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WO2024091449A1 - Dispositifs, systèmes et procédés de gestion de fluide de forage - Google Patents

Dispositifs, systèmes et procédés de gestion de fluide de forage Download PDF

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Publication number
WO2024091449A1
WO2024091449A1 PCT/US2023/035703 US2023035703W WO2024091449A1 WO 2024091449 A1 WO2024091449 A1 WO 2024091449A1 US 2023035703 W US2023035703 W US 2023035703W WO 2024091449 A1 WO2024091449 A1 WO 2024091449A1
Authority
WO
WIPO (PCT)
Prior art keywords
drilling fluid
drilling
recommendation
additive
setpoint
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2023/035703
Other languages
English (en)
Inventor
Colin Stewart
Wei Huang
Benjamin MERCERON
Kien TRAN
Chemsseddine BOUGUETTA
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Geoquest Systems BV
Schlumberger Technology Corp
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Geoquest Systems BV
Schlumberger Technology Corp
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Geoquest Systems BV, Schlumberger Technology Corp filed Critical Schlumberger Canada Ltd
Priority to CN202380082040.2A priority Critical patent/CN120344749A/zh
Priority to EP23805297.1A priority patent/EP4602243A1/fr
Publication of WO2024091449A1 publication Critical patent/WO2024091449A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/01—Arrangements for handling drilling fluids or cuttings outside the borehole, e.g. mud boxes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/06—Arrangements for treating drilling fluids outside the borehole

Definitions

  • Downhole drilling often involves degrading a formation by rotating a drill bit against a formation at the bottom of a wellbore.
  • Drilling fluid or drilling mud
  • the drilling fluid may cool the drill bit, collect the cuttings generated by the drill bit, and carry the cuttings to the surface.
  • the formula of a drilling fluid is often engineered to have particular properties, such as shear strength, density, viscosity, and so forth. These properties relate to the drilling effectiveness drilling operation. As the drilling fluid collects the cuttings and interacts with the formation, the properties of the drilling fluid may be altered. Changing the properties of the drilling fluid may result in a reduced effectiveness of the drilling operation, which may result in damage to the downhole drilling assembly.
  • a drilling fluid engineer may provide additives to the drilling fluid to maintain its desired properties.
  • the drilling fluid engineer typically directly manages analysis of the properties of the returned fluid.
  • the drilling fluid engineer uses a combination of trial and error and his or her extensive experience in drilling fluid management to determine the type and amount of additives to add to the drilling fluid. This process is imprecise and expensive and may result in decreased effectiveness of the drilling operation and increased drilling fluid costs.
  • the drilling engineer may have multiple additives to change the drilling fluid properties. Each of the additives may change multiple properties, and a combination of additives and additive quantities may have unpredictable consequences on the drilling fluid properties.
  • a drilling fluid management system receives a measurement of measured drilling fluid properties for a drilling fluid.
  • the drilling fluid management system compares the measurement of the measured drilling fluid properties to setpoint drilling fluid properties to generate a difference between the measurement and the setpoint drilling fluid properties. Based at least in part on the difference between the measurement and the setpoint drilling fluid properties, the drilling fluid management system prepares a recommendation to return the drilling fluid to the setpoint drilling fluid properties.
  • a drilling fluid management system monitors drilling fluid properties of a drilling fluid at a surface location. The system determines whether the drilling fluid properties are within setpoint drilling fluid properties. The system generates a recommendation to return the drilling fluid to the setpoint drilling fluid properties.
  • FIG. 1 shows one example of a drilling system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure
  • FIG. 2 is a representation of a drilling fluid management system, according to at least one embodiment of the present disclosure.
  • FIG. 3 is a flowchart of a method for managing a drilling fluid, according to at least one embodiment of the present disclosure
  • FIG. 4 is a flowchart of a method for managing a drilling fluid, according to at least one embodiment of the present disclosure
  • FIG. 5 is a flowchart of a method for managing a drilling fluid, according to at least one embodiment of the present disclosure
  • FIG. 6 is a flowchart of a method for managing a drilling fluid, according to at least one embodiment of the present disclosure.
