Method to Reduce Peak Treatment Constituents in Simultaneous Treatment of Multiple Wells

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Not applicable.

Subterranean hydraulic fracturing is conducted to increase or “stimulate” production from a hydrocarbon well. To conduct a fracturing process, high pressure is used to pump special fracturing fluids, including some that contain propping agents (“proppants”) down-hole and into a hydrocarbon formation to split or “fracture” the rock formation along veins or planes extending from the well-bore. Once the desired fracture is formed, the fluid flow is reversed and the liquid portion of the fracturing fluid is removed. The proppants are intentionally left behind to stop the fracture from closing onto itself due to the weight and stresses within the formation. The proppants thus literally “prop-apart”, or support the fracture to stay open, yet remain highly permeable to hydrocarbon fluid flow since they form a packed bed of particles with interstitial void space connectivity. Sand is one example of a commonly-used proppant. The newly-created-and-propped fracture or fractures can thus serve as new formation drainage area and new flow conduits from the formation to the well, providing for an increased fluid flow rate, and hence increased production of hydrocarbons.

Three or more wells clustered together can be stimulated simultaneously with the same fracturing equipment. A need exists to stimulate multiple (e.g., three or more) wellbores simultaneously without exceeding pumping limits of available fracturing equipment.

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.

When simultaneously fracturing multiple wells, a required capacity of the (e.g., blending) equipment may be exceeded. This can be particularly relevant when the (e.g., blending) equipment is of a legacy type originally intended for single well operations. Additionally, when hydraulically fracturing wells, several treatment parameters can change during the treatment. For example, parameters such as water rate, sand rate and chemical additive rates may sequentially increase as the treatment progresses. Furthermore, when simultaneously fracturing multiple wells it has been conventional to start the treatment of all simultaneously fractured wells at the same time and follow the same treatment schedule for all wells. This conventional operation can lead to wide swings in the total water, sand, and chemical rates, etc., required during the treatment (e.g., with low rates near the start and high rates near the end of the treatment), which can lead to exceeding an operating parameter of the fracturing equipment (e.g., an available rate limit, as shown and described hereinbelow with reference to).

The herein disclosed system and method comprise introducing a time offset in the start time of the treatments for multiple (e.g., two, three, four, or more) wells being treated simultaneously so that the time offset reduces the maximum rate requirements from the blending equipment. In embodiments, the offset(s) can be devised to level (e.g., reduce variation or variability of) the operating parameter for (at least a portion of) the duration of the treatments of the multiple wells being treated simultaneously, and/or provide a buffer between the maximum (e.g., rate) requirements from the blending equipment and a maximum available parameter (e.g., a maximum available rate).

A modern fracturing fleet typically includes a water supply, a proppant supply, one or more blenders, a plurality of frac pumps, and a fracturing manifold connected to the wellhead. The individual units of the fracturing fleet can be connected to a central control unit called a data van. The control unit can control the individual units of the fracturing fleet to provide proppant slurry at a desired rate to the wellhead. The control unit can manage the pump speeds, chemical intake, and proppant density while pumping fracturing fluids and receiving data relating to the pumping from the individual units.

Multiple well completion techniques (also referred to as “simulfrac”) can be used to maximize operational use of equipment and personnel. Some oil fields have multiple wells drilled from a single pad. The placement of multiple wells within a single pad or area allows for a smaller footprint of production equipment. Multiple wells on a single pad also allows for hydraulic fracturing multiple wells without relocating the fracturing equipment. One such technique, called zipper fracturing, allows a single fracturing fleet to treat multiple wells by alternating the pumping operation from one well to another well. Another technique allows for multiple wells to be treated simultaneously. The hydraulic fracturing fleet can connect to three or more wells to pump the hydraulic fracturing treatment into the three or more wells at the same time. The pumping capacity of the available equipment may not be enough to treat all wells simultaneously. The wellsite may not be able to accommodate a fracturing fleet with enough pumping capacity to simultaneously treat the three or more wells. The available equipment may have a reduced reliability based on size, age, or time between major equipment servicing. A method to treat multiple wells with limited pumping capacity is needed.

In an embodiment, the fracturing fleet can be divided into a cleaning pumping group and a dirty pumping group. The clean pumping group pumps clean fluid or fluid without proppant. The dirty pumping group pumps dirty fluid or fluid with proppant. The clean pumping group can split the fluid output from the pumps into each of three or more wells (e.g., a first well, a second well, and a third well). The dirty pumping group can split the dirty fluid output from the pumps into each of the three or more wells (e.g., the first well, the second well, and the third well). Each well of the three or more wells (e.g., the first well, the second well, and the third well) can receive a combined treatment volume. The combined treatment volume can be designed to produce the desired fractures within the formation. The dirty pumping group can be comprised of pumping equipment with an increased reliability to reduce the chance of equipment malfunction during pumping. The clean pumping group can comprise pumping equipment with a lower reliability (e.g., equipment that is reliable, but can be less resistant to abrasion, thus lowering operating cost) than the pumping equipment used for the dirty pumping group as the clean fluid can be less abrasive and induce a lower level of stress on the pumping equipment. Utilizing pumping equipment with a reduced reliability to pump the less abrasive clean fluid can increase the pumping capacity of the frac fleet.

