Patent Application
20250137447
None.
Not applicable.
Not applicable.
Hydraulic fracturing operations may include a number of high pressure pumps directing proppant laden fluid into a hydrocarbon bearing formation. The proppant laden fluid must be pumped at pressure into downhole earth formations to produce fractures within the formation and provide a flow path to produce the desired hydrocarbons such as oil and gas. The pressures, flowrates, and concentration of the proppant laden fluids must be controlled to achieve the intended effect, and typically multiple pumps are used for purposes of volume and redundancy. Due to the high-stress nature of the pumping environment, high pressure pump parts may undergo mechanical wear and require frequent replacement. Failure of one or more pump parts may lead to an undesirable decrease in pumping performance during a pumping operation. A method of monitoring the health of the high pressure pumps during the pumping operation is desirable.
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.
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 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.
As used herein, a pumping unit can comprise a pump coupled to a prime mover. The term pump can refer to a fluid end, a positive displacement pump, a plunger pump, a piston pump, a progressive cavity pump, a gear pump, a screw pump, a lobe pump, a double screw pump, an impeller and diffuser, a centrifugal pump, a multistage centrifugal pump, a turbine, or any other type of pump suitable for pressurizing fluids. In some embodiments, the prime mover can include an electric motor, an internal combustion engine, or a hybrid motor configured to alternate between the two types of motor.
As used herein, a dual pumping unit can comprise two pumps coupled to a prime mover. The prime mover can provide torque and rotation to a first pump, a second pump, or both pumps. As previously described, the prime mover can be an electric motor, an internal combustion engine, or a hybrid motor.
As used herein, a wellbore treatment can be any fluid pumped into a wellbore during multiple stages of oil well construction. Each stage can be carried out with specialized equipment and wellbore treatments. Examples of various wellbore treatments can include drilling mud that is pumped into the wellbore by one or more mud pump. Drilling mud as a wellbore treatment can bring cutting back to surface and stabilize the inner surface of the wellbore. In another example, the various wellbore treatments can include cementitious slurry and any variety of spacer fluids that are pumped down the wellbore by one or more cement pumps. Cement slurry as a wellbore treatment can be used to stabilize the wellbore, isolate subterranean formations, and form a barrier between formation fluids and a string of casing. In another scenario, the various wellbore treatments can include a fracturing slurry that is pumped down the wellbore by one or more fracturing pumps. Fracturing slurry as a wellbore treatment can be used to fracture the wellbore, create seams, and fill the fractures with a propping material, e.g., sand, to provide a pathway for the production of wellbore fluids. The various wellbore treatments can include a wide variety of fluids including fracturing slurry, acidizing fluid, cementing fluid, spacer fluids, resin compounds for formation consolidation or isolation, weighted fluids for well control and/or intervention, gravel packing fluids for sand placement, solvent for cleaning, water and/or completion fluids for tool placement, clean-out, circulating, jetting and other remediation treatments.
As used herein, a fracturing fleet comprises a fluid supply, a proppant supply, a blending system, a plurality of pumping units (e.g., fracturing pumps) fluidically coupled to a wellbore and the blending system by a fluid network. The fracturing fleet may be configured to provide a flowrate of wellbore treatment from the blending system to a wellbore per a pumping schedule. In some scenarios, the fracturing fleet can comprise a group of “clean” pumps and a group of “dirty” pumps to provide a blended wellbore treatment fluid to the wellbore.
As used herein, a “clean” pump may refer to a pump that is used for pumping fluid that substantially comprises water. Similarly, “clean” fluid may refer to fluid that contains a minimal amount or no proppant or sand. In certain instances, “clean” fluid may comprise additives such as salts, friction reducers, corrosion inhibitor, gelling agents, acidifying agents, chemical additives, or any other types of additives. “Dirty” fluid may refer to fluid that comprises sand or proppant, or fluid that is sand-laden. A “dirty” pump may refer to a pump that is used for pumping fluid that comprises sand or proppant. In certain instances, the dirty pumping units may pump fluids with a proppant concentration of 5% to 60%. As used herein, “dirty” fluid may also be referred to as “slurry”. In certain instances, “dirty” fluid may also comprise one or more additives, for example, the additives listed above with respect to the “clean” fluid. In certain instances, “low pressure” can refer to pressures less than 1,000 psi and “high pressure” can refer to pressures between 1,000 and 30,000 psi.
A health status of a pumping unit can be determined from direct measurement of mechanical properties of various mechanical systems within the pump equipment. For example, a pump monitoring system can utilize one or more sensors to measure a stress level of one or more components. The measured stress level can be compared to a baseline or nominal operating stress level to determine a health status. The sensors monitored within the pump equipment can include a position sensor, a strain gauge, a torque sensor, or combinations thereof. For example, the torque sensor can be a mechanical sensor positioned in the power end, transmission, and/or pressure pump to directly measure the torque, e.g., torque measurement, of a component of the pump equipment proximate to the torque sensor. The position sensor may be a physical sensor configured to measure the position, e.g., position measurement, corresponding to the movement of a driveshaft and/or crankshaft in the power end. The strain gauge may generate a strain signal, e.g., strain measurement, within one or more fluid chambers located in a fluid end of pressure pump. The position measurement and strain measure may be compared to one another to determine a health status of the pressure pump, e.g., stress level of a chamber with the valves closed. Likewise, the torque measurements, alone or with one or both of the position and strain measurements, may be compared to a baseline or nominal operating level to determine abnormal operational values of the pressure pump and may correspond to a condition of the component to which the torque sensor is proximate. The health status of the pressure pump and/or one or more components of the pressure pump may depend on the reliability of the torque sensor, the positional sensor, the stress sensor, or combinations thereof. Additionally, the comparison of the sensor measurements to the baseline may include additional evaluation steps after the measurements of the sensors are received, for example, dataset smoothing, averaging, parsing, cleaning, or combinations thereof. A direct measurement of one or more values without mechanical sensors is desirable.
Certain embodiments of the present disclosure are directed to systems and methods for monitoring one or more properties of a pressure pump utilizing drive power characteristics of an electrical motor. A pumping unit can comprise a variable frequency drive (VFD) coupled to a power source and the prime mover to control the speed and torque of the prime mover. The VFD can direct various parameters of the prime mover including motor speed, torque, output current, output voltage, and total power output. A unit controller can be communicatively coupled to the VFD to control one or more parameters and receive operational data and/or datasets. The unit controller can receive continuous and/or periodic datasets of the operational data and parameters. A monitoring process can determine one or more performance metrics, e.g., health status, by monitoring the continuous and/or periodic datasets from the VFD. For example, the VFD parameters of current and torque can be compared to one or more baselines to determine pump performance and component conditions. In a scenario, the VFD parameters can indicate a value of pumping efficiency. In another scenario, the VFD parameters can indicate the health of one or more components of the pumping equipment, e.g., a leaking valve.
