Patent Grant
11834940
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. When one pump fails, operators can compensate by manually adjusting the remaining pumps to maintain the desired concentration and flowrate of proppant into the downhole formation. An increase in pumping properties to one or more of the remaining pumps may be detrimental based on the health of the remaining pumps. A method of balancing the pumping properties among multiple pumps 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 two pumps 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 wellbore treatment can be any fluid pumped into a wellbore during the 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 down the wellbore by mud pumps. 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 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 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 “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.
Certain embodiments of the present disclosure are directed to systems and methods for balancing the pumping load across multiple pumping units simultaneously fracturing one or more wellbores. In certain instances, it may be desirable to have independent control of the one or more pumping units, for example, both clean pumping units and dirty pumping units, to maintain a constant rate of proppant-laden fluid delivered to the wellbore. Adjusting the pumping load of individual pumping units downstream of the blender based on a number of weighted factors, also referred to as operational factors, may provide more reliability and fewer maintenance events while maintaining the amount and pressure of fracturing fluid pumped into a given well bore. Balancing the pumping load on a plurality of pumping units may allow for the reduction in pumping load and eventual replacement of a pump with decreasing pumping performance.
A balancing process can remove a pump, e.g., fluid end, from a pumping operation while compensating for the loss of pumping flowrate with the pumps, e.g., fluid ends, of the remaining pumping units. In some embodiments, the balancing process can stop the pumping operation of a selected pumping unit, decouple a pump, e.g., fluid end, with decreased pumping performance from the prime mover and return the selected pumping unit to the pumping operation utilizing the other pump coupled to the prime mover. In some embodiments, the balancing process can remove and replace a selected pumping unit with a pumping unit held in reserve.
Turning now to
The wellbore 112 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 (not shown). 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 bore 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 131 to a hydrocarbon bearing formation 132. Perforations 133 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, also called a fracturing unit, comprises a pumping system 138 and a unit controller 140. The pumping system 138 comprises a first pump 144, a second pump 146, and a prime mover 148. The prime mover 148 can be an electrical motor rotationally coupled to the first pump 144 and the second pump 146. The pumping system 138 can receive a fracturing fluid from a fluid source, e.g., a blender, and can deliver the fracturing fluid to the wellbore 112 via the high pressure line 124. The unit controller 140 may be a computer system suitable for communication with the service personnel, communication with a central controller, and control of the pumping system 138 as will be described further herein.
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, production tree, subsea tree, lubricator connector, blowout preventer, or combination thereof. The wellhead 120 can include one or more valves to direct the fluid flow from the wellbore 112 and one or more sensors that measure wellbore properties such as pressure, temperature, and/or flowrate data.
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 pumping unit 110 can be fluidically coupled to a wellbore treatment fluid source, e.g., a blender (not shown). The pumping unit 110 can deliver a wellbore treatment fluid to the hydrocarbon bearing formation 132 via the perforations 134. The pumping unit 110 can place the wellbore treatment fluid with sufficient volume and pressure to split or “fracture” the formation 132 along veins or planes extending from the wellbore 112. In some embodiments, the fracturing fluid comprises propping agents, also referred to as proppant, that are deposited into the fractures, e.g., veins, to support and/or prevent the fractures from closing. These proppants, e.g., sand and/or ceramic beads, can create a highly permeable fluid pathway to the inner bore of the casing string 116 via the perforations 134.
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 pumping unit 110 can be part of a fracturing fleet, also referred to as a fracturing spread, 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 fracturing units of the fracturing spread 200 can be communicatively coupled to a control center 236. The control center 236 comprises one or more controllers, e.g., computer systems, configured to direct the pumping operation of each of the fracturing units of the fracturing spread 200 while receiving periodic datasets indicative of the pumping operation. For example, the control center 236 can direct the dirty pumping units 212 to pump the proppant slurry into the wellbore 210 at a desired flowrate and pressure with the dirty blender 214 to suppling the desired concentration of proppant slurry to the dirty pumping units 212 via the low pressure manifold 216. The controller within the control center can be communicatively connected to a unit controller, e.g., unit controller 140 of
The blender unit 214 can mix liquid, e.g., water, with various chemicals and a proppant, e.g., sand, to produce the proppant slurry. In some embodiments, the blender unit 214, also referred to as the dirty blender, can produce a gelled water by mixing water from a water supply unit 240 and various chemicals from a chemical unit 242. The proppant slurry can be produced by mixing proppant from a proppant supply unit 244 to produce a desired concentration of proppant within the proppant slurry. The dirty blender 214 can be fluidically coupled to the low pressure manifold 216 by a supply line 246.
