provide a desired total job discharge rate or a total change desired in discharge rate. This can enable use of 100% natural gas fixed speed engines for mechanical (direct) drive pumping where variability in output is required. This may present advantages in terms of both cost and pump availability.

[0011] The controller may select pumps and set points according to an algorithm. The selection process may be explained mathematically. For example, let there be N pumps with a constant-speed engine in a hydraulic fracturing spread, and let the maximum allowed gear be M. The maximum allowed gear may be determined by operating conditions (e.g., expected treating pressure) or by operator's experience. Let the flow rate at i-th gear of j-th pump be qi,j, i=1, . . . , M, j=1, . . . , N. For j-th pump, the chosen pump rate setpoint Qj can only be in the set {0, q1,j, q2,j, . . . , qM,j}. That is, Qj∈{0, q1,j, q2,j, . . . , qM,j}.

[0012] The controller may execute an algorithm according to the following steps: (1) Given a desired total pump rate Qtotal, the supervisory control algorithm determines at least one combination of Qj such that the sum of pump rates meets the desired total pump rate Qtotal; (2) if the number of combinations of Qj is more than one, then the control algorithm chooses one combination; and (3) the chosen rate setpoints are sent to individual pumps which performs necessary adjustments (e.g., gear shift) to track their setpoints. The following system of equations may be solved to determine the combination(s) of Qj in Step 1:Qj=∑izi,j⁢qi,j,j=1,… ,N(1)∑izi,j≤1,j=1,… ,N(2)zi,j=0⁢ or⁢ 1(3)∑jQj=Qtotal(4)where Qj is a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps. Equation 3 states that each available rate (e.g., based on gear) can be either chosen once or not chosen, while Equation 2 restricts the total number of choices for a specific pump can be no more than 1. The chosen rate for j-th pump may be calculated in Equation 1, and the sum of the chosen rates should be equal to (or approximately equal to and / or within a tolerance of) the desired rate as shown in Equation 4. The systems of equations may be solved, for example, by a greedy algorithm, heuristics, combinatorial optimization, search (e.g., breath-first search, depth-first search, brute-force search), or trial-and-error approach. It may not be required to obtain all possible combinations (or equivalently, all solutions to the system of equations) in order to achieve an acceptable total flow rate.In embodiments in which all pumps have the same engine, transmission, and fluid end, the set {0, q1,j, q2,j, . . . , qM,j} are the same for all j=1, . . . , N. This may be denoted as q1,j=q2,j= . . . =qM,j=qj. In this case, the problem can be reduced by solving the following Diophantine equation:N1⁢q1+N2⁢q2+⋯+Nj⁢qj=Qtotal(5)where Nj indicates how many pumps are using rate qj (i.e., shifted into j-th gear). The controller may solve for all possible combinations in polynomial time. Next, the controller may discard any combinations that requires a greater number of pumps than is available, i.e., ΣNj>N. Then, the controller may choose one combination and assign those rates to pumps. For example, let Qtotal=10 bpm, the pumps have two gears available with q1=2 bpm and q2=3 bpm, and there are five pumps available. In this example, solutions to Equation 5 are: (1) N1=5, N2=0; and (2) N1=2, N2=2. The controller may select the second solution considering that it uses fewer pumps. Then, controller may assign two pumps a rate setpoints q1=2 bpm, assign two pumps a rate setpoint of q2=3 bpm, and assign one pump to be idled. In some embodiments, selection of the combinations may be based on rules or may be selected to minimize a cost function. For example, selection criterion may be used to choose the combination using the least number of pumps. In some embodiments, selection of the combinations may be based on current operating points of pumps. For example, if all pumps are currently in Gear 1 (e.g., the rate being 2 bpm), the first solution may be chosen because there would be no gear shift required.In some embodiments, selection of the combinations may be based on pump dynamics in combination with current operating points of the pumps. A combination with least impact to the spread rate may be selected. Each gear shift may take two seconds regardless of upshift or downshift. In an example, there are two combinations available: (1) shift one pump from 2nd gear to 4th gear and shift one pump from 5th gear to 3rd gear; and (2) shift one pump from 2nd gear to 5th gear and shift one pump from 3rd gear to 1st gear. In this example, the first solution may be selected because the net change in gear is 0, while the net change in gear in the second solution is 1. Fewer net changes in gear shifts may generally indicate less impact to the spread rate, and the controller may select the combination on this basis.In some embodiments, the criteria for selection of the combinations may expedite Step 1 by eliminating possible combinations that are known to be less favorable. For example, in the example involving Equation 5 in which the solution is optimized for least number of pumps, if a brute force search method is used to list all the combinations and a combination has already been obtained for N1=2 and N2=3 assuming only two gears are allowed, then any combinations with N1≥6 may be ignored because regardless of the value of N2, the sum of N1 and N2 may be guaranteed to be greater than the sum of the current combination already obtained (N1+N2=5).