In an embodiment, the fluid pumping schedule can be designed to prevent peak pumping rate from exceeding the pumping capacity of the fracturing fleet. The pumping schedule can be designed to deliver a combined treatment volume comprising a clean fluid volume and a dirty fluid volume to each of three or more wells (e.g., a first well, a second well, and a third well). A fluid pumping schedule can be divided into stages that coincide with a change in pumping volume, pressure, rate, or proppant loading. The fluid pumping schedule for one or more of the three or more wells can be offset (e.g., temporally offset) relative to the fluid pumping schedule of at least one other of the three or more wells. For example, in embodiments the first well can be designed to begin a first pumping stage before the fluid pumping schedule for the second well begins the first pumping stage and/or before the fluid pumping schedule for the third well begins the first pumping stage. In embodiments, the first well can be designed to begin a first pumping stage before the fluid pumping schedule for the second well begins the first pumping stage, and the second well can be designed to begin the first pumping stage before the fluid pumping schedule for the third well begins the first pumping stage. Similarly, the fluid pumping schedule for the first well can be designed to transition from a first pumping stage to a second pumping stage before the second pumping schedule finishes the first pumping stage and/or before the third pumping schedule finishes the first pumping stage. In embodiments, the fluid pumping schedule for the first well can be designed to transition from the first pumping stage to the second pumping stage before the second pumping schedule finishes the first pumping stage, and the fluid pumping schedule for the second well can be designed to transition from the first pumping stage to the second pumping stage before the third pumping schedule finishes the first pumping stage. Offsetting the pumping stages will therefore offset the combined pumping rate delivered to the three or more wells (e.g., to the first, second, and third wells), thereby avoiding an operating limit of one or more fracturing units, while pumping the treatment into the one or more wells (e.g., into the first, second, and third wells) simultaneously.

In an embodiment, the pump sequence (also referred to herein as “pump schedule”) design can assign frac units to perform the pumping sequence based on a set of criteria provided by the user. A variety of pumping equipment can be delivered to a wellsite of various ages, versions of equipment, upgrades, and modifications. For example, a second generation and a third generation of the frac pump with different pump ratings can be delivered to the wellsite. Although the equipment can be functionally identical, some equipment may be better suited for pumping the clean fluid and some equipment may be better suited for pumping the dirty fluid. The pumping sequence design can provide a solution to the optimization of equipment by selecting the optimal set of equipment for the pumping operation. The pump sequence design can produce a pump schedule that maximizes the pumping capacity of the pumping equipment to stimulate multiple wells simultaneously.

Disclosed herein is a method of performing a pumping operation on multiple wells simultaneously by maximizing the treatment capacity of the fracturing fleet based on the available equipment. A pumping schedule can be designed with a pumping sequence design method that offsets the pumping schedule of each well to avoid exceeding the treatment capacity of the fracturing fleet. The pump schedule design can assign the pumping equipment to pump the clean fluid volume or the dirty fluid volume based on user criteria.

Described herein is a typical fracturing fleet at a wellsite. The pumping sequence can be partially controlled or fully controlled by a computerized managing application with feedback of equipment data provided by sensors on the fracturing units indicative of a pumping stage of the pumping sequence. Turning now to, an embodiment of a hydraulic fracturing systemthat can be utilized to pump hydraulic fracturing fluids into a wellbore, is illustrated. As depicted, a plurality of hydraulic fracturing pumps(also referred to as “frac pump” or high horsepower pumps) is connected in parallel to a fracturing manifold(also referred to as a “missile”) to provide fracturing fluids to the treatment well(also referred to as the wellhead). The fracturing fluids are typically a blend of friction reducer and water, e.g., slick water, and proppant. In some cases, a gelled fluid (e.g., water, a gelling agent, optionally a friction reducer, and/or other additives) may be created in a hydration blenderfrom the water supply unitand gelling chemicals from the chemical unit. When slick water is used, the hydration blendercan be omitted. The proppant is added at a controlled rate to the gelled fluid in one or more mixing blenders. Each of the one or more mixing blendersis in fluid communication with the manifoldso that the fracturing treatment is pumped into the manifoldfor distribution to the frac pumps, via supply line. The fracturing fluids are returned to the manifoldfrom the frac pumps, via high pressure line, to be pumped into the treatment wellthat is in fluid communication with the manifold. Although fracturing fluids typically contain a proppant, a portion of the pumping sequence may include a fracturing fluid without proppant (e.g., a pad fluid, clean fluid, flush fluid). Although fracturing fluids typically include a gelled fluid, the fracturing fluid may be blended without a gelling chemical. Alternatively, the fracturing fluids can be blended with an acid to produce an acid fracturing fluid, for example, pumped as part of a spearhead or acid stage that clears debris that may be present in the wellbore and/or fractures to help clear the way for fracturing fluid to access the fractures and surrounding formation.

A control vancan be communicatively coupled (e.g., via a wired or wireless network) to any of the frac units wherein the term “frac units” may refer to any of the plurality of frac pumps, a manifold, and associated blending unitwith one or more mixing blender(s), proppant storage unit, hydration blender, water supply unit, and chemical unit. The managing applicationexecuting on a computer (e.g., server)within the control vancan establish unit level control over the frac units communicated via the network. Unit level control can include sending instructions to the frac units and/or receiving equipment data from the frac units. For example, the managing applicationwithin the control vancan establish a pump rate ofbpm with the plurality of frac pumpswhile receiving pressure and rate of pump crank revolutions from sensors on the frac pumps.

Although the managing applicationis described as executing on a computer, it is understood that the computercan be a computer system, for example computer systemin, or 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(e.g., computer system) can include one or more processors, memory, input devices, and output devices, as described in more detail further hereinafter. Although the control vanis described as having the managing applicationexecuting on a computer, it is understood that the control vancan have 2, 3, 4, or any number of computers(e.g., computer systems) with 2, 3, 4, or any number of managing applicationsexecuting on the computers.

The fracturing fleet can be divided into three pumping groups that share a blending unitcomprising one or more blenders(e.g., mixing tubs, centrifugal blenders) to simultaneously treat three or more wells. Turning now to, an embodiment of a hydraulic fracturing systemthat can be utilized to pump hydraulic fracturing fluids into three wellbores, is illustrated. As depicted, the blender capacity can be divided among three sets of frac pumps. A first set of frac pumpscan be connected to a first manifoldA. A second set of frac pumpscan be connected to a second manifoldB. A third set of frac pumpscan be connected to a third manifoldC. As previously described, each mixing blenderof the blending unitcan produce a proppant slurry by adding proppant, e.g., sand, from the proppant storage unitto slick water blended from water provided by the water supplyA and a friction reducer from the chemical unitA. A portion of the proppant slurry from the blending unitcan be pumped through feed lineA to the first manifoldA and first set of frac pumps, a portion of the proppant slurry from the blending unitcan be pumped through feed lineB to the second manifoldB and second set of frac pumps, and a portion of the proppant slurry from the blending unitcan be pumped through feed lineC to the third manifoldC and second set of frac pumps. The total volumetric rate of slurry received by the first wellboreA, the second wellboreB, and the third wellboreC cannot exceed the total volumetric rate output of the blending unitThe volumetric rate output of the mixing blender(s)can be limited by the maximum proppant, e.g., sand, mixing rate of the mixing blender(s). A plurality of frac pumpsare connected in parallel to the first manifoldA. Likewise, a plurality of frac pumpsare connected in parallel to the second manifoldB, and a plurality of frac pumpsare connected in parallel to the third manifoldC. Although two frac pumpsare shown, it is understood that 1, 2, 4, 8, 16, or any number of frac pumpscan connect in parallel to first manifoldA, second manifoldB, and third manifoldC.