The fracturing units of the fracturing spread 200 can include a plurality of sensors to provide periodic datasets to the unit controller within each fracturing unit and to the controller within the control center 236. For example, each pumping unit, e.g., pumping unit 220 can have a flowrate sensor coupled to the pump 220A inlet, a pressure sensor coupled to the pump 220A outlet, and a position sensor coupled to the motor 220M. The plurality of sensors can provide periodic datasets of the pumping operation and of a status of each of the pumping units, e.g., pumping unit 220, to the controller within the control center 236. The sensors can be communicatively connected to the unit controller and/or the controller within the control center 236 by wired communication, wireless communication, or combinations thereof.
In some embodiments, one or more sensors can be fluidically coupled with the wellbore 210, 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 210, for example, proximate to the formation, e.g., formation 132 of
In some embodiments, the first pumping unit group 212 can be an example of a typical fracturing spread with a dirty blender 214 supplying a proppant slurry with a desired proppant concentration to a plurality of pumping units, e.g., dirty pumping units 212, configured to pump the proppant slurry at a desired pressure and flowrate to a wellbore 210. In some embodiments, the first pumping unit group 212 can be coupled to two or more wellbores, e.g., wellbore 210, to perform a sequential or simultaneous fracture of the two or more wellbores.
The exemplary fracturing spread 200 can comprise a second pumping unit group 250 configured to pump a clean fluid to the wellbore 210. The second group of pumping units, also referred to as clean pumping units 250, can be coupled to a blender unit 254 providing a clean fluid by a low pressure manifold 256 via a supply line 258. A water supply unit 280 and a chemical unit 282 can be fluidically coupled to the blender unit 254, also referred to as a clean blender. The clean pumping units 250 can be fluidically coupled to the wellbore 210 by a high pressure manifold 260 and a high pressure line 262. The second pumping unit group 250, e.g., the clean pumps, can include pumping units 270, 272, 274, and 276. Each of the pumping units, e.g., pumping unit 270, can be an embodiment of pumping unit 110 from
The fracturing spread 200 can combine the clean fluid from the clean pumping units 250 with the dirty fluid, e.g., proppant slurry, from the dirty pumping units 212 at the wellbore 210. In some embodiments, the high pressure line 262 from the high pressure manifold 260 of the clean pumping units 250 and the high pressure line 248 from the high pressure manifold 218 of the dirty pumping units 212 can be coupled a fluid junction 278. The fluid junction 278 can be a fluid control component or could be a part of a fracturing manifold or wellhead coupled to the wellbore 210. In some embodiments a pressure and flowrate sensor can be located between the high pressure manifold 260 of the clean pumping units 250 and the fluid junction 278, for example, along the high pressure line 262. In some embodiments a pressure and flowrate sensor can be located between the high pressure manifold 218 of the clean pumping units 212 and the fluid junction 278, for example, along the high pressure line 248. The controller within the control center 236 can establish a flowrate of proppant slurry with a desired proppant concentration at the fluid junction 278 and/or the wellbore 210 by controlling the supply of clean fluid from the clean pumping units 250 and the supply of proppant slurry from the dirty pumping units 212. The fracturing spread 200 can maximize the concentration of proppant within the proppant slurry by shutting down the clean pumping units 250 and supplying proppant from the proppant supply unit 244 at an operational limit or operational maximum value. The fracturing spread 200 can minimize the concentration of proppant by pumping the clean fluid from the clean pumping units 250 and shutting down the dirty pumping units 212. Alternatively, the fracturing spread 200 can pump clean fluid from the clean pumping units 250 and clean fluid from the dirty pumping units 212 by shutting off the proppant supply unit 244 feeding the dirty blender 214.
In some embodiments, the fracturing spread 200 can simultaneously fracture two wellbores. Each pumping unit group, clean pumping units 250 and dirty pumping units 212, can be divided or split into two or more groups. For example, pumping unit 270, 272 of the clean pumping units 250 and pumping units 220, 222 of the dirty pumping units 212 can be coupled to a first wellbore and pumping unit 274, 276 of the clean pumping units 250 and pumping units 224, 226 of the dirty pumping units 212 can be coupled to a second wellbore. Although the fracturing spread 200 is described as fracturing two wellbores, it is understood that the fracturing spread 200 could fracture 2, 3, 4, 5, 6, or any number of wellbores simultaneously by adding more fracturing units.