[0016] In some embodiments, given the criteria for selection of the combination, the processor may stop finding new combinations if there is at least one combination known to already meet the criteria. For example, if a pre-determined criteria says that the total number of pumps being used is in less than or equal to 5, then after the processor finds a solution N1=2 and N2=3, the processor may cease searching for new combinations.

[0017] In some embodiments, Step 1 (e.g., finding all the combinations) and Step 2 (e.g., selection of combinations) can be combined in one step by solving the following optimization problem:min⁢ ∑ i,j⁢wij⁢zij⁢qij(6)subject to Equations 1 through 4, where wij is the cost for the j-th pump to select the i-th gear. The cost function or cost term wij may be according to any of the examples described herein. The optimization problem above may be solved by the Hungarian algorithm, for example. In some embodiments, there may be a reward associated with each gear selection, and the goal of optimization may be to maximize total rewards. In such cases, the cost term wij may be the negative of reward if i-th gear is selected for the j-th pump.In some embodiments, for the optimization problem, one may use a heuristic based approach to find an optimal or suboptimal solution. For example, if one solution is found that satisfies all the constraints that generate a cost function value lower than a threshold, the search for an optimal or suboptimal solution may be stopped early.

[0019] In some embodiments, in Step 1, the sum of pump rates meets the desired total pump rate when the sum of pump rates EQ, is as close to Qtotal as possible while ΣQj≤Qtotal. In other embodiments, the controller may determine that the sum of pump rates meets the desired total pump rate when Qtotal−ΣQj is within a tolerance of [Qtol,min, Qtol,max].

[0020] In some embodiments, for example, in a split-flow operation, Step 1 may be applied to the clean side and the dirty side independently. That is, the controller may solve the system of equations to generate combinations of set points for the clean side and solve the system of equations to generate combinations of set points for the dirty side. In Step 2, combinations of both sides may be considered as a whole. That is, the controller may select a combination of the clean side and a combination of the dirty side from the generated combinations together (e.g., considering the combined flow rate output of both) according to any of the criteria disclosed herein.

[0021] In some embodiments, pumps with fixed-speed engines may be used in conjunction with one or more variable-speed engines. The rates of the variable-speed engine(s) may be considered by revising the total pump rate in Step 1 according to: Qtotal,fix=Qtotal−Qtotal,var, where Qtotal, var is the total rate of pumps with variable-speed engines, and Qtotal, fix replaces Qtotal in Step 1. Since Qtotal,var may be continuous (or piecewise continuous) in value, a gradient-based method can be applied if a cost function is used to determine the combination of rates of pumps with fixed-speed engines. That is, an optimized solution to the cost function may be obtained by a gradient-based method. Alternatively, pumps with variable-speed engines may be used as trim pumps, e.g., Qtotal, var can be varied by manipulating rates of variable-speed engine pumps without shifting gears of these pumps. In some embodiments, the controller may determine a combination of gears of the fixed-speed engine driven pumps which most closely approximates and undershoots the desired total flow rate, then the controller may determine a rate of flow of one or more variable-speed engine driven pumps to add to the flow of the fixed-speed engine driven pumps to even more closely approximate the desired flow rate.

[0022] Referring to FIG. 1, an exemplary wellbore servicing system 100 is shown. The wellbore servicing system 100 may be configured for fracturing wells in low-permeability reservoirs, among other wellbore servicing jobs. In fracturing operations, wellbore servicing fluids, such as particle laden fluids, may be pumped at high pressure downhole into a wellbore. The wellbore servicing system 100 may introduce particle laden fluids into a portion of a subterranean hydrocarbon formation at a sufficient pressure and velocity to form and extend fractures within the subterranean hydrocarbon formation. Proppants, such as grains of sand, may be mixed with the wellbore servicing fluid to keep the fractures open so that hydrocarbons may be produced from the subterranean hydrocarbon formation and flow into the wellbore. Hydraulic fracturing may create high-conductivity fluid communication between the wellbore and the subterranean hydrocarbon formation.

[0023] The wellbore servicing system 100 may include a blender 114 that is coupled to a manifold 118 (e.g., wellbore services manifold trailer) via a flowline or flowlines 116. The wellbore services manifold trailer may comprise a truck and / or trailer comprising one or more manifolds for receiving, organizing, and / or distributing wellbore servicing fluids during wellbore servicing operations. The manifold 118 may be coupled via outlet flowlines 122 and inlet flowlines 124 to pumps 120 (e.g., pumps having fixed speed engine driven power trains and / or pumps having variable speed engine or motor driven power trains). Outlet flowlines 122 may supply fluid to the pumps 120 from the manifold 118. Inlet flowlines 124 may supply fluid to the manifold 118 from the pumps 120. The manifold 118 may have manifold outlets from which wellbore servicing fluids flow to a wellhead 132 via one or more flowlines 134. The blender 114 may mix solid and fluid components to achieve a well-blended wellbore servicing fluid. Sand or proppant 102, water or other carrier fluid 106, and additives 110 may be fed into the blender 114 via feedlines 104, 108, and 112, respectively.