Certain embodiments of the present disclosure are directed to systems and methods of monitoring the health of a pressure pump by monitoring VFD parameters and additional sensor signals. In some embodiments, one or more sensors can confirm a change in the monitored VFD parameters. For example, a decrease in one of the VFD parameters, e.g., torque, may indicate a leaking valve and a pressure sensor, e.g., pressure transducer, may signal a decrease in fluid chamber pressure to confirm the VFD parameter. In some embodiments, a pumping unit can be removed from service in response to a decrease in the heath status of the pumping unit. In some embodiments, one or more pumping units with a diminished health status can be replaced by one or more reserve pumping units with a greater health status.
Turning now to
A wellbore 112 for a treatment well 118 located at the remote wellsite 114 can be drilled with any suitable drilling system. A casing string 116 can be conveyed into the wellbore 112 by a drilling rig, a workover rig, an offshore rig, or similar structure. A wellhead 120 may be coupled to the casing string 116 at surface 122. The pumping unit 110, located offshore or on land, can be fluidically coupled to a wellhead 120 by a high pressure line 124. The wellbore 112 can extend in a substantially vertical direction away from the earth's surface 122 and can be generally cylindrical in shape with an inner surface 126. At some point in the wellbore path, the vertical portion 128 of the wellbore 112 can transition into a substantially horizontal portion 130. The wellbore 112 can be drilled through the subterranean formation 136 to a hydrocarbon bearing formation 132.
In some embodiments, the wellbore 112 can be completed with a cementing process that places a cement slurry between the casing string 116 and the wellbore 112 to cure into a cement barrier 152. The wellhead 120 can be any type of pressure containment equipment connected to the top of the casing string 116, such as a surface tree, a production tree, a subsea tree, a lubricator connector, a blowout preventer, or combination thereof. The wellhead 120 can include one or more valves to direct the fluid flow into or out of the wellbore 112 and one or more sensors that measure wellbore properties such as pressure, temperature, and/or flowrate data. Perforations 134 made during the completion process that penetrate the casing string 116 and hydrocarbon bearing formation 132 can enable the fluid in the hydrocarbon bearing formation 132 to enter the casing string 116.
In some embodiments, the pumping unit 110 comprises pumping equipment 138 and a unit controller 140. The pumping equipment 138 can comprise a pump 144, a prime mover 146, and a VFD 148. The prime mover 146 can be an electrical motor rotationally coupled to the pump 144. The VFD 148 may deliver electrical power, e.g., voltage and current, from a power source 150 to the prime mover 146. The pump 144 can be directed by the prime mover 146 via the VFD 148 and the unit controller 140 to deliver the treatment fluid at a desired flowrate and pressure to the wellbore 112 via the high pressure line 124. The pumping equipment 138 can receive a treatment fluid from a fluid source, e.g., a blender. In some embodiments, the pumping unit 110 can include a mixing system to blend the treatment fluid for the pumping equipment 138. The unit controller 140 may be a computer system suitable for communication with the service personnel, communication with a central controller, control of the pumping equipment 138, and control of the mixing system as will be described further herein.
The pumping unit 110 can follow a pump procedure with multiple sequential steps to deliver a wellbore treatment, e.g., proppant slurry, into the wellbore 112. The pump procedure, also referred to as a pump schedule, can comprise a series of steps or pumping stages that direct the placement of treatment fluid at a predetermined pressure, flowrate, treatment type, treatment density, or combinations thereof as a function of time and/or volume of treatment fluid. The series of steps of the pump procedure may be an estimation that concludes when a pumping operation objective is reached. For example, the pumping operation may end before the estimated completion or be extended past the estimated completion in response to the pumping operation objective being achieved. The pump procedure can include pressure testing of pumping equipment, pressure testing of piping network, treatment mixing, activation of downhole tools, and various treatment blends.
In one or more embodiments, a monitoring process, executing on the unit controller 140, can monitor the VFD 148 and provide an indicia of the health status of the pumping unit 110. The monitoring process can monitor one or more independent parameters and/or dependent parameters of the VFD 148. In some embodiments, the monitoring process can compare the one or more parameters of the VFD 148, e.g., motor torque, to a baseline parameter, e.g., calculated torque. In some embodiments, the monitoring process can compare one or more parameters of the VFD 148 to the output of a second VFD of a second pumping unit, e.g., a first motor torque to a second motor torque. The monitoring process may determine one or more conditions of the pump 144 based on the one or more parameters of the VFD 148. In a scenario, the monitoring process may determine a failing health status or one or more components within the pump 144. In a second scenario, the monitoring process may determine a pumping efficiency for the pump 144 based on hydraulic power output and total power input. In some embodiments, the monitoring process may determine a value of remaining life for one or more failing components by comparing one or more parameters of the VFD 148 to a database of operational history. In some embodiments, the monitoring process may utilize one or more sensors within the pump 144 to determine the location of one or more failing components.
The pumping unit 110 can be comprise any suitable pumping equipment 138 for the desired wellbore treatment. For example, the pumping equipment 138 can be one or more mud pumps for delivering drilling mud to the wellbore 112. In a second scenario, the pumping equipment 138 can comprise one or more cement pumps for delivering a cementitious slurry to the wellbore 112. In a third scenario, the pumping equipment 138 can include one or more fracturing pumps for delivering fracturing fluid or fracturing slurry to the wellbore 112. In some scenarios, the pumping equipment 138 can include a mixing system for blending the wellbore treatment, e.g., drilling mud, cementitious slurry, and/or fracturing fluid. In other scenarios, the pumping equipment 138 can be fluidically coupled to a wellbore treatment fluid source, e.g., a blender, and the wellbore 112.
In some embodiments, the wellbore servicing environment 100 can comprise additional completion equipment to direct the wellbore treatment fluids into a target location. For example, a fracturing plug, e.g., wellbore isolation plug, can be set or installed below a target location for a set of perforations, e.g., perforations 134, to isolate the wellbore 112 below the target location from pumping pressures. In some embodiments, one or more perforating guns can be utilized to produce additional perforations, in coordination with, the one or more fracturing plugs. In another scenario, a fracturing valve, e.g., production sleeve, can be coupled to the casing string 116 and installed at a target depth. The fracturing valve can be opened for the placement of a wellbore treatment and can closed afterward. Although one set or location for the perforations 134 is illustrated in the wellbore servicing environment 100, it is understood that the wellbore servicing environment can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of sets of perforations 134.