A first wellboreA can receive a volume of proppant slurry from the first manifoldA via high pressure lineA. A second wellboreB can receive a volume of proppant slurry from the second manifoldB via high pressure lineB. A third wellboreC can receive a volume of proppant slurry from the third manifoldC via high pressure lineC. If the mixing blenderis a single mixing source, e.g., a single tub, the proppant slurry received by the first wellboreA can have the same fluid properties as the proppant slurry received by the second wellboreB and third wellboreC. Alternatively, if the mixing blenderis a dual mixing source, e.g., two tubs, and/or the bending unitcomprises a fluid proportioner as described in U.S. patent application Ser. No. 18/632,633, filed Apr. 11, 2024 and entitled “Slurry Proportioner System” or a multi-well blending system, for example, as described in U.S. patent Ser. No. 18/632,640, filed and Apr. 11, 2024 and entitled “Multi-Well Blending System”, the disclosure of each of which is hereby incorporated herein for purposes not contrary to this disclosure, the proppant slurry received by the first wellboreA (e.g., mixed in a first tub of the blender) can have different fluid properties than the proppant slurry received by the second wellboreB (e.g., mixed in a second tub of the blender) and/or the proppant slurry received by the third wellboreC (e.g., mixed in a third tub of the blender). In embodiments, one blendercan provide different slurries to each of the first wellboreA, the second wellboreB, and the third wellboreC.

A control van (e.g., control vanfrom) can be communicatively coupled (e.g., via a wired or wireless network) to all of the frac units, wherein the term “frac units” may refer to any of the plurality of frac pumps, a manifold (e.g., firstA, secondB, third manifoldC), mixing blender(s) (e.g.,) and associated proppant storage unit(s)(and/or a proppant delivery unit (such as an ExpressSand™ structure available from Halliburton Energy Services, Inc.) or a proppant transfer or metering unit (such as a conveyor belt, auger, or metering gate), water supply unit(s) (e.g.,A), and chemical unit(s) (e.g.,A). The managing applicationexecuting on a computer (e.g., server)within the control vancan establish unit level control over the frac units communicated via the network. Unit level control can include sending instructions to the frac units and/or receiving equipment data from the frac units.

The fracturing fleet can be divided into a clean pumping group and a dirty pumping group to increase the pumping capacity of the available pumping equipment. Turning now to, an embodiment of a hydraulic fracturing systemthat can be utilized to pump hydraulic fracturing fluids into three wellbores, is illustrated. As depicted, the pumping capacity of the fracturing fleet can be divided into a dirty fluid groupand a clean fluid group. The dirty fluid groupcan comprise a dirty blending unitA comprising dirty blender(s)(e.g., a mixing blender) connected to a first manifoldA, a second manifoldB, and a third manifoldC. As previously described, the dirty blender(s)can produce a proppant slurry by adding proppant from the proppant storage unitto a gelled fluid blended from water provided by the water supplyA and gelling chemicals or friction reducers from the chemical unitA. The proppant slurry, e.g., the dirty fluid, can be pumped through feed lineA to first dirty manifold, feed lineB to second dirty manifoldB, and feed lineC to third dirty manifoldC. A plurality of frac pumpsare connected in parallel to first manifoldA, second manifoldB, and third manifoldC. The clean fluid groupcan comprise a clean blending unitB including clean blender(s)(e.g., a mixing blender) connected to a first clean manifoldA, a second clean manifoldB, and a third clean manifoldC. In some cases, the clean blender(s)can be replaced with a boost pump, e.g., centrifugal pump, with chemical port to receive a chemical additive, such as a friction reducer. As previously described, the clean blender(s)can produce a slick water fluid blended from water provided by the water supplyB and friction reducer chemicals from the chemical unitB. The slick water fluid, e.g., the clean fluid, can be pumped through feed lineA to first clean manifoldA, e.g., third manifoldA, feed lineB to second clean manifoldB, e.g., fifth manifoldB, and feed lineC to third clean manifoldC, e.g., sixth manifoldC. A plurality of frac pumpscan connect in parallel to fourth manifoldA, fifth manifoldB, and sixth manifoldC.

A first wellboreA can receive a combined treatment volume comprising a clean fluid volume and a dirty fluid volume from the clean fluid groupand the dirty fluid group. The dirty fluid groupcan provide a dirty fluid volume via the first manifoldA fluidly connected to a wye blockA by high pressure lineA. The clean fluid groupcan provide a clean fluid volume via the first clean manifoldA, e.g., fourth manifoldA, fluidly connected to the wye blockA by high pressure lineA. High pressure connectorA delivers the combined treatment volume from the wye blockA to the first wellboreA. The wye blockA can be a solid block, a manifold, a tubing branch, or any suitable high pressure connection.

A second wellboreB can receive a combined treatment volume comprising a clean fluid volume and a dirty fluid volume from the clean fluid groupand the dirty fluid group. The dirty fluid groupcan provide a dirty fluid volume via the second dirty manifoldB fluidly connected to a wye blockB by high pressure lineB. The clean fluid groupcan provide a clean fluid volume via the fifth manifoldB fluidly connected to the wye blockB by high pressure lineB. High pressure connectorB delivers the combined treatment volume from the wye blockB to the second wellboreB. The wye blockB can be a solid block, a manifold, a tubing branch, or any suitable high pressure connection.