[0024] The wellbore servicing system 100 may 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 may further comprise 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. Operational information about the pumps 120 may be communicated to a controller 140 by the sensors 136. Further, the pump control inputs 138 may be configured to receive signals, instructions, orders, states, and / or data sufficient to alter, vary, and / or maintain an operation of the pumps 120. The controller 140, sensors 136, and pump control inputs 138 may be configured so that each pump 120 and / or individual components of the pumps 120 are independently monitored and 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 may further comprise a combined pump output sensor 142. The combined pump output sensor 142 may be associated with a flowline 134 that carries a fluid flow that results from the combined pumping efforts of all pumps 120. The combined pump output sensor 142 may be configured to monitor and / or report combined pump effect operational characteristic values to the control system 140. Alternatively, the combined output can be obtained by summing the output from individual sensors 136.

[0025] Referring to FIG. 2, the pump 120 may comprise a power end 502 and a fluid end 504 attached to the power end 502. The power end 502 may comprise a crankshaft 506 that reciprocates a plunger 508 within a bore 516 of the fluid end 504. The fluid end 504 may further comprise a compression chamber 510 into which fluid flows through a suction valve 512. Fluid may be pumped out of the compression chamber 510 through a discharge valve 514 as the plunger 508 is moved toward the compression chamber 510. The crankshaft 506 may be mechanically coupled to a gearbox 3, which is shown schematically in FIG. 3.

[0026] Referring to FIG. 3, an exemplary pumping system 1 for hydraulic fracturing is shown. The pumping system 1 may comprise a pump 120; a gearbox 3 mechanically coupled to the pump 120; a driveline 4 mechanically coupled to the gearbox 3; and a power unit 5 mechanically coupled to the driveline 4. The power unit 5 may be a natural gas powered engine. The driveline 4 may rotate at a fixed speed. That is, the natural gas powered engine may be configured to turn the driveline 4 at only one rotational velocity. Stated another way, the natural gas engine may have only two modes of operation: idle and drive, and in the drive mode, the driveline 4 is driven at only one rotational velocity. In other embodiments, the power unit 5 may be a diesel engine or a motor. In such embodiments, the power unit 5 may be variable speed (e.g., the driveline 4 may be driven at multiple speeds).

[0027] Referring to FIGS. 1 and 3, a system 100 for injecting fracking fluid into a wellbore may include fracking pumps 120 each comprising a fixed speed engine driven power train 6 (e.g., the power unit 5 is configured to turn a driveline4 of the power train 6 (which includes the gearbox 3) at a constant speed, e.g., the power unit 5 is a natural gas driven engine that has / consists of only two modes: a constant speed mode and an idle mode); and a controller 140 configured to determine a combination of flow rate setpoints (e.g., set points that are expected to result in certain flow rate outputs of the pumps 120, the flow rates being based on which gear in the gearbox 3 of the pumps 120 is selected, e.g., the setpoints may be an overall flow rate command or a gear selection command) of the fracking pumps corresponding to gears (e.g., of the gearbox 3) of the fracking pumps 120 such that a sum of the flow rate setpoints (e.g., each of the flow rate setpoints of the pumps being added together) meets a desired total flow rate of the fracking pumps 120 (e.g., the desired total flow rate may be set by an operator or automatically generated); and transmit the flow rate setpoints to the fracking pumps (e.g., via wired or wireless communication). The fracking pumps 120 may be configured to inject fracking fluid into the wellbore / wellhead 132 according to the pump rate setpoints. That is, the fracking pumps 120 may shift gears according to the setpoints to output a combined flow rate that better approximates the desired flow rate.

[0028] The setpoints may include a zero setpoint or an idle setpoint for one or more of the pumps. The controller 140 may be further configured to transmit the flow rate setpoints by transmitting one or more commands to shift one or more of the gears (e.g., in the gearbox 3 of one or more of the pumps 120) to achieve a state of the gears that corresponds to the combination of flow rate setpoints. Of the pumps 120 that are not set to idle, each pump 120 may have a certain gear selected so that the combined output of the pumps 120 achieves or approximates the desired flow rate setpoint. The command to shift the gear(s) may be received by a unit controller of the individual pump system 1, which may then control the gearbox 3 to shift gears. The command may also include a particular timing to make the shift. For example, if multiple pumps 120 need to have gears shifted to conform with the combination of setpoints, the controller 140 may time the gear shifts to be spaced out in time, which can be advantageous in that the asynchronous gear shifting may mitigate flow disturbances during transition to the combination of setpoints.