The unit controller 140 can receive data from the VFD 148 indicative of the pumping operation and/or condition of the pumping equipment 138. Turning now to
The wellbore treatment fluid can be transferred or pumped along a fluid path 220 that passes through the pump 144. The fluid path 220 can comprise an upstream fluid passage 222, a pump chamber 224, and a downstream fluid passage 226. The upstream fluid passage 222 can include a supply line 228, e.g., a suction line, fluidically coupled to an inlet chamber 244. In a context, the inlet chamber 244 can be fluidically coupled to the pump chamber, e.g., pump chamber 224, or more than one pump chamber. For example, the inlet chamber 244 can be an inlet manifold or suction header fluidically coupled to two or more pump chambers. Similarly, the downstream fluid passage 226 can comprise a high pressure line 230 and a discharge chamber 232. In some embodiments, the high pressure line 230 can be an embodiment of the high pressure line 124 illustrated in
The pump 144, also referred to as a fluid end, is illustrated as a cross-bore pump fluid end comprising the reciprocating element 212, a suction valve assembly 234, and a discharge valve assembly 236. A primary packing 238 may be one or more seals, e.g., O-rings and/or packing, in sealing engagement with the reciprocating element 212 and at least a portion of the element bore 218, e.g., a seal gland. The suction valve assembly 234 may comprise a valve body, a valve seat, and a closing mechanism, e.g., a spring. Likewise, the discharge valve assembly 236 may comprise a valve body, a valve seat, and a closing mechanism. Both the suction valve assembly 234 and the discharge valve assembly can be configured to have an open configuration and a closed configuration. In the closed configuration, the valve body can sealingly engage the valve seat to prevent fluid flow and/or a loss of pressure from above the valve assembly to below the valve assembly, for example, from the downstream fluid passage 226 to the pump chamber 224. The valve assembly can open, e.g., transition to the open configuration, in response to a pressure differential below the valve assembly, for example, pressure within the pump chamber 224 being greater than pressure within the discharge chamber 232. In some embodiments, the closing mechanism can align and bias the valve body into sealing engagement with the valve seat in response to the pressure above and below the valve assembly being approximately or nearly equal. When utilized in connection with a valve assembly, ‘open’ and ‘closed’ refer, respectively, to a configuration in which fluid can flow through the valve assembly (e.g., can pass between a valve body and a valve seat thereof) and a configuration in which fluid cannot flow through the valve assembly (e.g., cannot pass between a valve body and a valve seat thereof).
During the operation of the fluid end 144, the reciprocating element 212 can draw in treatment fluid through the suction valve assembly 234 and pressurize the treatment fluid within the pump chamber 224 until the discharge valve assembly 236 opens to expel the treatment fluid. The torque and rotational motion via the drive shaft 214 of the prime mover 146 can power the reciprocating element 212 to extend and retract along a direction or axis concentric with the element bore 218 of the fluid end 144. Forward strokes, also referred to as a discharge strokes, and return strokes, also referred to as suction strokes, are correlated to the movement of the reciprocating element 212 within the element bore 218. During a forward stroke, the reciprocating element 212 extends away from the crank shaft 210 and towards (or into) the fluid end 144. Before the forward stoke begins, the reciprocating element 212 is in a fully retracted position (also referred to as bottom dead center (BDC) with reference to the crank shaft 210), in which case the suction valve assembly 234 can be in a closed configuration having allowed fluid, e.g., wellbore treatment, to flow into the (e.g., high pressure) pump chamber 224. When discharge valve assembly 236 is in a closed configuration (e.g., under the influence of a closing mechanism, such as a spring, the high pressure in a discharge pipe or a manifold containing the discharge outlet 240 or discharge chamber 232) prevents fluid flow into discharge chamber 232 and causes pressure in the pump chamber 224 to accumulate upon stroking of the reciprocating element 212. When the reciprocating element 212 begins the forward or discharge stroke, the pressure builds inside the pump chamber 224 and acts as an opening force that results in positioning of the discharge valve assembly 236 in an open configuration, while a closing force (e.g., via a closing mechanism, such as a spring and/or pressure increase inside pump chamber 224) urges the suction valve assembly 234 into a closed configuration. As the reciprocating element 212 extends forward, fluid within the pump chamber 224 is discharged through the discharge outlet 240.
During a return or suction stroke, the reciprocating element 212 translates or retracts away from (or out of) the fluid end 144 and towards the crank shaft 210 of the pumping equipment 138. Before the return stroke begins, the reciprocating element 212 is in a fully extended position (also referred to as top dead center (TDC) with reference to the crank shaft 210), in which case the discharge valve assembly 236 can be in a closed configuration having allowed fluid to flow out of the pump chamber 224 and the suction valve assembly 234 is in a closed configuration. When the reciprocating element 212 begins and retracts towards the crank shaft 210, the discharge valve assembly 236 assumes a closed configuration, while the suction valve assembly 234 opens. As the reciprocating element 212 moves away from (or out of) the fluid end 144 during a return stroke, fluid flows through the suction valve assembly 234 and into the pump chamber 224.
While the foregoing discussion focused on a fluid end 144 comprising a single reciprocating element 212 disposed in a single element bore 218, it is to be understood that the fluid end 144 may include any suitable number of reciprocating elements. For example, the pumping equipment 138 may comprise a plurality of reciprocating elements 212 with corresponding reciprocating element bores 218 arranged in parallel and spaced apart along a planar arrangement. In such a multi-bore pump, each element bore 218A-Z may be associated with a corresponding reciprocating element 212A-Z and crank arm 216A-Z, and a single common drive shaft 214 from the prime mover 146 may drive each of the plurality of reciprocating elements 212A-Z and crank arms 216A-Z via a common crank shaft 210. Alternatively, a multi-bore pump may include multiple crankshafts 210A-Z, such that each crankshaft 210A-Z may drive a corresponding reciprocating element 212A-Z. Furthermore, the pumping equipment 138 may be implemented as any suitable type of multi-bore pump. In a non-limiting example, the pumping equipment 138 may comprise a Triplex pump having three reciprocating elements 212A-C (e.g., plungers or pistons) and associated reciprocating element bores 218A-C, discharge valve assemblies 236A-C and suction valve assemblies 234A-C, or a Quintuplex pump having five reciprocating elements 212A-E and five associated reciprocating element bores 218A-E, discharge valve assemblies 236A-E and suction valve assemblies 234A-E. Although the pump 144 is illustrated as a cross-bore pump fluid end, it is understood that the pump 144, e.g., fluid end, may be configured as an in-line, also called a concentric bore fluid end, a “T-bore” fluid end, a “X-bore” fluid end, a “Y-bore” fluid end, or any other suitable configuration of fluid end.