Turning now to
During pumping operations, exemplary fluid network 300 can feed the pumping unit 220 either a clean fluid or a dirty fluid from the blender unit 214, 254 and deliver high pressure fluid from the pumping unit 220 to the wellbore 210. The pumping unit 220 can receive clean fluid from the clean blender 254 via the low pressure manifold 216. The pumping unit 220 can receive either clean fluid or dirty fluid when the low pressure manifold 216 is coupled to the dirty blender 214. The fluid network 300 can deliver high pressure fluid from the pumping unit 220 to the wellbore 210 via the high pressure manifold 218. The pumping unit 220 can be configured in a dual pump mode or a single pump mode. In the dual pump mode, both of the pumps can be coupled to the motor and actively pumping. In the single pump mode, one of the two pumps can be coupled and the other pump can be decoupled so that only one pump is actively pumping. The unit controller, e.g., unit controller 140, can be calibrated to measure, calculate, and communicate the pumping operation of both pumps operating in the dual pump mode or the pumping operation of a single pump in the single pump mode. For example, the unit controller can report the flowrate of the pumping unit in dual mode is double the flowrate of the pumping unit in single mode. Similarly, the unit controller can calculate an increase or decrease rate of flowrate change in dual mode that is double the rate of flowrate change in single mode. If one of the pumps of the pumping unit 220 needs to be shut down due to decrease in pumping performance, the controller within control center 236 can direct the pumping unit 220 to ramp down and stop the pumping operation. The effected pump, for example pump 220B, can be isolated from the fluid manifold 310 and disconnected from the motor 220M. For example, an isolation valve on the inlet arm 316 can be closed to isolate the pump 220B from the low pressure manifold 216. An isolation valve on the discharge arm 318 can be closed to isolate the pump 220B from the high pressure manifold 218. The controller with in the control center 236 can recalibrate the unit controller of pumping unit 220 in single mode and restart the pumping unit 220 with the motor 220M powering the pump 220A while the pump 220B remains idle. The unit controller can direct the pumping operation of pumping unit 220 per the single mode calibration.
The calibration of the unit controller for either single mode or dual mode comprises a variety of parameters including pump count, power limit, torque limit, speed limit, temperatures, pressures, pressure/torque ratio, discharge rate per revolution, auxiliary system settings, prime mover drive settings/limits. For example, the flowrate of the pumping unit 220 in single mode is half the flowrate of the pumping unit 220 in single mode. In another example, the ramp rate (e.g., rate of change of flowrate) in single mode is twice as fast as the ramp rate in dual mode. In still another example, the torque limit in single mode is half the torque limit in dual mode. The unit controller can be calibrated or recalibrated based on the status of the pump, e.g., pump 220A. For example, the unit controller can determine if the pump 220A and pump 220B is connected to the motor 220M and calibrate the unit controller accordingly.
Turning now to
During pumping operations, exemplary fluid network 320 can feed the pumping unit 220 either a clean fluid or a dirty fluid from the blender unit 214, 254 and deliver high pressure fluid from the pumping unit 220 to the wellbore 210. The pumping unit 220 can receive clean fluid from the clean blender 254 or can receive either clean fluid or dirty fluid when the low pressure manifold 216 is coupled to the dirty blender 214. The fluid network 320 can deliver high pressure fluid from the pumping unit 220 to the wellbore 210 via the high pressure manifold 218. As previously described, the unit controller can be calibrated for dual mode and the pumping unit 220 can be operating in dual mode, e.g., both pump A and pump B operating. If one of the pumps of the pumping unit 220 needs to be shut down due to decrease in pumping performance, the controller within control center 236 can direct the pumping unit 220 to ramp down and stop the pumping operation. The effected pump, for example pump 220B, can be isolated from the fluid manifold 322 and disconnected from the motor 220M. For example, an isolation valve on the inlet arm 316 and the discharge arm 318 can be closed to isolate the pump 220B from the low pressure manifold 216 and high pressure manifold 218 respectively. The controller with in the control center 236 can recalibrate the unit controller of pumping unit 220 in single mode and can restart the pumping unit 220 with the motor 220M powering the pump 220A while the pump 220B remains idle.
Turning now to
During pumping operations, exemplary fluid network 330 can feed the pumping unit 220 either a clean fluid, a dirty fluid, or a blend of clean and dirty fluid via the dual manifold 334. The pumping unit 220 can receive clean fluid from the clean blender 254 via the low pressure manifold 336. The pumping unit 220 can receive either clean fluid or dirty fluid from the low pressure manifold 338 coupled to the dirty blender 214. The controller within the control center 236 can blend the clean fluid from the clean manifold 336 with dirty fluid from the dirty manifold 338 by operating the isolation valves 344A, 346A, 344B, and 346B. For example, the controller can decrease the concentration of the proppant entering the inlet arm 316 via the connector block 342 by partially closing the isolation valve 344B connected to the dirty manifold 338 to decrease the flowrate of dirty fluid, e.g., proppant slurry. In some embodiments, the controller can increase the opening valve of the isolation valve 346B coupled to the clean manifold 336 to increase the flowrate of clean fluid to compensate for the decrease in the flowrate of dirty fluid. The fluid network 330 can deliver high pressure fluid from the pumping unit 220 to the wellbore 210 via the high pressure manifold 218. As previously described, the unit controller can be calibrated for dual mode and the pumping unit 220 can be operating in dual mode, e.g., both pump A and pump B operating. If one of the pumps of the pumping unit 220 needs to be shut down due to decrease in pumping performance, the controller within control center 236 can direct the pumping unit 220 to ramp down and stop the pumping operation. The effected pump, for example pump 220B, can be isolated from the fluid manifold 310 and disconnected from the motor 220M. For example, an isolation valve on the inlet arm 316 can be closed to isolate the pump 220B from the low pressure manifold 216. An isolation valve on the discharge arm 318 can be closed to isolate the pump 220B from the high pressure manifold 218. The controller with in the control center 236 can recalibrate the unit controller of pumping unit 220 in single mode and can restart the pumping unit 220 with the motor 220M powering the pump 220A while the pump 220B remains idle.