A third wellboreC can receive a combined treatment volume comprising a clean fluid volume and a dirty fluid volume from the clean fluid groupand the dirty fluid group. The dirty fluid groupcan provide a dirty fluid volume via the third dirty manifoldC fluidly connected to a wye blockC by high pressure lineC. The clean fluid groupcan provide a clean fluid volume via the sixth manifoldC fluidly connected to the wye blockC by high pressure lineC. High pressure connectorC delivers the combined treatment volume from the wye blockC to the third wellboreC. The wye blockC can be a solid block, a manifold, a tubing branch, or any suitable high pressure connection.

Alternatively, a combination manifold can be used to combine the dirty fluid volume and clean fluid volume to a single output. A combination manifold comprises a clean low pressure side manifold, e.g.,A,B,C, a dirty low pressure side manifold, e.g.,A,B,C, and a unitary high pressure manifold that combines the fluid outputs of the pumpsto a single high pressure line fluidly connected to a wellbore (e.g., first wellboreA, second wellboreB, and third wellboreC).

A first combination manifold can comprise the clean low pressure side manifoldA fluidly connected to a clean group of pumpsvia supply lineand the dirty low pressure side manifoldA fluidly connected to a dirty group of pumpsvia supply line(as shown in). The dirty low pressure side manifoldA can be fluidly connected to the dirty blendervia supply lineA. The clean low pressure side manifoldA can be fluidly connected to the clean blendervia supply lineA. The high pressure output from the clean group of pumpsand dirty group of pumps, connected to the combination manifold, can fluidly connect via high pressure line(as shown in) to a unitary manifold output. The high pressure lineA andA can be replaced by high pressure lineA connecting the combination manifold to the first wellboreA.

A second combination manifold can comprise the clean low pressure side manifoldB fluidly connected to a clean group of pumpsvia supply lineand the dirty low pressure side manifoldB fluidly connected to a dirty group of pumpsvia supply line(as shown in). The dirty low pressure side manifoldB can be fluidly connected to the dirty blendervia supply lineB. The clean low pressure side manifoldB can be fluidly connected to the clean blendervia supply lineB. The high pressure output from the clean group of pumpsand dirty group of pumps, connected to the combination manifold, can fluidly connect via high pressure line(as shown in) to a unitary manifold output. The high pressure lineB andB can be replaced by high pressure lineB connecting the combination manifold to the second wellboreB.

A third combination manifold can comprise the clean low pressure side manifoldC fluidly connected to a clean group of pumpsvia supply lineand the dirty low pressure side manifoldC fluidly connected to a dirty group of pumpsvia supply line(as shown in). The dirty low pressure side manifoldC can be fluidly connected to the dirty blendervia supply lineC. The clean low pressure side manifoldC can be fluidly connected to the clean blendervia supply lineC. The high pressure output from the clean group of pumpsand dirty group of pumps, connected to the combination manifold, can fluidly connect via high pressure line(as shown in) to a unitary manifold output. The high pressure lineC andC can be replaced by high pressure lineC connecting the combination manifold to the third wellboreC.

A control van (e.g., control vanfrom) can be communicatively coupled (e.g., via a wired or wireless network) to any of the clean frac units or dirty frac units, wherein the term “frac units” may refer to any of the plurality of frac pumps, a manifold (e.g.,A,B,C,A,B,C), a mixing blender(s) (e.g.,and), and associated proppant storage unit, water supply unit (e.g.,A,B), and chemical unit (e.g.,A,B). The managing applicationexecuting on a computer (e.g., server)within the control vancan establish unit level control over the frac units communicated via the network. Unit level control can include sending instructions to the frac units and/or receiving equipment data from the frac units.

An alternate embodiment of a fracturing fleet with a clean pumping group and a dirty pumping group can utilize a single blender. Turning now to, an embodiment of a hydraulic fracturing systemthat can be utilized to pump hydraulic fracturing fluids into three or more wellbores, is illustrated. As depicted, the fracturing fleet can utilize a combined mix blender, e.g., a two tub blender and/or a fluid proportioner as noted herein, to supply fracturing fluids to a dirty fluid groupand a clean fluid group. The dirty fluid groupcan comprise a dirty side blender(e.g., a mixing blender) connected to a first manifoldA, a second manifoldB, and a third manifoldC. Although the frac pumpsare not illustrated, it is understood that one or more pumps can be fluidly connected to each manifold, e.g., the first manifoldA, the second manifoldB, and the third manifoldC. The clean fluid groupcan comprise a clean side blender(e.g., a mixing blender) connected to a fourth manifoldA, a fifth manifoldB, and a sixth manifoldC. The clean side blendercan be a boost pump, e.g., centrifugal pump, with chemical port to receive a chemical additive, such as a friction reducer. Although the frac pumpsare not illustrated, it is understood that one or more pumps can be fluidly connected to each manifold, e.g., the fourth manifoldA, the fifth manifoldB, and the sixth manifoldC. Slick water can be created within the clean side blenderand the dirty side blenderwith water from the water supply unitand gelling chemicals from the chemical unit. The dirty side blendercan mix proppant from the proppant storage unitto create the proppant slurry, e.g., the dirty fluid. The first manifoldA, the second manifoldB, and the third manifoldC can receive the dirty fluid from the dirty side blendervia the feed linesA,B, andC, respectively. The fourth manifoldA, the fifth manifoldB, and the sixth manifoldC can receive the clean fluid from the clean side blender. As previously described, the first wellboreA can receive the high pressure proppant slurry from the first manifoldA via high pressure lineA and high pressure gelled fluid from the fourth manifoldA via the high pressure lineA. The second wellboreB can receive the high pressure proppant slurry from the second manifoldB via high pressure lineB and high pressure gelled fluid from the fifth manifoldB via the high pressure lineB. The third wellboreC can receive the high pressure proppant slurry from the third manifoldC via high pressure lineC and high pressure gelled fluid from the sixth manifoldC via the high pressure lineC. Wye blocksA,B, andC can be used as described with reference to.