[0029] The controller 140 may be further configured to determine a plurality of combinations of flow rate setpoints, and select the combination of flow rate set points from among the plurality of combinations of flow rate setpoints. Each of the plurality of combinations of flow rate setpoints may include a distinct combination of gears selected or a distinct combination of gears that would be selected according to the setpoints in the combination. That is, in each combination, there may be a unique combination of gear selection and / or idle selection of the respective pumps 120. In each combination, or one more of the pumps 120 may have gears selected and one or more of the pumps 120 may be set to idle. Each combination may be unique (e.g., no two combinations of the plurality of combinations are the same).

[0030] The controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints of the combination. For example, after generating the plurality of combinations of flow rate setpoints, the controller 140 may compare the current state of gears of the pumps 120 with the state of gears of each of the plurality of combinations and determine which of the plurality of combinations would require the least number of gear shifts from the current state to the particular combination. Alternatively or additionally, the controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a number of the fracking pumps 120 used. For example, some of the combinations may have a greater number of pumps set to idle than others, and the controller may select the combination that has the greatest number of pumps being set to idle. Alternately or additionally, controller 140 may be configured to select the combination of flow rate setpoints so as to minimize a cost function. The cost function may be based on an economic cost to run the pumps 120. For example, the cost function may take into consideration efficiency and / or energy demand of the pumps depending on which gear they are in.

[0031] The selection of the combination and / or the cost function may also take into consideration equipment limitations and / or equipment health. For example, the combination may be selected in consideration of information that at least some of the equipment cannot accept full power (e.g., due to maintenance issues). The controller may use a cost function that is in terms of the amount of natural gas expected to be consumed for running a given pump in a given gear. The cost function may take into account number of shifts required and may tend to minimize the number of shifts required. The controller may select the combination having the lowest combined expected natural gas consumption rate. In some embodiments, the selection of the combination may be based on inputs from the equipment (e.g., real time data). For example, the selection may be based on data regarding pump transmission, engine, cooling systems, air cleaner restrictions, and / or lube oil level / quality. In some embodiments, the controller is configured to exclude one or more pumps in response to the controller determining that the one or more pumps would be unable to achieve a particular flow rate based on one or more inputs from the equipment. In some embodiments, the cost function takes into account pumping efficiency associated with gears of the pumps. In some embodiments, the cost function is based on efficient loading of the pumps. In some embodiments, the cost function is based on emissions associated with the set points. In some embodiments, the cost function minimizes the number of variable speed engine driven pumps used.

[0032] The controller 140 may be configured to determine the plurality of combinations of flow rate setpoints by using (e.g., solving) Equations 1-4. The equations may be solved by any suitable method. The controller 140 may be configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps. That is, the controller 140 may generate a plurality of flow rate setpoint combinations, and determine that one of them “meets” the desired flow rate because that combination yields a combined flow rate that more closely approximates the desired flow rate than any other of the generated combinations. Additionally or alternatively, the controller 140 may be configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate. For example, the controller 140 may discard combinations that are expected to yield a combined flow rate outside of the tolerance and select a combination expected to yield a combined flow rate that is inside the tolerance. If multiple combinations are expected to yield a combined flow rate that is inside the tolerance, the controller 140 may select the combination that would be expected to yield a flow rate closest to the desired flow rate and / or select the combination based on other factors, for example, the number of pumps at idle in the combination, the combination that minimizes the cost function, and / or any other suitable factors.

[0033] Referring to FIG. 4, the system 100 may include one or more clean side fracking pumps 120A and one or more dirty side fracking pumps 120B. The fracking pumps 120A, 120B may be fluidly coupled to a wellbore / wellhead 132 (e.g., via a manifold). The controller 140 may be configured to determine the desired total flow rate of the clean side fracking pumps 120A and a desired total flow rate of the dirty side fracking pumps 120B to meet a combined total flow rate of the clean side fracking pumps 120A and the dirty side fracking pumps 120B. These desired total flow rates may be based on a desired concentration of proppant to be pumped into the wellbore / wellhead 132. The controller 140 may then determine a combination of flow rate setpoints of the clean side fracking pumps 120A corresponding to gears of the clean side fracking pumps such that a sum of the flow rate setpoints of the clean side fracking pumps 120A meets the desired total flow rate of the clean side fracking pumps, and determine a combination of flow rate setpoints of the dirty side frack pumps 120B corresponding to gears of the dirty side fracking pumps 120B such that a sum of the flow rate setpoints of the dirty side fracking pumps 120B meets the desired total flow rate of the dirty side fracking pumps 120B. The determination of the combinations of flow rate setpoints can be achieved by any of the methods disclosed herein.