In some embodiments, the controller can direct the fluid network 330 to flush a pump before isolating the pump from the fluid network 330. Using the prior example of pump 220B, the controller can close the isolation valve 344B coupled to the dirty manifold 338 and fully open isolation valve 346B coupled to the clean manifold 336 to flush all of the proppant slurry from the pump 220B. This flushing operation can occur during the pumping operation, as the pumping unit 220 is ramping down, e.g., decreasing the flowrate, or operating at a decreased value of flowrate. After the flushing operation, the controller can isolate the pump 220B, shut down the pumping unit 220, disconnect the motor 220M from the pump 220B, and resume the pumping operation with pump 220A.
Turning now to
During pumping operations, exemplary fluid network 350 can feed the pumping unit 220 either a clean fluid, a dirty fluid, or a blend of clean and dirty fluid via the dual manifold 334 and wye-block 324. The pumping unit 220 can receive clean fluid from the clean blender 254 via the low pressure manifold 336. The pumping unit 220 can receive either clean fluid or dirty fluid from the low pressure manifold 338 coupled to the dirty blender 214. The controller within the control center 236 can blend the clean fluid from the clean manifold 336 with dirty fluid from the dirty manifold 338 by operating the isolation valves 344A, 346A, 344B, and 346B. For example, the controller can decrease the concentration of the proppant to pump 220A and pump 220B via the wye-block 324 by partially closing the isolation valve 344A connected to the dirty manifold 338 to decrease the flowrate of dirty fluid, e.g., proppant slurry. In some embodiments, the isolation valve 346A coupled to the clean manifold 336 can be operated to a greater open value by the controller to compensate for the decrease in flowrate of the dirty fluid. The fluid network 350 can deliver high pressure fluid from the pumping unit 220 to the wellbore 210 via the high pressure manifold 218. As previously described, the unit controller can be calibrated for dual mode and the pumping unit 220 can be operating in dual mode, e.g., both pump A and pump B operating. If one of the pumps of the pumping unit 220 needs to be shut down due to decrease in pumping performance, the controller within control center 236 can direct the pumping unit 220 to ramp down and stop the pumping operation. In some embodiments, the controller can initiate a flushing operation previously described to flush the proppant slurry from the pump 220A and pump 220B before disconnecting one of the pumps. The effected pump, for example pump 220B, can be isolated from the fluid manifold 352 and disconnected from the motor 220M. For example, an isolation valve on the inlet arm 316 can be closed to isolate the pump 220B from the dual manifold 334. An isolation valve on the discharge arm 318 can be closed to isolate the pump 220B from the high pressure manifold 218. The controller within the control center 236 can recalibrate the unit controller of pumping unit 220 in single mode and can restart the pumping unit 220 with the motor 220M powering the pump 220A while the pump 220B remains idle.
Turning now to
During pumping operations, exemplary fluid network 360 can feed the pumping unit 220 a clean fluid from the clean blender 254, a dirty fluid from the dirty blender 214, or a blended proppant slurry from both the clean blender 254 and the dirty blender 214 via a low pressure manifold 216. As previously described, the unit controller can be calibrated for dual mode and the pumping unit 220 can be operating in dual mode, e.g., both pump A and pump B operating. The fluid network 360 can deliver high pressure fluid from the pumping unit 220 to the wellbore 210 via the high pressure manifold 218. If one of the pumps of the pumping unit 220 needs to be shut down due to a decrease in pumping performance, the controller within control center 236 can direct the pumping unit 220 to ramp down and stop the pumping operation. The effected pump, for example pump 220B, can be isolated from the fluid manifold 310 and disconnected from the motor 220M. For example, an isolation valve on the inlet arm 316 can be closed to isolate the pump 220B from the low pressure manifold 216. An isolation valve on the discharge arm 318 can be closed to isolate the pump 220B from the high pressure manifold 218. The controller with in the control center 236 can recalibrate the unit controller of pumping unit 220 in single mode and can restart the pumping unit 220 with the motor 220M powering the pump 220A while the pump 220B remains idle.