  • FIG. 7 illustrates certain components that may be included within a computer system, according to at least one embodiment of the present disclosure.
  • a drilling fluid management system may monitor drilling fluid properties for the drilling fluid.
  • a drilling fluid manager may compare the measured drilling fluid properties of the drilling fluid to setpoint drilling fluid properties. If the drilling fluid has deviated from the setpoint drilling fluid properties, the drilling fluid manager may prepare a recommendation to return the drilling fluid to the setpoint drilling fluid properties.
  • the recommendation may include mechanisms to return the drilling fluid to the setpoint drilling fluid properties, including the use of additives, adjustments to surface drilling parameters, a volume recommendation to adjust the total drilling fluid volume, any other adjustments to drilling fluid properties, and combinations thereof.
  • the drilling fluid management system may implement the recommendation. In this manner, the drilling fluid management system may maintain the drilling fluid within the setpoint drilling fluid properties.
  • FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102.
  • the drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102.
  • the drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of the drill string 105.
  • BHA bottomhole assembly
  • the drill string 105 may include several joints of drill pipe 108 connected end- to-end through tool joints 109.
  • the drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106.
  • the drill string 105 may further include additional components such as subs, pup joints, etc.
  • the drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface.
  • the drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.
  • the drilling fluid may be engineered with particular drilling fluid properties to facilitate cooling the bit 110, the cutting structures thereon, lifting cuttings out of the wellbore, supporting the walls of the wellbore, and so forth.
  • the drilling fluid may be stored in a mud pit 112 at a surface location 111.
  • Drilling fluid may be drawn from the mud pit 112 and pumped into the drill string 105 using one or more mud pumps 114.
  • the drilling fluid may carry cuttings, swarf, or other material out of the wellbore 102.
  • the cuttings, swarf, and other material may cause a change to the properties of the drilling fluid, such as a change in density, shear stress, viscosity, and so forth.
  • the drilling fluid is returned to the surface location 111, such as to the mud pit 112, the properties of the drilling may be changed by the introduction of contaminants from the wellbore 102.
  • a measurement station 116 or sensor station may measure the parameters of the drilling fluid.
  • the drilling fluid may have setpoint fluid properties.
  • the drilling fluid may be less effective at cooling the bit 110, the cutting structures thereon, lifting cuttings out of the wellbore, supporting the walls of the wellbore, and so forth.
  • a drilling fluid engineer may add one or more additives to the drilling fluid. For example, the drilling fluid engineer may add the additives to the drilling fluid in the mud pit 112 and mix the drilling fluid and the additives.
  • the measurement station 116 may measure the parameters of the re-mixed drilling fluid and compare them to the setpoint fluid properties. Using the measured parameters, the drilling fluid engineer may continue to add additives until the measured parameters are within the setpoint fluid properties. This process is effectively trial and error, tempered by the experience of the drilling fluid engineer.
  • a drilling fluid manager may generate a recommendation for actions a drilling operator may take to return the drilling fluid to the setpoint fluid properties.
  • the drilling fluid manager may monitor the parameters of the drilling fluid and determine a combination of additives to add to the drilling fluid.
  • the drilling fluid manager may provide the recommendation to an additive manager, and the additive manager may add the additive to the drilling fluid.
  • the drilling fluid manager may provide the recommendation to a drilling operator and the drilling operator may add the additive to the drilling fluid. This may help to improve the accuracy of the return of the drilling fluid to the setpoint drilling fluid properties.
  • the recommendation may include an additive volume and/or additive schedule. The drilling operator and/or the additive manager may add the additive according to the additive volume and/or the additive schedule.
  • the drilling fluid manager may analyze a total volume of fluid in the drilling system 100.
  • the drilling fluid manager may analyze the volume of fluid in the mud pit 112.
  • the recommendation may include a volume recommendation to add and/or remove a volume of the drilling fluid to maintain a setpoint volume of the drilling fluid. The volume recommendation may help to maintain the appropriate volume of drilling fluid in the drilling system 100.