[0034] Referring to FIG. 5, a system 100 for injecting fracking fluid into a wellbore may include first fracking pumps 120C each comprising a fixed speed engine driven power train; and second fracking pumps 120D each comprising a variable speed engine driven power train. The first fracking pumps 120C and the second fracking pumps 120D may be fluidly coupled to a wellbore / wellhead 132. The system 100 may further include controller 140 configured to determine a combination of first flow rate setpoints of the first fracking pumps 120C corresponding to gears of the first fracking pumps 120C and a combination of second flow rate setpoints of the second fracking pumps 120D such that a sum of the first flow rate setpoints plus a sum of the second flow rate setpoints meets a desired total flow rate of the first fracking pumps 120C and the second fracking pumps 120D. For example, the controller 140 may first determine a plurality of combinations of first flow rate setpoints, select a combination from the plurality of combinations of first flow rate setpoints, then generate the plurality of second flow rate setpoints to approximate a difference between the combined flow rate of the selected combination of first flow rates and the desired flow rate, and select a combination of second flow rate setpoints from the plurality of second flow rate setpoints such that a total combined flow rate of the first combination of flow rates and the second combination of flow rates approximates the desired total flow rate. Additional methods such as using a cost function and / or minimizing the number of active pumps may be used to select the combinations.

[0035] The combination of first flow rate setpoints may be determined by any of the methods disclosed herein. The combination of second flow rate setpoints may also be determined based on gear usage but the gears may allow for continuous or piece-wise continuous possibilities for the setpoints. The controller may generate the combinations of second flow rate setpoints based on efficient engine / motor speed and gear selection combinations.

[0036] The controller 140 may transmit the first flow rate setpoints to the first fracking pumps 120C, and transmit the second flow rate setpoints to the second fracking pumps 120D. The first fracking pumps 120C may inject fracking fluid into the wellbore / wellhead 132 according to the first pump rate setpoints, and the second fracking pumps 120D may inject fracking fluid into the wellbore / wellhead 132 according to the second pump rate setpoints. In some embodiments, the first fracking pumps 120C are all natural gas driven (fixed engine speed) pumps, and the second fracking pumps 120D are diesel driven pumps, electrically driven pumps, or a combination of diesel driven pumps and electrically driven pumps. The flow rate of the electrically driven pumps may be controlled by a variable frequency drive.

[0037] Referring to FIG. 6, a method 600 for injecting fracking fluid into a wellbore may include the step 610 of determining, by a controller, a combination of flow rate setpoints of fracking pumps corresponding to gears of the fracking pumps (e.g., the flow rate setpoints could be the gear settings themselves or a flow rate setting which would require a certain gear setting) such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps (e.g., expected flow rates from each of the respective pumps having their respective flow rate setpoints when summed approximate the total desired total flow rate), wherein the fracking pumps each comprising a fixed speed engine driven power train (e.g., the engine turns a driveline at a fixed rate, e.g., the driveline speed is not adjustable, e.g., the engine is only capable of idling and running at a fixed speed); the step 620 of transmitting, by the controller, the flow rate setpoints to the fracking pumps (e.g., by wired or wireless transmission); and the step 630 of injecting, by the fracking pumps, fracking fluid into the wellbore according to the pump rate setpoints (e.g., the fracking pumps respectively receive the flow rate setpoints from the controller, and based on the flow rate setpoints, each of the fracturing pumps either has no change, increases a rate of pumping by changing gears, decreases a rate of pumping by changing gears, shifts into idle, or shifts out of idle into a particular gear).

[0038] The fracking pumps may be natural gas driven. The transmitting of the flow rate setpoints may include transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints. This may also include commanding one or more pumps to shift into idle and / or commanding one or more pumps to shift out of idle to a particular gear.

[0039] The method 600 may further include determining a plurality of combinations of flow rate setpoints, and selecting the combination of flow rate set points from among the plurality of combinations of flow rate setpoints. The plurality of combinations of flow rate setpoints may be generated according to any of the methods described herein. For example, the controller may generate multiple combinations that would achieve a flow rate within a tolerance of the desired flow rate. The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a total number of gear shifts (e.g., from the current gear configuration to the gear configuration that would occur as a result of the setpoints in the particular combination) required to achieve the flow rate setpoints. The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a number of the fracking pumps used (e.g., maximize the number of fracking pumps that would idle as a result of the setpoints in the particular combination). The selecting of the combination of flow rate setpoints may include selecting the combination of flow rate setpoints so as to minimize a cost function (e.g., selecting the combination that would result in least natural gas consumption or maximum profit considering natural gas expenditures and / or fracking efficiency). The determining of the plurality of combinations of flow rate setpoints may include determining the plurality of combinations of flow rate setpoints by using (e.g., solving) Equations 1-4 (e.g., using numerical methods).

[0040] The determining of the combination of flow rate setpoints may include determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with sums of other combinations of flow rate setpoints of the fracking pumps. That is, the controller may generate a plurality of combinations of flow rate setpoints and select the one that is predicted to result in the closest flow rate to the desired flow rate. This prediction may be based on quality of the natural gas. The determining and / or the selecting of the combination of flow rate setpoints may include determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0041] The method 600 may further include determining the desired total flow rate of clean side fracking pumps and a desired total flow rate of dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps (e.g., also to achieve a desired proppant concentration), and determining a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps (e.g., each flow rate setpoint would result in a certain gear of a particular fracking pump being used or would result in the fracking pump being idle) such that a sum of the flow rate setpoints of the dirty side fracking pumps meets (e.g., is within a tolerance of) the desired total flow rate of the dirty side fracking pumps. The method 600 may further include controlling, by the controller, one or more additional pumps (e.g., one or more diesel pumps and / or one or more electric pumps) to achieve the desired total flow rate while maintaining the flow rate setpoints. Any of the method steps ay be performed by the controller and / or a processor.