A pump with a decrease in pumping performance can be disconnected from the prime mover of the pumping unit. Turning now to
The pump 400A and the pump 400B can be a positive displacement pump with a valve system 402. In some embodiments, the pump 400A and the pump 400B can comprise multiple chambers 404 with plungers driven by a drive shaft and/or crankshaft 406 with the valve system 402 comprising intake valves and discharge valves. For example, each of the pumps, e.g., pump 400A, can include three chambers 404 with a plunger (not shown) reciprocating within each chamber and mechanically coupled to a crankshaft 406. Each chamber may include a suction valve and a discharge valve that operate with each stroke of the plunger. The suction valve fluidically couples the chamber to a low pressure manifold, e.g., manifold 216 of
The prime mover, e.g., motor 400M, can be releasably coupled to the drive shaft and/or crankshaft 406 by a decoupler mechanism 418. The decoupler mechanism can include an coupling actuator and a positioning sensor communicatively connected to the controller. The decoupler mechanism can be configured to engage or disengage the motor 400M to the drive shaft and/or crankshaft 406 as will be described hereinafter.
The motor 400M, e.g., prime mover, can be communicatively coupled to a unit controller 410, e.g., unit controller of
In some embodiments, the unit controller 410 can be communicatively coupled to the system controller 414 within the control center, e.g., control center 236 of
Turning now to
The extend-retract mechanism within the actuator 516 can operate the decoupler mechanism 418 from a coupled configuration to a decoupled configuration. In some embodiments, the extend-retract mechanism can be communicatively coupled to the unit controller 410. The extend-retract mechanism can comprise a first volume of fluid, a pump, and a second volume of fluid. For example, an extender mandrel within housing can be urged outward from the housing by transferring fluid from the first volume to the second volume by the pump. In some embodiments, the extender mandrel within the housing can be extended by an electric motor turning a gearing system mechanically coupled to the mandrel. In some embodiments, the extender mandrel can be a threaded rod that is extended/retracted from the housing by an electric motor. The extend-retract mechanism can be controlled to move in a first direction, e.g., to a coupled configuration, and move in a second direction, e.g., to a decoupled configuration, by the unit controller 410 of
The set of positional sensors 518 can provide feedback of the position of the dynamic element 514 and thus the configuration of the decoupler mechanism 418 to the unit controller 410. Each of the sensors within the set of positional sensors 518 can be a magnetic sensor, e.g., a hall-effect sensor, configured to sense the position of the dynamic element 514. As illustrated in
In some embodiments, the unit controller 410 of the pumping unit 400 can determine if the pump 400B is coupled to the motor 400M by receiving a signal, e.g., a positive value, from sensor 518A. In some embodiments, the unit controller 410 can calibrate or recalibrate the pumping unit 400 in single mode or dual mode in response to the signal from sensor 518A.
As illustrated in
As illustrated in
Turning now to
As shown in
In some embodiments, the unit controller 410 of the pumping unit 400 can determine the pump 400B is decoupled to the motor 400M by receiving a signal, e.g., a positive value, from sensor 518B. In some embodiments, the unit controller 410 can calibrate or recalibrate the pumping unit 400 from dual mode to single mode in response to the signal from sensor 518B.
A wellbore servicing operation can utilize a fracturing spread to fracture one or more formations. As described in
In some scenarios, the pumping units of the fracturing spread can utilize fluid network 300 described in
In some scenarios, the pumping units of the fracturing spread can utilize fluid network 330 or fluid network 350 described in
In some scenarios, the pumping units of the fracturing spread can utilize fluid network 360 described in
During the performance of a wellbore servicing operations, one or more pumps, e.g., pump 220B of pumping unit 220, may need to cease operation and in some cases be replaced. Referring to exemplary pumping system 400 in
With reference to
Returning to the example of
As used herein, ramp rate can refer to the acceleration/deceleration rate for the pumping unit. Ramps rates can be same or different for each pumping unit. In other words, ramp rate is defined as the rate-of-change of pumping rate (e.g., flowrate of the pump). By controlling an individual ramp rate of each pumping unit simultaneously receiving a pumping rate change, the overall combined flowrate can be a controlled constant. Overall pumping flowrate can be held constant while multiple pumps are simultaneously changing rates as long as the sum of the ramp rates (e.g., positive and negative slopes; increasing and decreasing) is zero.
Returning to the balancing process 650, the balancing process 650 may determine a transition period at step 660 defined as a value of time between a first pump load, e.g., Total flowrate of step 652, and a second pump load, e.g., distribution of flowrate at step 658. The transition period, e.g., transition period 614, may be determined based on the greatest rate change, e.g., PUMP 1. At step 662, the balancing process may determine a ramp rate for each of the pumps during a transition period, e.g., transition period 614, that results in a constant flowrate. Returning to
The balancing process 650 may divide the transition period, e.g., transition period 614 and/or 616, into multiple sequential time steps. For example, transition period 614 can be divided into six transition sub-periods of 1 second duration, e.g., 614A is 1 second, 614B is 1 second, etc. The balancing process 650 can determine a balanced ramp rate within each sub-period, e.g., 614B, so that the total flowrate, e.g., the transitional balanced pump load, remains constant within each sub-period and thus, the flowrate of the plurality of pumps remains constant with the flowrate before the transition period, during the transition period, during each sub-period of the transition period, and after the transition period ends. Although the examples illustrate pumps with constant ramp rate throughout the transition period, it is understood that the transition period may include step changes and/or one or more pumps may return to a constant flowrate before the end of the transition period as long as the flowrate of the plurality of pumps remains constant during each sub-period of the transition period.