Drive power characteristics, e.g., torque and current, from the VFD 148 can determine one or more conditions of the pumping equipment 138. Turning now to
In some embodiments, the VFD 148 may include one or more processors and non-transient memory configured to output one or more dependent parameters based on algorithms executing in memory. The VFD 148 may receive feedback or determine feedback from one or more dependent parameters, for example motor speed. The VFD 148 can determine motor speed 320, output current 322, output torque 324, power factor 326, load percentage 328, and total power output 330 based on one or more dependent parameters of the VFD 148, the prime mover 146, the pumping operation, or combinations thereof. For example, the VFD 148 can determine the motor speed 320, typically given in revolutions per minute (RPM), as a function of the output frequency 310 and one or more primary mover characteristics, for example, number of poles within the motor. The VFD 148 can determine the output current 322, e.g., current delivered to the motor, in response to the power load, the output voltage 312, and output frequency 310. The VFD 148 can determine the output torque 324 as a function of the output power (watts) and the motor speed 320. An exemplary expression for the output torque 324 can be expressed in Equation 1:
wherein: T is the torque in Newton meters (Nm), P is the power in watts (W), and N is the speed in RPM. An exemplary expression for the power (P) can be expressed in Equation 2:
wherein: V is the root mean square (RMS) voltage, I is the RMS current (amperes), PF is the power factor (dimensionless) and u is the motor efficiency (dimensionless). The power factor 326 (PF as expressed in equation 2) can be a measure of how effectively the power, e.g., voltage and current, is being utilized and can be determined from the voltage and current waveforms. The load percentage 328 can be a measure of the capacity of the prime mover 146 and determined by comparing a current load to an operational limit of the prime mover 146. The total power output 330 can be the total power delivered to the prime mover 146 and can be derived from the voltage, current, and power factor 326. Although six dependent variables for the VFD 148 have been described, it is understood that the VFD 148 may have more dependent variables suitable for feedback to the unit controller 140, for example, energy consumption, drive status, alarm codes, DC bus voltage, braking resistor status, input phase balance, PID feedback, and any other dependent variable depending on the type of VFD, configuration of VFD, the prime mover 146, the pumping equipment, the pumping operation, or combinations thereof.
The monitoring process executing on the unit controller 140 can determine one or more conditions of the pumping equipment 138, e.g., pump performance and/or a heath status, by monitoring one or more drive power characteristics, e.g., independent and dependent parameters, of the VFD 148 such as motor torque 324 and output current 322. In some embodiments, the output torque 324 and/or output current 322 can be a function of the pumping pressure required for a stage (or pumping interval) of the pump schedule. Said another way, the amount of force required to generate the predetermined pumping pressure of the treatment fluid from the one or more reciprocating elements 212 can be a function of the output torque 324 supplied by the VFD 148 to the crank shaft 210 via the drive shaft 214 of the prime mover 146. The pumping pressure required for each step or stage of the pump procedure can be a function of one or more wellbore conditions, e.g., formation porosity. In some embodiments, the pumping pressure and flowrate, also referred to as the setpoint pressure and setpoint flowrate, for each stage of the pump schedule can be predetermined during a planning stage by a model, for example, a hydraulics fluid model. The type of pump, number of cylinders, and diameter of reciprocal element can vary depending on the type, version, and/or model number of pumping unit. Said another way, the calculated torque value 410 can be determined by the pressure setpoint from the pump schedule (for a model number of pump) for a given stage of the pumping operation. For example, a value of the output torque 324 can be determined by a pumping pressure required for a stage or step of the pumping operation as determined by a model during the planning stage. In some embodiments, the monitoring process can compare the value of the output torque 324 and/or output current 322 to the predetermined pumping pressure for given stage to determine one or more conditions of the pumping equipment 138. For example, a value of the motor torque 324 can change noticeably when the pumping equipment 138 develops a weak cylinder, e.g., pump chamber 224. A weak cylinder, e.g., pump chamber 224, can result from a failing or leaking suction valve assembly 234, discharge valve assembly 236, primary packing 238, or similar leak path out of the pumping equipment 138. Although motor torque 324 and output current 322 are described, other independent and/or dependent parameters of the VFD 148, for example, output voltage 312, motor speed 320, positional feedback, temperature, power output 330, power factor 326, vibration, or combinations thereof can determine one or more conditions of the pumping equipment 138.
In some embodiments, the output torque 324 can indicate overall performance of the pumping equipment 138 and a torque profile, e.g., a graph of torque versus time, can identify poorly performing specific cylinders and/or components. Turning now to
An upper limit 412 can be determined for the calculated torque value 410 for each stage of the pumping operation. The upper limit 412 can be a function of the mechanical health of the type of the pumping equipment, e.g., pumping equipment configuration. For example, an increase in friction or deformation of sliding parts can result in an increase in torque value 410. In some embodiments, the upper limit 412 can be a positive delta value representing mechanical failure added to the calculated torque value 410. In some embodiments, the upper limit 412 can include a threshold value determined by historical value. For example, the historical value can be determined from maintenance records, pumping operation reports, job reports, or combinations thereof. In some embodiments, the upper limit 412 can be a percentage increase applied to the torque value 410. For example, the upper limit 412 can be an increase of 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, or any value within a range of 1% to 25%.
A lower limit 414 can be determined for the calculated torque value 410 for each stage of the pumping operation. The lower limit 414 can be a function of the mechanical health of the pumping equipment 138 located along the fluid path 220, for example, the upstream fluid passage 222, the suction valve assembly 234, the pump chamber 224, the primary packing 238, the discharge valve assembly 236, the downstream fluid passage 226, or combinations thereof. In some embodiments, the lower limit 414 can be a negative delta value representing a loss of sealing ability added to the calculated torque value 410. The mechanical health status of the pump equipment 138 can be rated positive or “good performance” in response to the pumping equipment 138, e.g., primary packing 238, maintaining the sealing ability, e.g., holding pressure. The mechanical health status of the pump equipment 138 can be rated negative or “poor performance” in response to one or more components of the pumping equipment 138 located along the fluid path 220, e.g., primary packing 238, losing the sealing ability, e.g., losing pressure. For example, a loss of sealing ability from one or more components of the pump equipment 138 can result in a loss of pumping pressure from the pump chamber 224 (e.g., discharge stroke), a loss of suction pressure to the pump chamber 224 (e.g., suction stroke), or both during pumping operations. In some embodiments, the lower limit 414 can be a percentage decrease applied to the torque value 410. For example, the lower limit 414 can be an decrease of 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, or any value within a range of 1% to 25%.
Continuing with
As further illustrated in
Also illustrated in
Drive parameters can also be used in conjunction with other sensors such as stroke/crank sensor (e.g., position sensor) to help pinpoint under-performing components—an example of which would be using a crankshaft or plunger-stroke position sensor in conjunction with torque profile to determine which cylinder of a multi-cylinder pump has an issue. Referring again to
The one or more positional sensors may include a rotary encoder 250, crankshaft sensor 252, stroke sensor 254, or combinations thereof. The rotary encoder 250, also referred to as a shaft encoder, may provide data on the angular motion of the drive shaft 214 including position, speed, distance, or any combination thereof. The rotary encoder 250 may be an absolute rotary encoder, an incremental encoder, or any electro-mechanical device that converts angular position or motion to analog and/or digital signals. The crankshaft sensor 252 can be an inductive sensor, a hall effect sensor, magneto-resistive sensor, optical sensor, or any other type of sensor configured to determine the position and speed of the crankshaft. For example, the crankshaft sensor 252 can determine an angle Θ relative to a TDC and/or BDC location of the crank shaft 210. The stroke sensor 254 can be coupled to each of the reciprocating elements 212 to provide data on the location and speed of each reciprocating elements 212 relative to the corresponding element bore 218. Although three types of sensor located in three distinct locations are disclosed, it is understood that that any variety of positional sensor configured to detect or confirm the position of each reciprocating element 212 and/or valve position located along the fluid path 220 to measure valve effectiveness and timing can be utilized.