[0042] The system and method of the present disclosure may improve control of the overall flow rate into a well. Unlike the conventional art, where operators or automated control systems may struggle to manually control set points of multiple natural-gas driven pumps with a fixed speed engine in rapidly changing conditions, the system and method of the present disclosure may quickly and efficiently determine a flow rate setpoint that would achieve a desired flow rate. Advantageously, the system and method of the present disclosure can also optimize for efficiency and / or effectiveness.ADDITIONAL DISCLOSURE

[0043] The following are non-limiting, specific embodiments in accordance with the present disclosure:

[0044] In a first embodiment, a system for injecting fracking fluid into a wellbore comprises fracking pumps each comprising a fixed speed engine driven power train; and a controller configured to: determine a combination of flow rate setpoints of the fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps; and transmit the flow rate setpoints to the fracking pumps, wherein the fracking pumps are configured to inject fracking fluid into the wellbore according to the pump rate setpoints.

[0045] A second embodiment can include the system of the first embodiment, wherein the fracking pumps are natural gas driven.

[0046] A third embodiment can include the system of the first or second embodiments, wherein the controller is further configured to transmit the flow rate setpoints by transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints.

[0047] A fourth embodiment can include the system of any of the first through third embodiments, wherein the controller is further configured to determine a plurality of combinations of flow rate setpoints, and select the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

[0048] A fifth embodiment can include the system of any of the first through fourth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints.

[0049] A sixth embodiment can include the system of any of the first through fifth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a number of the fracking pumps used.

[0050] A seventh embodiment can include the system of any of the first through sixth embodiments, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a cost function.

[0051] An eighth embodiment can include the system of any of the first through seventh embodiments, wherein the controller is further configured to determine the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj is a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.A ninth embodiment can include the system of any of the first through eight embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0053] A tenth embodiment can include the system of any of the first through ninth embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0054] An eleventh embodiment can include the system of any of the first through tenth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the system further comprises dirty side fracking pumps, and wherein the controller is further configured to determine the desired total flow rate of the clean side fracking pumps and a desired total flow rate of the dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps, and determine a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps such that a sum of the flow rate setpoints of the dirty side fracking pumps meets the desired total flow rate of the dirty side fracking pumps.

[0055] A twelfth embodiment can include the system of any of the first through eleventh embodiments, further comprising additional pumps each comprising a variable speed engine driven power train, wherein the controller is further configured to control the additional pumps to achieve the desired total flow rate while maintaining the flow rate setpoints.

[0056] In a thirteenth embodiment, a system for injecting fracking fluid into a wellbore comprises first fracking pumps each comprising a fixed speed engine driven power train; second fracking pumps each comprising a variable speed engine driven power train; and a controller configured to: determine a combination of first flow rate setpoints of the first fracking pumps corresponding to gears of the first fracking pumps and a combination of second flow rate setpoints of the second fracking pumps such that a sum of the first flow rate setpoints plus a sum of the second flow rate setpoints meets a desired total flow rate of the first fracking pumps and the second fracking pumps; and transmit the first flow rate setpoints to the first fracking pumps, and transmit the second flow rate setpoints to the second fracking pumps, wherein the first fracking pumps are configured to inject fracking fluid into the wellbore according to the first pump rate setpoints, and the second fracking pumps are configured to inject fracking fluid into the wellbore according to the second pump rate setpoints.

[0057] A fourteenth embodiment can include the system of the thirteenth embodiment, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are diesel driven.

[0058] A fifteenth embodiment can include the system of the thirteenth or fourteenth embodiments, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are electrically driven.

[0059] In a sixteenth embodiment, method for injecting fracking fluid into a wellbore comprises determining, by a controller, a combination of flow rate setpoints of fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps; transmitting, by the controller, the flow rate setpoints to the fracking pumps; and injecting, by the fracking pumps, fracking fluid into the wellbore according to the pump rate setpoints, wherein the fracking pumps each comprising a fixed speed engine driven power train.

[0060] A seventeenth embodiment can include the method of the sixteenth embodiment, wherein the fracking pumps are natural gas driven.

[0061] An eighteenth embodiment can include the method of the sixteenth or seventeenth embodiments, wherein the transmitting of the flow rate setpoints comprises transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints.

[0062] A nineteenth embodiment can include the method of any of the sixteenth through eighteenth embodiments, further comprising determining a plurality of combinations of flow rate setpoints, and selecting the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

[0063] A twentieth embodiment can include the method of any of the sixteenth through nineteenth embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints.