In some embodiments, the system controller can direct the unit controller of PUMP 1 to decouple a pump with the decrease in pumping performance. For example, the system controller 414 within the control center 236 can direct the unit controller 410 to activate the decouple mechanism 418 within PUMP 1, e.g., pumping system 400, to decouple the pump 400B, e.g., pump 220B of pumping unit 220, from the motor 400M, e.g., motor 220M. In this example, the pump 400B with the decrease in pumping performance can be decoupled from the motor 400M while the other pump 400A with normal operation remains coupled to the motor 400M. PUMP 1 can be returned to the pumping operation with pump 400A operational and pump 400B decoupled or non-operational. In some embodiments, the system controller can direct the isolation valves within a fluid manifold, e.g., fluid manifold 310, to close. For example, the system controller within the control center 236 can direct the isolation valves within the inlet arm 316 and discharge arm 318 of fluid network 300 coupled to the non-operational pump to close.
In some embodiments, the system controller can isolate PUMP 1 from the fracturing spread and replace PUMP 1 with another pumping unit, for example, PUMP 5. A pumping unit, e.g., PUMP 5, can be held in reserve, e.g., in a non-operational state, in case of a pumping unit failure. In the example of
In some embodiments, the balancing process can utilize a second transition period 616 to add a pumping unit to the pumping operation. The balancing process may determine a ramp rate for each of the pumps during the second transition period 616. Returning to
Turning now to a second example of
The system controller may execute a balancing process 650 for flowrate balancing with the following steps. At step 652, the balancing process can determine the total flowrate of the system for the first balanced pump load. From the example of
The balancing process executing on the system controller can determine the new pumping rate target for each pump based on the weighted factors of capacity, efficiency, service life, and cost for the second balanced pump load. In the example of
The balancing process may determine a ramp rate for each of the pumps for a first transitional pump load during the transition period 614. For example, the transition period 614 is 6 seconds in length, thus the balancing process can set the PUMP 1 rate of change at 6 BPM per 6 seconds for a decrease in ramp rate of 1 BPM per second. The balancing process can set the rate change for the remaining three pumps based on the new pumping rate target. For example, the balancing process can set PUMP 4 to 2 BPM per 6 seconds for an increase ramp rate of 1/3 BPM per sec. The balancing process can set PUMP 3 to 3 BPM per 6 seconds for an increase ramp rate of 1/2 BPM per sec. The balancing process can set PUMP 2 to 1 BPM per 6 seconds for an increase ramp rate of 1/6 BPM per sec. Thus, the balancing process can set the ramp rate change of flowrate decreasing equal to the total combined ramp rate change of flowrate increasing.
The balancing process can simultaneously execute the new target flowrates for each of the pumps during the transition period 614 and prepare for the second transition period 616. In the example of
In some embodiments, the balancing process can simultaneously execute the new target rates during the second transition period 616 with ramp up and ramp down rates. For example, the balancing process may determine a second transitional pump load with an increase ramp rate for the new pumping unit, PUMP 5, to be 6 BPM per 6 seconds for an increase in rate of 1 BPM per second. The balancing process can set the rate change for PUMP 4 to 2 BPM per 6 seconds for a decrease in rate of 1/3 BPM per sec. The balancing process can set PUMP 3 to 3 BPM per 6 seconds for an decrease of 1/2 BPM per sec. The balancing process can set PUMP 2 to 1 BPM per 6 sec for a decrease ramp rate of 1/6 BPM per sec. Thus, the balancing process can determine a second transitional pump load with the total combined ramp rate change for the flowrate decreasing equal to the ramp rate change of flowrate increasing.
Turning now to a second example of
The system controller may simultaneously execute a balancing process for flowrate balancing with the following steps. At step 652, the balancing process can determine the total flowrate of the system. From the example of
The balancing process executing on the system controller can determine the new pumping rate target for each pump based on the weighted factors of capacity, efficiency, service life, and cost. In the example of
The balancing process may determine a ramp rate for each of the pumps during the transition period 614. For example, the transition period 614 is 6 seconds in length, thus the balancing process can set the PUMP 1 rate of change at a decrease ramp rate of 1 BPM per second. The balancing process can set the increase ramp rate change for PUMP 2 and PUMP 3 at 1/2 BPM per sec. The balancing process can set PUMP 4 to remain unchanged. Thus, the balancing process can set the ramp rate change of flowrate decreasing equal to the total combined rate change of flowrate increasing.