A comparison of drive parameters of a group of pumping units can also clearly indicate issues with pump performance and/or pump health status. When multiple pumping units are being used, e.g., a fracturing fleet, the drive parameters from each VFD can be compared to each other to detect issues by comparing output current 322 or output torque 324. For instance, a pumping unit 110 with a failing pump 144 can have a torque requirement, e.g., torque output 324, that is different from the rest of the group of pumping units running at the same pressure setpoint. Turning now to
In the exemplary torque profile 430, motor torque 438 can begin operation within the normal operating range “A” as shown with line 438A and at some value of time the motor torque 438 can drop below the lower limit 414 as illustrated with a portion of motor torque 438B. The difference of the motor torque 438B compared to motor torques 440, 442, 444, 446 can indicated a health status of the pump equipment, e.g. pump equipment 138, for pumping unit 110A. In another scenario, the motor torque 438 can display an oscillating curve comprising repetitive torque peaks 438C and torque valleys 438D indicative of the pressure performance of each pump cylinder, e.g., each pump chamber 224. As previously described, one or more positional sensors, e.g., sensor 254, located in one or more locations within the pump equipment 138 can provide the relative position of each of the reciprocating elements 212 to the corresponding element bore 218 for each pump chamber 224 and may identify the cylinder losing pressure, e.g., generating the torque valley 438D.
Health prediction of pumping equipment using motor torque 324 and/or output current 322 can be utilized predict remaining useful life of pumping systems and components. As component wear occurs, drive parameters from the VFD 148 may change and these changes can be tracked and extrapolated in time to estimate remaining life or pending maintenance. Parts, components, and/or assemblies can be utilized until a reasonable life remains with planned maintenance instead of running the parts to failure. Turning now to
In some embodiments, one or more databases can be utilized to track the amplitude and frequency of the oscillations, e.g., peaks 438E and valleys 438F of the torque profile 450. The database can track the amplitude and frequency at a given flowrate and pressure of the pumping operation. The database can include the output pressure and flowrate that corresponds to the oscillations. Likewise, the database can track the rate of change, e.g., progression, of the amplitude and frequency as the one or more components continue operation. The monitoring process can determine a remaining life value based on i) the amplitude and frequency, ii) the output pressure and flowrate, iii) the rate of change of the amplitude, iv) a comparison to the historical database, v) or combinations thereof. In some embodiments, an error rate of the prediction of remaining life of the pumping equipment 138 can decreased with an increasing size of the database. For example, using the continuously growing historical database, a correlation can be developed between amplitude, frequency of torque oscillations (at a given rate and pressure) vs. remaining healthy life or damage of amplitude/sealing capability of the various components such as suction and discharge valves.
Although 5 pumping units are illustrated, it is understood that there may be 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, or any number of pumping units. Although the five motor torques, e.g., motor torque 440, are compared to each other, it is understood that the five motor torques can be compared to a calculated torque value, e.g., calculated torque value 410. In some embodiments, the upper limit 412 and lower limit 414 can be determined from a calculated torque value, e.g., calculated torque value 410, that is determined or derived from the pumping pressure for a given stage.
Drive parameters can also be used to monitor overall system performance of a pumping unit. An example would be monitoring torque or motor current stability. Under normal conditions, these drive parameters will remain reasonably stable (often responding only to the pump volumetric output profile). But in some instances of system instability, motor current and torque oscillations will be clearly apparent, indicating issues. Simple first and second order derivative of those parameters can be used to alert the operators or automatic prevention action can be implemented if the instability is of higher magnitude.
Sensor data can be utilized with the monitoring of dependent parameters and independent parameters of VFD 148 to provide a confirmation of indications of pump health status and help to prevent false indications. In some embodiments, the pump 144 may include one or more sensors located along the fluid path 220. Returning to
Returning to
In some embodiments, one or more fluid sensors coupled to the upstream fluid passage 222 of the fluid path 220 can identify one or more conditions indicative of fluid cavitation. For example, the first fluid sensor 258 fluidically coupled to the inlet chamber 244 and the fourth fluid sensor 266 coupled to the supply line 228 may be a pressure transducer and/or flowrate sensor configured to monitor the one or more fluid characteristics including fluid pressure, fluid flowrate, percent fill of each pump chamber 224, percent fill of each inlet chamber 244, volumetric efficiency of the pump 144, or combinations thereof. The comparison of the data from the first fluid sensor 258 and/or fourth fluid sensor 266 to can confirm a condition of fluid cavitation within the upstream fluid passage 222 as determined by the monitoring process based on the output torque 324, output current 322, or any other combination of independent parameters or dependent parameters from the VFD 148.
In some embodiments, the VFD 148 may receive sensor signals from one or more motor sensors 242 coupled to the prime mover 146. For example, the sensor 242 may be temperature sensor that provides the operating temperature of the prime mover 146 and/or a vibration sensor, e.g., an accelerometer, that provides a measurement of vibration of the prime mover 146 to the VFD 148 and/or unit controller 140.
Although the power section of the pumping equipment 138 is described as comprising the VFD 148 communicatively coupled to the prime mover 146 that is rotationally coupled to the crank shaft 210, it is understood that the VFD 148 may also be described as an adjustable frequency drive, an adjustable speed drive, a variable speed drive, an AC drive, a micro drive, an inverter drive, or any other suitable controller for an electric motor configured to control speed and torque by varying the frequency of the input electricity, e.g., voltage and current. The VFD 148 is a solid-state power conversion system comprising a rectifier bridge converter, a direct current link, and an inverter and may be configured as a voltage source inverter (VSI) drive, current source inverter (CSI) drive, six-step inverter drive, load commutated inverter (LCI) drive, matrix converter (MC), cycloconverter, or doubly fed slip recovery system. The configuration of the VFD 148 can be dependent on the prime mover 146, the power source 150, the operating environment, or combinations thereof. For example, a VFD is typically used with a three-phase induction motor, however any type of electric motor may be utilized including single-phase motors, synchronous motors, axial flux motors, permanent magnet motors, or any combination thereof.