Alternatively, a combination manifold can be used to combine the dirty fluid volume and clean fluid volume to a single output. As previously disclosed, a combination manifold comprises a clean low pressure side manifold, e.g.,A,B,C, a dirty low pressure side manifold, e.g.,A,B,C, and a unitary high pressure manifold that combines the fluid outputs of the pumpsto a single high pressure line fluidly connected to a wellbore (e.g.,A,B,C). A first combination blender can supply fluid to both a dirty low pressure side manifoldA and clean low pressure side manifoldA which supply fluid to a dirty group of pumpsand a clean group of pumpswith a combined output to a unitary manifold output fluidly connected to the first wellboreA. A second combination blender can supply fluid to both a dirty low pressure side manifoldB and clean low pressure side manifoldB which supply fluid to a dirty group of pumpsand a clean group of pumpswith a combined output to a unitary manifold output fluidly connected to the second wellboreB. A third combination blender can supply fluid to both a dirty low pressure side manifoldC and clean low pressure side manifoldC which supply fluid to a dirty group of pumpsand a clean group of pumpswith a combined output to a unitary manifold output fluidly connected to the third wellboreC.

Turning now to, an example of unit level control of the frac units is illustrated. As an example, the water supply unitincludes a water supply tank, a unit control module, a unit sensor module, a water supply pump, and a pipeline. The unit control module(e.g., microprocessor controller) is in communication with and can operate the water supply pumpand an isolation valve. The unit sensors moduleis in communication with and can receive periodic sensor data from various sensors including temperature, pressure, flow rate, density, viscosity, chemical, vibration, strain, accelerometers, exhaust, acoustic, fluid level, equipment identity, and any other sensors typically used in the oilfield. The sensors can measure data at a periodic rate such as milliseconds, seconds, minutes, hours, days, and months. For example, the unit sensor modulecan receive periodic data from a water level sensor. The managing applicationwithin the control vancan establish unit level control of the water supply unitby communicatively connecting to the unit control moduleand the unit sensor module. The managing applicationwithin the control vancan control the isolation valveand water supply pumpvia the unit control module. The control vancan monitor the equipment data, such as water level and flow rate, via unit sensor module. Although the water supply unitis shown, all of the frac units can have a unit control moduleand unit sensor modulesuch as the hydration blender, the chemical unit, the proppant storage unit, the mixing blender, the manifold, and the plurality of frac pumps. The managing applicationwithin the control vancan direct the fracturing fleet, illustrated in,,, or, to prepare a fracturing fluid having a desired composition and pump the frac fluid at a desired pressure and flow rate, for example in accordance with a pumping schedule as described herein.

In an aspect, one or more frac units of the fracturing fleet, illustrated in,,, or, can be connected to the treatment wellat a production tree of the treatment well. For example, in, a wellhead isolation tool can connect the manifoldto the production tree. The wellhead isolation tool and production tree can include a unit sensor module (e.g.,) with one or more surface sensors, downhole sensors, and associated monitoring equipment. The sensors on surface frac units can measure the equipment operating conditions including temperature, pressure, flow rate, density, viscosity, chemical, vibration, strain, accelerometers, exhaust, acoustic, fluid level, and equipment identity. Sensors on the wellhead isolation tool and production tree can measure the environment inside the treatment well including temperature, pressure, flow rate, density, viscosity, chemical, vibration, strain, accelerometers, and acoustic. In an aspect, one or more frac units of the frac fleet can connect to the treatment wellwith a wellhead isolation tool, a wellhead, a production tree, a drilling tree, or a blowout preventer.

The method used by the managing applicationto pump the frac fluid at a desired pressure and flow rate can include an automated fleet control method following a pumping sequence. Turning now to, the hierarchy of a method of automated fleet controlis illustrated. The automated fleet control hierarchyincludes pumping sequence control, supervisory control, and a plurality of unit level controlA-Z. The pumping sequence controlmay be the managing applicationexecuting on the computer. An operator located in the control vanmay install a pumping sequence for a given fracturing service into the pumping sequence controlexecuting on the computer. The pumping sequence may be a series of steps, also called stages, defining one or more parameters of a fracturing job as a function of time or as a function of volume, wherein the parameters can include volumetric flow rate (e.g., barrels per minute) and pressure (e.g., pounds per square inch). A stage can be expressed by the time period required to pump a specific volume at a specified volumetric flow rate. The stage may also be expressed by the specific volume pumped during a time period by a specified volumetric flow rate. The volumetric flow rate can individually identify various components of the treatment volumetric flow rate, for example, water, clean flow rate (slick water), acid fluids, and dirty flow rate (proppant laden fluids). The addition of dry treatment additives, e.g., proppant, can be expressed as additive concentration (e.g., mass per unit volume such as pounds per gallon). The addition of liquid treatment additives, e.g., biocide, can be expressed as concentration units (e.g., gal of additive per 1000 gal of water). The pumping sequence can list one or more individual components and one or more combined components, for example, clean flow rate (e.g., slick water), proppant concentration (pounds per gallon), and dirty flow rate (e.g., proppant laden fluid). The pumping sequence can include stages with steady state flow rates and transition flow rates (ramp up flow rates and ramp down flow rates). The pumping sequence may include pressure as a limiting treatment value or as a target treatment value. When pressure is set as a limiting treatment value, the volumetric pump rate of the treatment may progress through a stage as long as the resulting pressure does not exceed the limiting treatment value. When pressure is set as a target treatment value, the volumetric pump rate of the treatment may deviate, e.g., increase or decrease, from an initial setting to achieve the target treatment value. Stages of a pumping sequence can correspond to various locations downhole, for example, fracturing a plurality of stages starting at the toe of a horizontal or lateral leg of a well and proceeding stage-wise to the heel of the lateral leg adjacent to a vertical portion of the wellbore. The pumping sequence control(e.g., managing application) can direct the supervisory controlto follow the pumping sequence. The supervisory controlcan direct the unit controlA-Z to communicate the commands and instructions to the unit control module of each frac unit, such as unit control moduleof the water supply unit. The supervisory controlmay direct two or more frac units to work in concert with the same instructions given to each unit. For example, the supervisory controlcan instruct the unit controlA-Z to direct a plurality of frac pumpsto operate at the same pump rate. The supervisory controlcan direct one or more frac units to operate within the same limits. For example, the supervisory controlcan instruct the one or more unit controlsA-Z to direct the mixing blenderto supply frac fluid to the plurality of frac pumpsat the same flow rate as the frac pumpsare pumping. Supervisory controllercan also instructto mix proppant, liquid additives, and/or dry additives at a particular rate and/or concentration.