The balancing process can execute the new target flowrates for each of the pumps during the transition period 614 and prepare for the second transition period 616. In the example of
In some embodiments, the balancing process can simultaneously execute the new target rates during the second transition period 616 with ramp up and ramp down rates. For example, the balancing process may determine a ramp up rate for the new pumping unit, PUMP 5, to be an increase ramp rate of 1 BPM per second. The balancing process can set PUMP 2 and PUMP 3 to 3 BPM per 6 seconds for a decrease ramp rate of 1/2 BPM per sec. The balancing process can set PUMP 4 remain unchanged at 9 BPM. Thus, the balancing process can set the ramp rate change of total combined flowrate decreasing equal to the ramp rate change of flowrate increasing.
The computer system at the wellsite may be a computer system suitable for communication and control of the pumping equipment, e.g., a fracturing spread 200. The pumping operation described in
In some embodiments, the computer system 700 may comprise a DAQ card 714 for communication with one or more sensors. The DAQ card 714 may be a standalone system with a microprocessor, memory, and one or more applications executing in memory. The DAQ card 714, as illustrated, may be a card or a device within the computer system 700. In some embodiments, the DAQ card 714 may be combined with the input output device 708. The DAQ card 714 may receive one or more analog inputs 716, one or more frequency inputs 718, and one or more Modbus inputs 920. For example, the analog input 716 may include a volume sensor, e.g., a tank level sensor. For example, the frequency input 718 may include a flow meter, i.e., a fluid system flowrate sensor. For example, the Modbus input 720 may include a pressure transducer. The DAQ card 714 may convert the signals received via the analog input 716, the frequency input 718, and the Modbus input 720 into the corresponding sensor data. For example, the DAQ card 714 may convert a frequency input 718 from the flowrate sensor into flowrate data measured in gallons per minute (GPM).
The following are non-limiting, specific embodiments in accordance with the present disclosure:
A first embodiment, which is a computer-implemented method of managing a pumping unit during a pumping operation, comprising determining, by a managing process executing on a system controller, a position of a decoupler mechanism on the pumping unit; calibrating, by the managing process, a unit controller with a dual pump mode in response to determining the decoupler mechanism is in a coupled position, wherein the pumping unit is operating with a first pump and a second pump coupled to a prime mover in the dual pump mode; calibrating, by the managing process, the unit controller with a single pump mode in response to determining the decoupler mechanism is in a decoupled position, wherein the pumping unit is operating with the first pump coupled to the prime mover and the second pump decoupled from the prime mover in the single pump mode; and pumping, by the system controller, a wellbore treatment fluid in accordance with the pumping unit in i) the dual pump mode or ii) the single pump mode.
A second embodiment, which is the method of the first embodiment, wherein the pumping unit comprises the first pump, the second pump, and the prime mover.
A third embodiment, which is the method of the first or second embodiment, wherein the first pump is coupled to the prime mover, and wherein the decoupler mechanism couples the second pump to the prime mover.
A fourth embodiment, which is the method of any of the first through the third embodiments, wherein the decoupler mechanism comprises a static element, a dynamic element, an actuator, and a set of sensors; wherein the static element is coupled to a drive shaft of the prime mover; wherein the dynamic element is slidingly coupled to a drive shaft of the second pump; and wherein the actuator is coupled to the dynamic element and a housing of the second pump.
A fifth embodiment, which is the method of any of the first through the fourth embodiments, wherein the set of sensors comprises a first positional sensor in a location associated with the coupled position and a second positional sensor in location associated with the decoupled position.
A sixth embodiment, which is the method of any of the first through the fifth embodiments, wherein the set of sensors are positional sensors, and wherein the positional sensors are hall-effect sensors.
A seventh embodiment, which is the method of any of the first through the sixth embodiments, wherein the coupled position of the decoupler mechanism comprises an actuator positioning a dynamic element in engagement with a static element, wherein a first positional sensor is configured to return a signal based on the position of the dynamic element, and wherein the coupled position is configured to transfer torque and rotation from the static element to the dynamic element.
An eighth embodiment, which is the method of any of the first through the seventh embodiments, wherein the decoupled position of the decoupler mechanism comprises an actuator positioning a dynamic element away from and not engaged with a static element, wherein a second positional sensor is configured to return a signal based on the position of the dynamic element, and wherein the decoupled position is configured to rotationally isolate the second pump from the prime mover.
A ninth embodiment, which is the method of any of the first through the eighth embodiments, wherein the power end is an internal combustion engine or an electric motor.
A tenth embodiment, which is the method of any of the first through the ninth embodiments, further comprising transporting a pumping unit to a remote wellsite; fluidically coupling a pumping unit to a wellbore; beginning the pumping operation by a system controller communicatively coupled to the pumping unit; retrieving, by the system controller, one or more datasets of periodic pumping data indicative of the pumping operation; and mixing a wellbore treatment, by a blender unit, per a pumping schedule.