In some embodiments, the unit controller 140 can receive data indicative of the pumping operation from the VFD 148 and/or one or more sensors, e.g., torque sensor 250, coupled to the pump equipment 138. The data may be a periodic dataset, a constant stream of data, or combinations thereof. The data may be stored within memory, a data storage location, a database, a network location, a local storage location, a remote storage location, or combinations thereof. In a scenario, the data may be stored in non-transitory memory within the unit controller 140. In a second scenario, the data may be stored in a local storage location, e.g., secondary storage. In a third scenario, the data may be stored in a local and/or remote network location, e.g., storage drive. In a fourth scenario, the data may be transmitted via mobile communications to a cloud based network location, e.g., virtual storage location on a mobile network. Although the data is described as being stored, it is understood that the unit controller may access the data in any suitable manner, e.g., send, receive, access, and/or retrieve the data.
The pumping unit 110 can be part of a typical fracturing fleet comprising a plurality of pumping units fluidically couple to a wellbore via a manifold and working in concert to place a proppant slurry into a subterranean formation. Turning now to
The treatment fluid, e.g., fracturing fluid, can be blended by various pumping equipment of the fracturing fleet and delivered to the plurality of pumping units 522 by the fluid network 524. The fracturing fluids are typically a blend of friction reducer and water, e.g., slick water, with some concentration of proppant, e.g., sand. In some cases, a carrier fluid (e.g., water, a gelling agent, optionally a friction reducer, and/or other additives) may be created in a hydration blender 514 from the water supply unit 512 and gelling chemicals from the chemical unit 516. When slick water is used, the hydration blender 514 can be omitted. The proppant is added at a controlled rate to the carrier fluid or slick water in a mixing blender 520 that is fluidically coupled to the fluid network 524. The treatment fluid can be distributed to the pumping units 522A-H via the supply line 228 (as shown in
A control van 510 can be communicatively coupled (e.g., via a wired or wireless network) to the fracturing fleet, e.g., plurality of pumping units 522A-H. A managing process 536 executing on computer system 532 within the control van 510 can establish unit level control over the various equipment of the fracturing fleet including the plurality of pumping units 522A-H, the blender 520, the proppant storage 518, the water supply unit 512, the hydration blender 514, the chemical unit 516, and various sensors and remote operated valves within the fluid network 524. The managing process 536 can direct the pumping operation and receive periodic datasets indicative of the pumping operation.
In some scenarios, the managing process 536 can direct the pumping operation via the VFD, e.g., VFD 148 of
Although the managing process 536 and monitoring process are described as executing on a computer system 532, it is understood that the computer system 532 can be any form of a computer system such as a server, a workstation, a desktop computer, a laptop computer, a tablet computer, a smartphone, or any other type of computing device. The computer system 532 can include one or more processors, memory, input devices, and output devices, as described in more detail further hereinafter.
In an embodiment, the monitoring process can alert the service crew, the managing process 536, or both of a health status of one or more pumping units. For example, the monitoring process may determine a “poor” health status for the pump equipment of pumping unit 522A in response to the VFD parameters of pumping unit 522A. In some embodiments, the managing process 536 may slow the pump rate of pumping unit 522A by decreasing the motor speed 320 of the VFD. For example, the monitoring process may identify cavitation as the source of the “poor” health status of the pumping unit 522A and the cavitation condition may diminish or disappear in response to slowing the pumping speed. In some embodiments, the managing process 536 may cease pumping operation of the pumping unit 522A and isolate the pumping unit 522A from the fluid network 524 or replace the pumping unit 522A with a fresh pumping unit held in reserve. In some embodiments, the managing process 536 may redistribute the pumping load, e.g., flowrate, to the remaining pumping units 522B-H. In some embodiments, the managing process 536 may distribute the pumping load of pumping unit 522A to the replacement pumping unit.
The pumping unit 110 can be a dual pumping unit of a blended fracturing fleet comprising a plurality of pumping units fluidically coupled to a wellbore via a high pressure manifold and working in concert to place a proppant slurry into a subterranean formation. Turning now to
The dual pumping units of the fracturing fleet 600 can be communicatively coupled to a control center 636. The control center 636 comprises a managing process executing on one or more system controllers, e.g., computer systems, configured to direct the pumping operation of each of the dual pumping units of the fracturing fleet 600 while receiving periodic datasets indicative of the pumping operation. For example, the control center 636 can direct the dirty pumping units 612 to pump a treatment fluid into the wellbore 610 at a desired flowrate and pressure with the dirty blender 614 suppling the desired concentration of proppant slurry to the dirty pumping units 612 via the low pressure manifold 616. The controller within the control center can be communicatively connected to a unit controller, e.g., unit controller 140 of
The managing process can direct the pumping operation with communication to the unit controller of each pumping unit. The unit controller and/or the system controller can direct the pumping operation via the VFD, e.g., VFD 148 of
The blender unit 614 can mix liquid, e.g., water, with various chemicals and a proppant, e.g., sand, to produce a wellbore treatment. The wellbore treatment can be produced by mixing proppant, e.g., sand, from a proppant supply unit 644 to produce a desired concentration of proppant within the wellbore treatment. The dirty blender 614 can be fluidically coupled to the low pressure manifold 616 by a supply line 646.
The dual pumping units of the fracturing fleet 600 can include a VFD 148 and a plurality of sensors to provide periodic datasets to the unit controller 140 within each dual pumping unit and to the system controller within the control center 636. For example, the VFD 148 within each dual pumping unit can communicate a continuous or periodic dataset to the unit controller 140, the system controller, or both. In another example, each dual pumping unit, e.g., dual pumping unit 620 can have a flowrate sensor coupled to the pump 620A inlet, a pressure sensor coupled to the pump 620A outlet, and a position sensor coupled to the motor 620M. The plurality of sensors can provide periodic datasets of the pumping operation and of a status of each of the dual pumping units, e.g., pumping unit 620, to the system controller within the control center 636. The sensors can be communicatively connected to the unit controller 140 and/or the system controller within the control center 636 by wired communication, wireless communication, or combinations thereof.
In some embodiments, one or more sensors can be fluidically coupled with the wellbore 610, for example, a sensor can be coupled to a wellhead, a production tree, a fracturing tree, a wellhead isolation device, or combinations thereof. The sensors can be configured to measure one or more wellbore environment properties such as wellbore pressure and wellbore temperature. The sensors can be configured to measure wellbore treatment fluid properties, such as, density, flowrate, pressure, and temperature. In some embodiments, the one or more sensors can be located within the wellbore 610, for example, proximate to the formation, e.g., formation 132 of
In some embodiments, the first pumping unit group 612 can be an example of a typical fracturing fleet, e.g., fracturing fleet 500, with a dirty blender 614 supplying a proppant slurry with a desired proppant concentration to a plurality of pumping units, e.g., dirty pumping units 522, configured to pump the proppant slurry at a desired pressure and flowrate to a wellbore 610. In some embodiments, the first pumping unit group 612 can be coupled to two or more wellbores, e.g., wellbore 610, to perform a sequential or simultaneous fracture of the two or more wellbores.