A pumping sequence, also called a pumping schedule, may be comprised of a series of pumping stages with a transition between each pumping stage. For example, a pumping sequence may comprise a plurality of time-dependent pumping intervals, also called pumping stages, executed in a consecutive sequence (e.g., over a time period corresponding to a job timeline). The pumping stages may include steady-state stages and transition stages (e.g., having an increasing or decreasing parameter such as flow rate, proppant concentration, and/or pressure) that may be time dependent and represented as a function of time. Turning now to, a pumping sequenceis illustrated for a given treatment zone within a wellbore and comprises a plurality of stages,,, and. The pumping sequence is illustrated as a graph of fracturing job parameters such as pressure, flow rate, and proppant concentration (e.g., density) as a function of time. The chart includes a pressure axiswith units of pounds per square inch (psi), flowrate axiswith units of barrels per minute (bpm), a proppant concentration axiswith units of pounds per gallon (ppg), and a horizontal axis of time with units of seconds, minutes, or hours. The graph of the pumping sequenceincludes a pressure plot line, flowrate plot line, and proppant plot linefor a single zone hydraulic fracturing treatment. The first stageis a transition stage in the pumping sequence, where the pressure plot line, flowrate plot line, and proppant plot lineare increasing in value. The transition stages can be a smooth plotline (e.g.,and), indicating an approximate steady increase in pressure and flowrate or a stepped increase (e.g.,) indicating an incremental increase in proppant density. The second stagecan be a steady state stage where the pumping rate remains steady (also referred to simply as a steady stage). The pressure plot line, flowrate plot line, and proppant plot lineare steady in value. The third stagecan be a transition stage where the plotlines are decreasing in value to another steady state stage. Although three pumping stages are described, in understood that the pumping schedule could have 3, 6, 12, 24, or any number of pumping stages. A fracturing job can include treatment for 2, 3, 4, 5, 10, 20, 40, 80, or any number of zones, and a corresponding number of pumping sequencesof the type illustrated incan be used, and collectively a plurality of pumping sequences corresponding to a plurality of treatment zones (e.g., fracturing zones) within a wellbore may be referred to collectively as an overall well treatment/fracturing schedule for a given well. The pumping sequencecan include the pumping operations of multiple groups of pumping equipment, such as the clean fluid groupand the dirty fluid groupshown inor, within each stage or zone treated as will be described herein. In embodiments, one or more stages can be a combination of steady and transition stages, where some parameters change while others do not. For example, the pump rate to each well can remain constant while the proppant concentration is stepped or ramped up during the stage.

A pumping schedule to simultaneously treat three or more wells can be created based on pumping equipment availability. Turning now towith reference to, a combined pumping schedule, or combined pumping sequence(also referred to herein as a “multi-well treatment schedule” or “combined treatment schedule”), is illustrated for a given treatment zone within a wellbore. As detailed hereinbelow, the treatment schedule depicted inexceeds a maximum available rate, for example during interval. The chart inmay represent a combined pumping sequence with a pumping schedule for flow rate of proppant slurry delivered to the first wellboreA, a pumping schedule for the second wellboreB, and a pumping schedule for the third wellboreC, e.g., as shown in. The graph of the combined pumping sequenceincludes a flowrate plot lineA for a pumping sequence for the first wellboreA, a flowrate plot lineB for a pumping sequence for the second wellboreB, a flowrate plot lineC for a pumping sequence for the third wellboreC, and a total flowrate plot linefor the combined pumping sequence. The combined pumping sequenceand total flowraterepresents the summation of the flowrateA for the first wellboreA plus flowrateB for the second wellboreB plus the flowrateC for the third wellboreC. The combined pumping sequencemay have any number of stages, also called intervals. For example, pumping stage, also called interval, is a steady stage over an interval of time, that coincides with intervalfor flowratesA,B, andC, where the flowrates (A,B, andC) do not change. Intervalis a steady stage over an interval of time, that coincides with intervalfor flowrateA,B, andC, where the flowrates (A,B, andC) do not change. However, during interval, the total flowrateexceeds, by a value, the maximum available rate(which is an operating limit of the fracturing units). The total flowrateand the operating limit, e.g.,, may depend on the type of fracturing unit. For example, the operating limit of the water supply unitmay be the total flowrate of water. The operating limit for the chemical unitmay be the total flowrate of chemicals. The operating limit of the blender may be the total flowrate exiting the blender, the flowrate capacity of the supply lines to the blender, the flowrate capacity of the proppant supply, the maximum proppant metering of the blender, or the blender may be limited by the total volume of the blend tub. The operational limit of the proppant storage unitmay be the total flowrate of proppant. The operational limit of the frac pumpmay be a combination of pressure limit and total flowrate. The operational limit of the high pressure line, wellhead, and associated wellhead isolation equipment may be a combination of pressure limit and total flowrate. The combined pumping sequencemay be modified during the design phase to reduce the total flowratebelow the maximum available rateduring interval. Although the pumping sequencerepresents the flowrate delivered to the first wellboreA, the second wellboreB, and third wellboreC, it is understood that the combined pumping sequencecould represent four, five, or any number of wells. Although the combined pumping sequenceillustrates the total flowrateand maximum available flowrate, it is understood that the chart could present water flowrate, proppant flowrate, gelled fluid flowrate, proppant slurry flowrate, pump flowrate, chemical flowrate, blender tub level, or any other operational limit.