  • the drilling fluid manager may receive wellbore information, such as wellbore depth, formation information, and so forth.
  • the drilling fluid manager may determine the recommendation based on the wellbore information. For example, the drilling fluid manager may determine an additive type, volume, schedule, and so forth based on the formation of the BHA 106. This may help the drilling fluid manager to generate recommendations that may move the drilling fluid closer to the setpoint.
  • the recommendation may include one or more adjustments to surface drilling parameters.
  • the recommendation may include an adjustment to the rotational rate of the drill string 105 in rotations per minute (“RPM”), volumetric flow rate of the drilling fluid, weight on bit (“WOB”), any other surface drilling parameter, and combinations thereof.
  • adjusting a surface drilling parameter may help to improve the rate of penetration (“ROP”) of the drilling system 100 for the existing drilling fluid properties.
  • adjusting the surface drilling parameters may be performed in addition to providing an additive to adjust the drilling fluid properties.
  • adjusting the surface drilling parameters may be performed as an alternative to providing an additive to adjust the drilling fluid properties.
  • the drilling fluid manager may review future drilling plans to prepare the recommendation. For example, the drilling fluid manager may review the wellbore trajectory compared to the location of the bit 110 for projected interception with a particular formation, reservoir, or other geological feature. In some examples, the drilling fluid manager may review plans for the termination of drilling activities, installation of wellbore structures, any other future drilling plans, and combinations thereof. In some embodiments, if a change in wellbore status is imminent, the recommendation may be different than if no change were forthcoming. For example, the recommendation may not include an additive, may include an additive in a different volume or addition schedule, or may include a different additive than would otherwise have been recommended with no forecast change in wellbore status.
  • a recommendation without additives may be more cost-effective than adding the additives because drilling with drilling fluid that has drilling fluid properties that have varied from the setpoint may be cheaper than the cost of adding the additives.
  • the BHA 106 may include the bit 110 or other components.
  • An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 1 10).
  • additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.
  • the BHA 106 may further include a rotary steerable system (RSS).
  • the RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore.
  • At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and/or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.
  • an absolute reference frame such as gravity, magnetic north, and/or true north.
  • the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.
  • special valves e.g., kelly cocks, blowout preventers, and safety valves.
  • Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.
  • the bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials.
  • the bit 110 may be a drill bit suitable for drilling the earth formation 101.
  • Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits.
  • the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof.
  • the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102.
  • the bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.
  • FIG. 2 is a representation of a drilling fluid management system 218, according to at least one embodiment of the present disclosure.
  • Each of the components of the drilling fluid management system 218 may include software, hardware, or both.
  • the components may include one or more instructions stored on a computer-readable storage medium and executable by processors of one or more computing devices, such as a client device or server device. When executed by the one or more processors, the computer- executable instructions of the drilling fluid management system 218 may cause the computing device(s) to perform the methods described herein.
  • the components may include hardware, such as a special-purpose processing device to perform a certain function or group of functions.
  • the components of the drilling fluid management system 218 may include a combination of computer-executable instructions and hardware.
  • the components of the drilling fluid management system 218 may, for example, be implemented as one or more operating systems, as one or more stand-alone applications, as one or more modules of an application, as one or more plug-ins, as one or more library functions or functions that may be called by other applications, and/or as a cloud-computing model.
  • the components may be implemented as a stand-alone application, such as a desktop or mobile application.
  • the components may be implemented as one or more web-based applications hosted on a remote server.
  • the components may also be implemented in a suite of mobile device applications or “apps.”
  • the drilling fluid management system 218 may be used in association with a drilling system, such as the drilling system 100 of FIG. 1.
  • the drilling fluid management system 218 may include one or more setpoint drilling fluid properties 220.
  • the setpoint drilling fluid properties 220 may be included as part of a well design.
  • the setpoint drilling fluid properties 220 may be based on a target wellbore trajectory that travels through target or anticipated formations.
  • the setpoint drilling fluid properties 220 may be determined during wellbore planning or scheduling.