The exemplary fracturing fleet 600 can comprise a second pumping unit group 650 configured to pump a clean fluid to the wellbore 610. The second group of pumping units, also referred to as clean pumping units 650, can be coupled to a blender unit 654 providing a clean fluid by a low pressure manifold 656 via a supply line 658. A water supply unit 680 and a chemical unit 682 can be fluidically coupled to the blender unit 654, also referred to as a clean blender. The clean pumping units 650 can be fluidically coupled to the wellbore 610 by a high pressure manifold 660 and a high pressure line 662. The low pressure manifold 656 and the high pressure manifold 660 can be combined into a single fluid network, e.g., fluid network 524. The second pumping unit group 650, e.g., the clean pumps, can include dual pumping units 670, 672, 674, and 676. Each of the dual pumping units, e.g., pumping unit 670, can comprise a prime mover “M”, e.g., prime mover 146, rotationally coupled and releasably coupled to a first pump “A”, e.g., first pump 144A, and a second pump “B”, e.g., second pump 144B. As previously described, the pumps of each dual pumping unit are labeled A, B and the prime mover is labeled M. For example, the term pump 670A will refer to the first pump “A” powered by the prime mover “M” of the pumping unit 670.
The fracturing fleet 600 can combine the clean fluid from the clean pumping units 650 with the dirty fluid, e.g., proppant slurry, from the dirty pumping units 612 at the wellbore 610. In some embodiments, the high pressure line 662 from the high pressure manifold 660 of the clean pumping units 650 and the high pressure line 648 from the high pressure manifold 618 of the dirty pumping units 612 can be coupled a fluid junction 678. The fluid junction 678 can be a fluid control component or could be a part of a fracturing manifold or wellhead coupled to the wellbore 610. In some embodiments a pressure and flowrate sensor can be located between the high pressure manifold 660 of the clean pumping units 650 and the fluid junction 678, for example, along the high pressure line 662. In some embodiments a pressure and flowrate sensor can be located between the high pressure manifold 618 of the clean pumping units 650 and the fluid junction 678, for example, along the high pressure line 648. The system controller within the control center 636 can establish a flowrate of proppant slurry with a desired proppant concentration at the fluid junction 678 and/or the wellbore 610 by controlling the supply of clean fluid from the clean pumping units 650 and the supply of proppant slurry from the dirty pumping units 612.
In some embodiments, the monitoring process can alert the service crew, the managing process, or both of a health status of one or more pumping units. For example, the monitoring process may determine a “poor” health status for the pump equipment of pumping unit 620 in response to the VFD parameters of pumping unit 620. In some embodiments, the managing process may slow the pump rate of pumping unit 620 by decreasing the motor speed 320 of the VFD. For example, the monitoring process may identify cavitation as the source of the “poor” health status of the pumping unit 620 and the cavitation condition may diminish or disappear in response to slowing the pumping speed. In some embodiments, the managing process may cease pumping operation of the pumping unit 620 and disconnect the pump with the “poor” heath status, e.g., pump 620A, and restart the pumping unit 620 operating with only one pump 620B. In some embodiments, the managing process may cease pumping operation of the pumping unit 620 and isolate the pumping unit 620 from the fluid network or replace the pumping unit 620 with a fresh pumping unit held in reserve. In some embodiments, the managing process may redistribute the pumping load, e.g., flowrate, to the remaining pumping units 622, 624, 626. In some embodiments, the managing process may distribute the pumping load of pumping unit 620 to the replacement pumping unit.
The computer system at the wellsite may be a computer system suitable for communication and control of the pumping equipment, e.g., a fracturing fleet 500. The pumping operation described in
In some embodiments, the computer system 700 may comprise a DAQ card 720 for communication with one or more sensors. The DAQ card 720 may be a standalone system with a microprocessor 722, memory, and one or more applications executing in memory. The DAQ card 720, as illustrated, may be a card or a device within the computer system 700. In some embodiments, the DAQ card 720 may be combined with the input output devices 708. The DAQ card 720 may receive one or more analog inputs 724, one or more frequency inputs 726, and one or more Modbus inputs 728. For example, the analog input 724 may include a volume sensor, e.g., a tank level sensor. For example, the frequency input 726 may include a flow meter, i.e., a fluid system flowrate sensor. For example, the Modbus input 728 may include a pressure transducer. The DAQ card 720 may convert the signals received via the analog input 724, the frequency input 726, and the Modbus input 728 into the corresponding sensor data. For example, the DAQ card 720 may convert a frequency input 726 from the flowrate sensor into flowrate data measured in gallons per minute (GPM).
In some embodiments, the computer system 700 can receive data indicative of the pumping operation from the VFD 148 and/or one or more sensors, e.g., torque sensor 250, via the DAQ card 714 and/or the input output devices 708. The data may comprise periodic datasets, a constant stream of data, or combinations thereof. The data may be stored within memory 704, the secondary storage 706, a network location via the network devices 710, a remote storage location, or combinations thereof. In some embodiments, the computer system 700 can be communicatively coupled with a mobile communication network via the long range radio transceiver 712, e.g., a mobile network provider. In some embodiments, the computer system 700 can be communicatively coupled to a cloud based network location, e.g., a virtual computer system on a mobile network. In some embodiments, the computer system 700 can transmit/receive data and/or instructions from the cloud based network locations.
The following are non-limiting, specific embodiments in accordance with the present disclosure.
A first embodiment, which is A system of a pumping unit, comprising a variable frequency drive (VFD) communicatively coupled to a prime mover; a pump rotationally coupled to the prime mover; a unit controller communicatively coupled to the VFD, the unit controller comprising a processor and a non-transitory memory and configured to: control a pumping operation of the pumping unit via control of the prime mover; receive a data stream of one or more parameters from the VFD indicative of the pumping operation; compare the one or more parameters to a lower limit threshold; and modify the pumping operation in response to the lower limit threshold exceeding the one or more parameters.
A second embodiment, which is the method of the first embodiment, further comprising one or more sensors configured to measure data indicative of a pumping operation, and wherein the one or more sensor are communicatively coupled to the unit controller.
A third embodiment, which is the method of the first or second embodiment, wherein the one or more sensors comprise a positional sensor, a pressure sensor, a flowrate sensor, a vibration sensor, a density sensor, or combinations thereof.
A fourth embodiment, which is the method of any of the first through the third embodiments, wherein the unit controller is further configured to: compare the one or more parameters to an upper limit threshold.
A fifth embodiment, which is the method of any of the first through the fourth embodiments, wherein the one or more parameters comprise i) output torque, ii) output current, iii) motor speed, iv) power factor, v) load percentage, vi) total power output, vii) output frequency, viii) output voltage, ix) acceleration rate, x) deceleration rate, xi) PID setpoint, or xii) combinations thereof.