An eleventh embodiment, which is a method of replacing a pumping unit during a pumping operation delivering a wellbore treatment fluid into a wellbore penetrating a formation, comprising pumping a wellbore treatment with a pumping unit configured in a dual mode and a unit controller calibrated for the dual mode; receiving, by the unit controller comprising a processor and non-transitory memory, an indication of reduced pump operation; stopping, by the unit controller, the pumping operation of the pumping unit by reducing a rotational speed of a prime mover to zero during a transitional period; activating, by the unit controller, a coupling actuator of a decoupler mechanism to move a dynamic element from a coupled configuration to a decoupled configuration; receiving feedback from one of a set of sensors that the dynamic element is positioned in a decoupled position; recalibrating, by the unit controller, from the dual mode to a single mode in response to the decoupled position of the dynamic element; and pumping a wellbore treatment with the pumping unit configured in the single mode and the unit controller calibrated for the single mode.
A twelfth embodiment, which is the method of the eleventh embodiment, wherein the wellbore treatment fluid comprises i) a clean fluid, ii) a dirty fluid, or iii) a blended fluid, and wherein the blended fluid comprises a portion of clean fluid and a portion of dirty fluid.
A thirteenth embodiment, which is the method of any of the eleventh and the twelfth embodiments, wherein the dual mode comprises a first pump and a second pump coupled to a prime mover.
A fourteenth embodiment, which is the method of any of the eleventh through the thirteenth embodiments, wherein the indication of reduced pump operation is received via i) sensors, or ii) a system controller; wherein a plurality of sensors provide periodic datasets indicative of the pumping operation; and wherein the system controller is communicatively coupled to the unit controller via wired or wireless communication device.
A fifteenth embodiment, which is the method of any of the eleventh through the fourteenth embodiments, further comprising determining, by the unit controller, the transitional period to reduce the pumping operation of the pumping unit to zero.
A sixteenth embodiment, which is the method of any of the eleventh through the fifteenth embodiments, 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 seventeenth embodiment, which is a system of a dual-pumping unit, comprising a prime mover; a first pump coupled to the prime mover via a decoupler mechanism; a set of sensors configured to identify a position of the decoupler mechanism; a unit controller comprising a processor and a non-transitory memory communicatively coupled to the prime mover, the decoupler mechanism, and the set of sensors, configured to: control a pump rate of a pumping operation with the dual-pumping unit in a dual mode via control of the prime mover; stop a pumping operation by slowing a rotational motion of a drive shaft via the prime mover to a stop during a transitional period; activate an coupling actuator of the decoupler mechanism to move a dynamic element from a coupled configuration to a decoupled configuration; receive feedback from the set of sensors of the dynamic element in a decoupled position; and recalibrate the unit controller from the dual mode to a single mode in response to the decoupled position of the dynamic element.
An eighteenth embodiment, which is the system of the seventeenth embodiment, further comprising a second pump coupled to the prime mover.
A nineteenth embodiment, which is the system of the seventeenth embodiment, further comprising deactivating the coupling actuator of the decoupler mechanism in response to receiving feedback from the set of sensors of the dynamic element being in the decoupled position.
A twentieth embodiment, which is the system of any of the seventeenth through the nineteenth embodiments, further comprising the decoupler mechanism is in a locked position in response to the deactivating the coupling actuator.
A twenty-first embodiment, which is the system of any of the seventeenth through the twentieth embodiments, a fluid network coupled to the first pump; wherein the first pump receives a treatment fluid from the fluid network; and wherein the treatment fluid is i) a clean fluid, ii) a dirty fluid, or iii) a blended fluid.
A twenty-second embodiment, which is a computer-implemented method of managing a pumping unit during a pumping operation, comprising determining, by a managing process executing on a system controller, a position of a decoupler mechanism on a pumping unit; calibrating, by the managing process, the unit controller with a dual pump mode in response to determining the decoupler mechanism in the coupled position, wherein the pumping unit is operating with first fluid end and the second fluid end coupled to the power end in the dual pump mode; calibrating, by the by the managing process, the unit controller with a single pump mode in response to determining the decoupler mechanism in the decoupled position, wherein the pumping unit is operating with first fluid end coupled to the power end and the second fluid end decoupled from the power end in the single pump mode; and pumping, by the system controller, a wellbore treatment fluid in accordance with the pumping unit in i) the dual pump mode or ii) the single pump mode.
A twenty-third embodiment, which is the method of the twenty-second embodiment, wherein the pumping unit comprises a first fluid end, a second fluid end, and a power end.
A twenty-fourth embodiment, which is the method of the twenty-second or twenty-third embodiment, wherein the first fluid end is coupled to the power end, and wherein the decoupler mechanism couples the second fluid end to the power end.
A twenty-fifth embodiment, which is the method of any of the twenty-second through the twenty-fourth embodiments, further comprising transporting a pumping unit to a remote wellsite; fluidically coupling a pumping unit to a wellbore; beginning the pumping operation by a system controller communicatively coupled to the pumping unit; retrieving, by the system controller, one or more datasets of periodic pumping data indicative of the pumping operation; and mixing a wellbore treatment, by a blender unit, per the pump schedule.
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.
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