[0064] A twenty-first embodiment can include the method of any of the sixteenth through twentieth embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a number of the fracking pumps used.

[0065] A twenty-second embodiment can include the method of any of the sixteenth through twenty-first embodiments, wherein the selecting of the combination of flow rate setpoints comprises selecting the combination of flow rate setpoints so as to minimize a cost function.

[0066] A twenty-third embodiment can include the method of any of the sixteenth through twenty-second embodiments, wherein the determining of the plurality of combinations of flow rate setpoints comprises determining the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.A twenty-fourth embodiment can include the method of any of the sixteenth through twenty-third embodiments, wherein the determining of the combination of flow rate setpoints comprises determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0068] A twenty-fifth embodiment can include the method of any of the sixteenth through twenty-fourth embodiments, wherein the determining of the combination of flow rate setpoints comprises determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0069] A twenty-sixth embodiment can include the method of any of the sixteenth through twenty-fifth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the method further comprises determining the desired total flow rate of the clean side fracking pumps and a desired total flow rate of dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps, and determining a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps such that a sum of the flow rate setpoints of the dirty side fracking pumps meets the desired total flow rate of the dirty side fracking pumps.

[0070] A twenty-seventh embodiment can include the method of any of the sixteenth through twenty-sixth embodiments, further comprising controlling, by the controller, additional pumps to achieve the desired total flow rate while maintaining the flow rate setpoints.

[0071] While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. For example, the various elements or components may be combined or integrated in another system or certain features may be omitted or not implemented. Also, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other techniques, systems, subsystems, or methods without departing from the scope of this disclosure. Other items shown or discussed as directly coupled or connected or communicating with each other may be indirectly coupled, connected, or communicated with. Method or process steps set forth may be performed in a different order. The use of terms, such as “first,”“second,”“third” or “fourth” to describe various processes or structures is only used as a shorthand reference to such steps / structures and does not necessarily imply that such steps / structures are performed / formed in that ordered sequence (unless such requirement is clearly stated explicitly in the specification).

[0072] 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. 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. Language of degree used herein, such as “approximately,”“about,”“generally,” and “substantially,” represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the language of degree may mean a range of values as understood by a person of skill or, otherwise, an amount that is + / −10%.

[0073] Disclosure of a singular element should be understood to provide support for a plurality of the element. It is contemplated that elements of the present disclosure may be duplicated in any suitable quantity.

[0074] Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc. The use of terms such as “high-pressure” and “low-pressure” is intended to only be descriptive of the component and their position within the systems disclosed herein. That is, the use of such terms should not be understood to imply that there is a specific operating pressure or pressure rating for such components. For example, the term “high-pressure” describing a manifold should be understood to refer to a manifold that receives pressurized fluid that has been discharged from a pump irrespective of the actual pressure of the fluid as it leaves the pump or enters the manifold. Similarly, the term “low-pressure” describing a manifold should be understood to refer to a manifold that receives fluid and supplies that fluid to the suction side of the pump irrespective of the actual pressure of the fluid within the low-pressure manifold.

[0075] Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as embodiments of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. Any discussion of a reference herein is not an admission that it is prior art. Any disclosures of all patents, patent applications, and / or publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.

[0076] As used herein, terms such as parallel, perpendicular, vertical, horizontal, and coincident are not intended to necessarily mean exactly parallel, exactly perpendicular, exactly vertical, exactly horizontal, and exactly coincident. Rather, those terms are intended to mean what those of ordinary skill in the art would recognize as parallel, perpendicular, vertical, horizontal, and coincident. In other words, those and similar terms may cover a structural configuration even when there is some imperfection, variation, or deviation from an exact relationship.

[0077] As used herein, the term “or” does not require selection of only one element. Thus, the phrase “A or B” is satisfied by either one or both elements from the set {A, B}. A clause that recites “A or B” can be infringed with only one of the listed items, both of the listed items, multiples of the listed items, and one or both of the listed items and another item not listed. The phrase “A, B, or C” is satisfied by any one or any combination of any two or more from the set {A, B, C}. A clause that recites “A, B, or C” can be infringed with only one of the listed items, multiples of the listed items, and one or more of the items from the list and another item not listed.

[0078] As used herein, the article “a” means “one or more.” As used herein, the article “an” means “one or more.” As used herein, the article “the” when referring to a singular noun means “the one or more.” Thus, the phrase “an element” means “one or more elements;” and the phrase “the element” means “the one or more elements.”

[0079] As used herein, the term “and / or” includes any combination of the elements associated with the “and / or” term. Thus, the phrase “A, B, and / or C” includes any of A alone, B alone, C alone, A and B together, B and C together, A and C together, or A, B, and C together.

Examples

ninth embodiment

A ninth embodiment can include the system of any of the first through eight embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

[0053]A tenth embodiment can include the system of any of the first through ninth embodiments, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

[0054]An eleventh embodiment can include the system of any of the first through tenth embodiments, wherein the fracking pumps are clean side fracking pumps, wherein the system further comprises dirty side fracking pumps, and wherein the controller is further configured to determine the desired ...