In embodiments, the plot lines and stage plans include concentration values instead of rate values such as depicted in,, and) for certain parameters. For example, the stage plan can, in embodiments, include concentration values for proppant and/or liquid chemicals such as friction reducer. In such embodiments, the pumping sequence control, supervisory control or unit control can be a concentration value and not a rate. The pumping sequence control can convert the concentration to a rate and verify that the maximum allowable rate is not exceeded.

In embodiments, optimum staggered start times for treatment of each of the multiple wells is calculated/determined. The optimum stagger times can be selected to ensure a treatment rate variable does not exceed a preselected maximum operating limit. This preselected operating limit may be the ultimate maximum capability of the fracturing unit, as described hereinbelow with reference to the embodiment of, or some lower limit than the ultimate maximum capability, as described hereinbelow with reference to. Setting an operating limit lower than the maximum rate can reserve available capacity for use if needed for adjustment to the treatment schedule for one or more of the multiple wells (e.g., and thus the combined treatment schedule) on-the-fly, as it can sometimes be required to adjust the treatment schedule on-the-fly based on the response of the wells to the treatment.

By way of example, a modified combined pumping schedule (also referred to as a modified pumping sequence) to simultaneously treat three or more wells can be modified based on the available pumping equipment operational limits. Turning now towith reference to, a modified combined pumping schedule, or modified combined pumping sequence, is illustrated. As detailed further hereinbelow, the modified treatment scheduleofutilizes staggered (or “offset”) start times for the treatments to the three wellbores to maintain the total flow ratebelow the maximum available flow rate. The chart inmay represent the flow rate of proppant slurry delivered to the first wellboreA, the second wellboreB, and the third wellboreC shown in. The graph of the modified combined pumping sequence) includes a flowrate plot lineA for the pumping sequence for the first wellboreA, a flowrate plot lineB for the pumping sequence for the second wellboreB, a flowrate plot lineC for the pumping sequence for the third wellboreC, and a total flowrate plot linefor the combined pumping sequence. The total flowraterepresents the summation of the flowrateA for the first wellboreA plus flowrateB for the second wellboreB plus flowrateC for the third wellboreC. The combined pumping sequencemay have any number of stages or timed intervals. The pumping sequence for the first wellboreA may begin before the pumping sequence for the second wellboreB and/or the third wellboreC. In embodiments, the pumping sequence for the second wellboreB may begin before the pumping sequence for the third wellboreC. The first pumping stage, or time interval, for the first wellboreA (and optionally every subsequent pumping stage) may begin before the first pumping stage (and optionally every subsequent pumping stage) for the second wellboreB and/or the third wellboreC. The first pumping stage, or time interval, for the second wellboreB (and optionally every subsequent pumping stage) may begin before the first pumping stage for the third wellboreC. Said another way, the first pumping stage for the second wellboreB, flowrateB, may begin at the end of the first pumping stage for the first well, flowrateA, and/or the first pumping stage for the third wellboreC, flowrateC, may begin at the end of the first pumping stage for the second well, flowrateB.

For example, pumping stageA is a steady stage over an interval of time (e.g., from tto t) for the flowrateA of the first wellA. The pumping stageB is a steady stage over an interval of time (e.g., from tto t) for the flowrateB of the second wellboreB that is identical in time interval and rate to pumping stageA for the flowrateA of the first wellA. Similarly, the pumping stageC is a steady stage over an interval of time (e.g., from tto t) for the flowrateC of the third wellboreC that is identical in time interval and rate to pumping stageA for the flowrateA of the first wellA and pumping stageB for the flowrateB of the second wellB. Pumping stageB begins (e.g., at t) before pumping stageA ends (e.g., at t); pumping stageC begins (e.g., at t) before pumping stageB ends (e.g., at t). The pumping sequence for the first well, flowrateA, includes pumping stageA,A, andA. The pumping sequence for the second well, flowrateB, includes corresponding pumping stageB,B, andB that are offset in time from the first well flowrateA. The pumping sequence for the third well, flowrateC, includes corresponding pumping stageC,C, andC that are offset in time from the first well flowrateA and the second well flowrateB.

The total flowratecan be below the maximum available rateby a minimum value. The minimum value can be maintained greater than or equal to zero, such that the total flowratecan be equal to or below the maximum ratefor the entire pumping schedule. Delaying the start of the pumping sequence for the second wellB (e.g., by a time t-t) and/or the third wellC (e.g., by a time t-t) relative to the start of the pumping sequence for the first wellboreA, and/or delaying the start of the pumping sequence for the third wellboreC (e.g., by a time t-t) relative to the second wellboreB can be utilized to decrease the total flowratebelow the maximum rate, for example as shown by reference numeral. Although the pumping sequenceillustrates the flowrate and maximum available rate, it should be understood that the chart could present water flowrate, proppant flowrate, gelled fluid flowrate, proppant slurry flowrate, pump flowrate, chemical flowrate, blender tub level, or any other operational limit.

As described hereinabove with reference to, the multi-well modified treatment schedulecan be designed, pre-planned, and/or adjusted “on the fly” (e.g., during the simultaneous treatment of the multiple wellbores) so the maximum of the parameter (e.g., total flow rate) does not to exceed the maximum operating limit (e.g., a maximum available rate).

As noted hereinabove, in embodiments, the multi-well modified treatment schedulecan be designed, pre-planned, and/or adjusted “on the fly” (e.g., during the simultaneous treatment of the multiple wellbores) so the maximum of the parameter (e.g., total flow rate) does not exceed a target operating limit (e.g., target maximum total flow rateA) that is less than the maximum operating limit (e.g., a maximum available ratecapability of the fracturing unit). As discussed in detail hereinbelow with reference to, the minimum valuecan be increased to provide an additional available capacity or bufferfor adjustment to the treatment schedule on-the-fly, as desired.

In embodiments, as further described hereinbelow with reference to, the multi-well modified treatment schedulecan be designed to minimize the required operating parameter (e.g., total flow rate) instead of solely optimizing to stay below a maximum (e.g., maximum available total flow rate) of the fracturing unit. For example, such embodiments, the offset between starting time of the first, second, and third (or more) well treatments can be selected to maximize the time the forklift has for exchanging containers on the proppant equipmentacross the full time range of the multi-well treatment.