  • the setpoint drilling fluid properties 220 may be designed to maintain drilling conditions that improve the ROP.
  • the drilling fluid management system 218 may include a drilling fluid manager 222.
  • the drilling fluid manager 222 may receive the setpoint drilling fluid properties 220.
  • a measurement collector 224 may collect and/or receive various measurements related to the drilling system.
  • the measurement collector 224 may collect one or more measured drilling fluid properties 226.
  • the measured drilling fluid properties 226 may include any measurable drilling fluid parameter.
  • the measured drilling fluid properties 226 may include one or more of fluid density, fluid viscosity, fluid shear strength, clay concentration, oil to water ratio, lime concentration, pH, methylene blue die (MBT) absorption, salinity, drill solid contents, product concentration, any other drilling fluid parameter, and combinations thereof.
  • the measurement collector 224 may collect and/or receive surface drilling parameters 228.
  • the surface drilling parameters 228 may include any drilling parameter measured and/or measurable at the surface, including one or more of WOB, torque on bit (“TOB”), drilling fluid flow rate, drilling fluid pressure, RPM, any other surface drilling parameter, and combinations thereof.
  • the measurement collector 224 may collect and or receive information regarding the drilling fluid inventory 230.
  • the drilling fluid inventory 230 may include any aspects of the inventory of the drilling fluid.
  • the drilling fluid inventory 230 may include a total volume of the fluid used in the drilling system.
  • the drilling fluid inventory 230 may include a list of drilling fluid additives and their associated quantities (e.g., weights and/or volumes) located at the rig site, such as additives located in one or more additive tanks.
  • the drilling fluid inventory 230 may include an additive history, including a historical list of the type and quantities of additives previously added to the drilling fluid.
  • the drilling fluid manager 222 may receive the measurements from the measurement collector 224.
  • a comparison manager 232 may compare the measured drilling fluid properties 226 to the setpoint drilling fluid properties 220.
  • the setpoint drilling fluid properties 220 may be the drilling fluid properties that may help to improve the ROP.
  • the comparison manager 232 may determine the difference between the setpoint drilling fluid properties 220 and the measured drilling fluid properties 226. For example, the comparison manager 232 may determine how far from the setpoint drilling fluid properties 220 the measured drilling fluid properties 226 have strayed.
  • a recommendation generator 234 of the drilling fluid manager 222 may prepare a recommendation for adjustments to the drilling fluid management system 218.
  • the recommendation generator 234 may prepare a recommendation that may help to maintain the drilling fluid at the setpoint drilling fluid properties 220.
  • the recommendation generator 234 may prepare a recommendation that includes one or more recommended additives to add to the drilling fluid.
  • the additives may change the properties of the drilling fluid.
  • the recommendation may include a type and quantity (e.g., volume and/or weight) of the additives to change the properties of the drilling fluid.
  • the type and quantity of the additives may change the properties of the drilling fluid to return to the setpoint drilling fluid properties 220.
  • the recommendation prepared by the recommendation generator 234 may help to maintain the drilling fluid within the setpoint drilling fluid properties 220.
  • the recommendation generator 234 may prepare a recommendation more accurately, precisely, and/or quickly than under conventional mechanisms.
  • the recommendation generator 234 may prepare a recommendation that incorporates data from the measured drilling fluid properties 226, offset wellbores, chemistry of the drilling fluid, and other factors. This may help to improve the quality of the recommendation and/or the speed of the return of the drilling fluid to the setpoint drilling fluid properties 220.
  • the recommendation generator 234 may incorporate any information about the drilling system into the recommendation.
  • the recommendation generator 234 may incorporate the surface drilling parameters 228.
  • the surface drilling parameters 228 may impact how the additives and/or the drilling fluid properties impact the drilling of the wellbore.
  • the recommendation generator 234 may generate a recommendation based on the surface drilling parameters 228. This may help the additives to move the drilling fluid to the setpoint drilling fluid properties 220 faster and/or more accurately.