Claims

1. A system for injecting fracking fluid into a wellbore, comprising:fracking pumps each comprising a fixed speed engine driven power train; anda controller configured to:determine a combination of flow rate setpoints of the fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps; andtransmit the flow rate setpoints to the fracking pumps,wherein the fracking pumps are configured to inject fracking fluid into the wellbore according to the pump rate setpoints.

2. The system of claim 1, wherein the fracking pumps are natural gas driven.

3. The system of claim 1, wherein the controller is further configured to transmit the flow rate setpoints by transmitting one or more commands to shift one or more of the gears to achieve a state of the gears that corresponds to the combination of flow rate setpoints.

4. The system of claim 1, wherein the controller is further configured to determine a plurality of combinations of flow rate setpoints, and select the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

5. The system of claim 4, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a total number of gear shifts required to achieve the flow rate setpoints.

6. The system of claim 4, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a number of the fracking pumps used.

7. The system of claim 4, wherein the controller is further configured to select the combination of flow rate setpoints so as to minimize a cost function.

8. The system of claim 4, wherein the controller is further configured to determine the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj is a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.

9. The system of claim 1, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

10. The system of claim 1, wherein the controller is further configured to determine that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being within a tolerance of the desired flow rate.

11. The system of claim 1, wherein the fracking pumps are clean side fracking pumps, wherein the system further comprises dirty side fracking pumps, and wherein the controller is further configured to determine the desired total flow rate of the clean side fracking pumps and a desired total flow rate of the dirty side fracking pumps to meet a combined total flow rate of the clean side fracking pumps and the dirty side fracking pumps, and determine a combination of flow rate setpoints of the dirty side frack pumps corresponding to gears of the dirty side fracking pumps such that a sum of the flow rate setpoints of the dirty side fracking pumps meets the desired total flow rate of the dirty side fracking pumps.

12. The system of claim 1, further comprising additional pumps each comprising a variable speed engine driven power train, wherein the controller is further configured to control the additional pumps to achieve the desired total flow rate while maintaining the flow rate setpoints.

13. A system for injecting fracking fluid into a wellbore, comprising:first fracking pumps each comprising a fixed speed engine driven power train;second fracking pumps each comprising a variable speed engine driven power train; anda controller configured to:determine a combination of first flow rate setpoints of the first fracking pumps corresponding to gears of the first fracking pumps and a combination of second flow rate setpoints of the second fracking pumps such that a sum of the first flow rate setpoints plus a sum of the second flow rate setpoints meets a desired total flow rate of the first fracking pumps and the second fracking pumps; andtransmit the first flow rate setpoints to the first fracking pumps, and transmit the second flow rate setpoints to the second fracking pumps,wherein the first fracking pumps are configured to inject fracking fluid into the wellbore according to the first pump rate setpoints, and the second fracking pumps are configured to inject fracking fluid into the wellbore according to the second pump rate setpoints.

14. The system of claim 13, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are diesel driven.

15. The system of claim 13, wherein the first fracking pumps are natural gas driven, and one or more of the second fracking pumps are electrically driven.

16. A method for injecting fracking fluid into a wellbore, comprising:determining, by a controller, a combination of flow rate setpoints of fracking pumps corresponding to gears of the fracking pumps such that a sum of the flow rate setpoints meets a desired total flow rate of the fracking pumps;transmitting, by the controller, the flow rate setpoints to the fracking pumps; andinjecting, by the fracking pumps, fracking fluid into the wellbore according to the pump rate setpoints,wherein the fracking pumps each comprising a fixed speed engine driven power train.

17. The method of claim 16, wherein the fracking pumps are natural gas driven.

18. The method of claim 16, further comprising determining a plurality of combinations of flow rate setpoints, and selecting the combination of flow rate set points from among the plurality of combinations of flow rate setpoints.

19. The method of claim 18, wherein the determining of the plurality of combinations of flow rate setpoints comprises determining the plurality of combinations of flow rate setpoints by solving the following system of equations:Qj=∑izi,j⁢qi,j,j=1,… ,N∑izi,j≤1,j=1,… ,Nzi,j=0⁢ or⁢ 1∑jQj=Qtotalwherein Qj a flow rate setpoint of a j-th pump of the fracking pumps, zi,j is a coefficient indicating whether an i-th gear of the j-th pump is used, qi,j is a flow rate setpoint of the i-th gear of the j-th pump, and Qtotal is a total flow rate setpoint of the fracking pumps.

20. The method of claim 16, wherein the determining of the combination of flow rate setpoints comprises determining that the sum of the flow rate setpoints meets the desired flow rate in response to the sum of the flow rate setpoints being the closest to the desired flow rate as compared with other sums of flow rate setpoints of the fracking pumps.

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