A sixth embodiment, which is the method of any of the first through the fifth embodiments, further comprising determining an upper limit threshold by applying a positive delta value to a calculated parameter value; determining a the lower limit threshold by applying a negative delta value to the calculated parameter value; and determining a normal operation range of the pump that is a function of the upper limit threshold and the lower limit threshold, wherein the upper limit threshold is greater than the calculated parameter value, and wherein the lower limit threshold is less than the calculated parameter value.
A seventh embodiment, which is the method of any of the first through the sixth embodiments, wherein the calculated parameter value is determined by i) a pressure setpoint, ii) a flowrate setpoint, iii) a treatment fluid, or iv) combinations thereof in a pump schedule.
An eighth embodiment, which is the method of any of the first through the seventh embodiments, wherein the calculated parameter value is an average parameter value of a group of two or more pumping units performing the pumping operation.
A ninth embodiment, which is the method of any of the first through the eighth embodiments, further comprising: a high pressure line fluidically coupling the pumping unit to a wellbore; a wellbore treatment fluid for the pumping unit to pump into the wellbore; and wherein the wellbore treatment fluid is selected from a group consisting of a drilling mud, a fracturing slurry, a cementitious slurry, a spacer fluid, a completion fluid, an acidizing fluid, a gravel packing fluid, a resin compound, and water.
A tenth embodiment, which is the method of any of the first through the ninth embodiments, wherein: the pump is a fluid end, a positive displacement pump, a plunger pump, a piston pump, a progressive cavity pump, a gear pump, a screw pump, a lobe pump, a double screw pump, an impeller and diffuser, a centrifugal pump, a multistage centrifugal pump, a turbine, or any other type of pump suitable for pressurizing fluids; and wherein the prime mover is an electrical motor.
An eleventh embodiment, which is the method of any of the first through the tenth embodiments, further comprising a second pump rotationally coupled to the prime mover.
A twelfth embodiment, which is a method of monitoring a condition of a pumping unit pumping a wellbore treatment fluid into a wellbore penetrating a formation, comprising: pumping the wellbore treatment fluid with the pumping unit comprising a unit controller communicatively coupled to a variable frequency drive (VFD) that is communicatively coupled to a prime mover that is rotationally coupled to a pump; retrieving, by the unit controller comprising a processor and non-transitory memory, a data stream indicative of a pumping operation via one or more parameters from the VFD; comparing the one or more parameters to a lower limit threshold; and modifying the pumping operation in response to the lower limit threshold exceeding the one or more parameters.
A thirteenth embodiment, which is the method of any the twelfth embodiments, wherein the one or more parameters comprise i) output torque, ii) output current, iii) or both.
A fourteenth embodiment, which is the method of any of the twelfth through the thirteenth embodiments, wherein modifying the pumping operation comprises i) slowing a pumping speed of the pumping unit or stopping the pumping unit.
A fifteenth embodiment, which is the method of any of the twelfth through the fourteenth embodiments, further comprising determining, by the unit controller, a calculated parameter for the VFD corresponding to i) a setpoint pressure, ii) a setpoint flowrate, iii) a treatment fluid density, or iv) combinations thereof, of a pump schedule; and determining, by the unit controller, the lower limit threshold for the one or more parameters of the VFD by applying a negative delta to the calculated parameter.
A sixteenth embodiment, which is the method of any of the twelfth through the fifteenth embodiments, further comprising comparing the one or more parameters to an upper limit threshold; and modifying the pumping operation in response to the one or more parameters exceeding the upper limit threshold.
A seventeenth embodiment, which is the method of any of the twelfth through the sixteenth embodiments, further comprising (i) transporting the pumping unit to a wellsite; and (ii) fluidically coupling the pumping unit to the wellbore.
A eighteenth embodiment, which is the method of any of the twelfth through the seventeenth embodiments, further comprising (i) transporting the pumping unit to a wellsite, wherein the pumping unit is a first pumping unit; (ii) fluidically coupling the first pumping unit to a fluid network comprising at least a second pumping unit; (iii) fluidically coupling the fluid network to a treatment fluid source and the wellbore at the wellsite; (iv) communicatively coupling a system controller to each of the pumping units, wherein a managing process executing on the system controller directs the pumping operation and receives data indicative of the pumping operation; and (v) wherein modifying the pumping operation comprises stopping, by the system controller, the pumping operation of the first pumping unit; (vi) isolating the first pumping unit from the fluid network; and (vii) replacing the first pumping unit with a third pumping unit held in reserve.
A nineteenth embodiment, which is a method of monitoring a condition of a pumping unit pumping a wellbore treatment fluid into a wellbore penetrating a formation, comprising: directing a pumping operation via a system controller communicatively coupled to the two or more pumping units, wherein each of the two or more pumping units comprise a unit controller communicatively coupled to a variable frequency drive (VFD) that is communicatively coupled to a prime mover that is rotationally coupled to a pump; pumping the wellbore treatment fluid via the two or more pumping units into the wellbore; retrieving, by the unit controller comprising at least one processor and non-transitory memory, a data stream indicative of the pumping operation via one or more parameters from the VFD; determining, by the system controller comprising at least one processor and non-transitory memory, a calculated parameter value by averaging a first parameter value from each of the two or more pumping units; determining, by the system controller, a lower limit threshold by applying a delta value to the calculated parameter value; comparing the first parameter value of each of the two or more pumping units to the lower limit threshold; and identifying a failing pump of the two or more pumping units in response to the lower limit threshold exceeding the first parameter value of the failing pump.
A twentieth embodiment, which is the method of the nineteenth embodiments, further comprising confirming a poor health status of one or more components of the failing pump by comparing periodic pumping data from one or more sensors to the first parameter value of the failing pump.
A twenty-first embodiment, which is the method of any of the nineteenth through the twentieth embodiments, further comprising determining a value of remaining pumping life of the failing pump in response to confirming the one or more components.
A twenty-second embodiment, which is the method of any of the nineteenth through the twentieth-first embodiments, wherein the first parameter value is i) output torque or ii) output current.
A twenty-third embodiment, which is the method of any of the nineteenth through the twenty-second embodiment, wherein modifying the pumping operation comprises i) reducing a motor speed or ii) stopping the pump.
A twenty-fourth embodiment, which is the method of any of the nineteenth through the twenty-third embodiment, further comprising: (i) transporting the two or more pumping units to a wellsite; (ii) fluidically coupling two or more pumping units to a fluid network; and (iii) fluidically coupling the fluid network to a treatment fluid source and the wellbore.
A twenty-fifth embodiment, which is the method of any of any of the nineteenth through the twenty-fourth embodiments, further comprising retrieving, by the system controller, periodic pumping data indicative of the pumping operation, and wherein the periodic pumping data includes an indication of pumping performance of the pumping unit.
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. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. 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.
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 an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and 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.