In the embodiment of, described hereinabove, the second pumping sequence is staggered (e.g., delayed) relative to the first pumping sequence, and the third pumping sequence is staggered (e.g., delayed) relative to the second pumping sequence (and thus also the first pumping sequence). In the modified pumping sequence of, the second pumping sequence begins (e.g., at t) prior to the end of the first steady stageA of the first pumping sequence (e.g., at t), and the third pumping sequence begins (e.g., at t) prior to the end of the first steady stageB of the second pumping sequence (e.g., at t). Reference will now be made to, which is an illustration of another modified combined pumping sequenceaccording to an embodiment of the disclosure. As detailed further hereinbelow,depicts an embodiment in which the modified combined pumping schedule provides a leveled maximum rateand a substantial buffer. In the embodiment of, the entire first steady stageA of the first pumping sequence is completed prior to the start of the first steady stageB of the second pumping sequence, and the entire first steady stageB of the second pumping sequence is completed prior to the start of the first steady stageC of the third pumping sequence, and so on for more than three wellbores. In this embodiment, first steady stageA of the first pumping sequence ends (e.g., at time t) when the first steady stageB of second sequence begins (e.g., at t), and first steady stageB of the second pumping sequence ends (e.g., at time t) when the first steady stageC of third sequence begins (e.g., at t). The modified pumping sequence can be an optimized modified pumping sequence for which the total flow rateis less than target operating limitA, which target operating limitA is less than the maximum available rateby buffer. The maximum of the total flow rateof the modified pumping sequence is significantly less than the max available rate, by the difference′, where′≥. The modified pumping sequencecan be designed such that difference′ between the maximum of the total flow rateof the modified pumping sequence at least 10, 20, 30, or 40% less than the max available rate, (i.e., that′ is greater than or equal to 10, 20, 30, or 40% of the maximum available rate). The modified pumping sequencecan be designed such that differencebetween the target maximumA of the total flow rateof the modified pumping sequence at least 10, 20, 30, or 40% less than the max available rate, (i.e., thatis greater than or equal to 10, 20, 30, or 40% of the maximum available rate), thus providing an additional buffer capacity (e.g., additional flow rate capacity above an expected target maximum total flow rate).

In embodiments, the levelling provided by the modified combined pumping sequence can reduce the variability of an operating parameter by 5, 10, 15, 20, 25% or more, regardless of whether or not the initially combined pumping sequence exceeded an operating limit for that (or another) operating parameter.

Thus, the leveled and staggered modified pumping sequenceofcan provide a bufferrelative to the staggered modified pumping sequenceof. The leveled modified combined pumping sequencecan facilitate the operations. The leveled modified pumping sequenceofalso provides more level total flow raterelative to the modified pumping sequenceof, which can facilitate operating during the simultaneous wellbore treatments. For example, leveling the modified pumping sequence, as described with reference tocan provide for more consistent operation of a forklift, conveyor belt, front end loader, container flipper or rotator for proppant material (e.g., wet sand, dry sand, other proppant), and/or the mixing capacity of the blender tub.

The modified treatment schedulecan be designed, for example, to operate a fracturing unit as close to a steady rate as possible, as shown for total flow rate in. For example the stagger or offset time for the treatment schedule (e.g., the difference or offset t−tfrom the start of the first pumping sequence to wellboreA and second pumping sequence to wellboreB, the difference or offset t−tfrom the start of the first pumping sequence to wellboreA and third pumping sequence to wellboreC, and/or the difference or offset t−tfrom the start of the second pumping sequence to wellboreA and third pumping sequence to wellboreC), could be set to operate the (e.g., proppant) equipment at as constant a rate as possible throughout the full day. Such optimization can be utilized to reduce or minimize the required operating rate, rather than optimizing to stay below a maximum rate threshold (as described with reference to). In this manner, the time the forklift has for exchanging containers could be leveled (e.g., made more consistent) to remove both the very long and very short times between container changes. The planning of the optimum start time for the treatment of each well can be calculated using the supervisory control software (e.g., the supervisory control, as described herein) controlling the equipment performing the frac treatment.

When the first treatment stage is completed on a well, it is typically quickly followed up with a treatment of the next stage of the well. Transition times from the end of one treatment stage to the start of the next treatment stage can be on the order of ten to thirty minutes or more. It may be beneficial to take into consideration multiple treatment stages when planning the optimum stagger sequence for the start times of the various stages of the various wells. In other words, in embodiments, a better optimum may be attained by considering all treatments planned to be completed in a day as opposed to optimizing on a stage by stage basis. That is, the analysis to determine the modified treatment schedule can consider one or more (e.g., all) stages of each of the wells being treated simultaneously to optimally stagger and/or level the modified combined treatment schedule.

In embodiments, an optimum stagger for start times is determined and then additional time (e.g., additional transition time) can be added to the stagger to provide a buffer time that can be available if a treatment stage needs to be extended based on an on-the-fly decision made during the simultaneous treatment of the multiple wells. Another method to increase the rate on-the-fly during the treatment to one well can be to reduce the rate to one or more of the other wells being treated simultaneously with the one well. The allowable reduction amount per well and the priority of which one or more wells would have the rate reduced can be pre-planned in the supervisory control software controlling the equipment performing the frac treatment. Thus, in embodiments, the rate of a treatment parameter to one or more wells being simultaneously treated can be reduced during the treatment when it is determined that the treatment parameter needs to be increased on another one of the multiple wells, while still remaining below the maximum operating limit(e.g., of the blender). The reduction amount can be equally or unequally shared by the other wells being simultaneously treated. How the reductions are shared among the wells can be pre-planned into the pumping sequence control software prior to the start of the job. If a bufferhas been pre-programmed, the treatment parameter can be increased on one or more of the multiple wells, without reducing the rate of a treatment parameter to one or more other wells being simultaneously treated, as long as the increase does not surpass the maximum available limit (e.g., so long as the maximum available rateis not surpassed), although the target operating parameter (e.g., the target maximum rateA) may be (e.g., temporarily) surpassed.