  • the recommendation generator 234 may incorporate the drilling fluid inventory 230 into the recommendation. For example, the recommendation generator 234 may review the available types and quantities of the additives. Based on the drilling fluid inventory 230, the recommendation generator 234 may prepare the recommendation using the available additives and other materials. This may help the drilling fluid move back to the setpoint drilling fluid properties 220 without delay based on waiting for a shipment or arrival of an additive or other material to the drill site. [0040] In some embodiments, the recommendation generator 234 may receive future plans for the wellbore. For example, the recommendation generator 234 may receive information regarding changes in wellbore status. Changes in wellbore status may include changes in setpoint drilling fluid properties 220.
  • the recommendation generator 234 may modify the recommendation based on the threshold period of time.
  • the recommendation may include a recommendation not to adjust the drilling parameters if the setpoint drilling fluid properties 220 are scheduled to change.
  • the recommendation may include a recommendation to adjust the drilling flid to reach the new setpoint drilling fluid properties 220. For example, if the duration of time to change the drilling fluid properties will intersect or overlap the change in the setpoint drilling fluid properties 220, then the recommendation may include additives that may change the drilling fluid properties to the new setpoint drilling fluid properties 220.
  • the future plans may include a change in the drilling status of the wellbore.
  • the future plans may include an end to drilling activities. If the end to the drilling activities is within the threshold period of time, then the recommendation may be to not change the drilling fluid properties.
  • the recommendation may incorporate the anticipated cost. For example, each of the additives has an associated cost. And not changing a drilling fluid parameter based on future plans has an associated cost.
  • the recommendation generator 234 may prepare the recommendation based on the associated cost. For example, the recommendation generator 234 may prepare the recommendation based on the lowest cost option.
  • the drilling fluid manager 222 may review the total volume of drilling fluid within the drilling system, including the total volume of drilling fluid within the tank, the wellbore, and so forth. The total volume of fluid may change based on fluid ingress from the wellbore, wellbore advance of depth, fluid additives, and so forth.
  • the recommendation generator 234 may prepare a volume recommendation to adjust the total volume of drilling fluid. For example, the volume recommendation may recommend to reduce the total volume of drilling fluid or increase the total volume of drilling fluid. This may help to manage the total amount of drilling fluid of the drilling system.
  • the setpoint drilling fluid properties 220 may include a range of parameters.
  • the recommendation may be to make no change to the drilling fluid.
  • the comparison manager 232 may monitor the received measurements from the measurement collector 224. When the comparison manager 232 determines that the measured drilling fluid properties have moved out of the range of parameters, then the recommendation generator 234 may prepare a recommendation to adjust the drilling fluid properties.
  • the drilling fluid management system 218 includes an additive manager 236.
  • the additive manager 236 may receive the recommendation generated by the recommendation generator 234.
  • the additive manager 236 may implement the recommendation.
  • the additive manager 236 may add the additives and the associated quantities to the drilling fluid.
  • the additive manager 236 may include an automatic additive adding system.
  • the additive tanks may be connected to the drilling fluid system, such as the drilling fluid tank (e g., the mud pit), such as through a series of pipes, pumps, hoppers, any other system, and combinations thereof.
  • the additive manager 236 may be connected to valves or other actuation mechanisms, and the additive manager 236 may cause the additives to flow from the additive tanks to the drilling fluid system by actuating the actuation mechanisms. In some embodiments, the additive manager 236 may actuate the actuation mechanisms with a timing to add, according to the recommendation, the recommended quantity of the additive in the recommended schedule.
  • the drilling fluid management system 218 may continue to monitor the drilling fluid status.
  • the measurement collector 224 may collect and/or receive updated measurements, including one or more of the measured drilling fluid properties 226, the surface drilling parameters 228, or the drilling fluid inventory 230.
  • the drilling fluid manager 222 may receive the updated measurements, and the comparison manager 232 may monitor the comparison between the updated measurements and the setpoint drilling fluid properties 220. In some embodiments, this process may be performed in real-time. This may allow the drilling fluid management system 218 to maintain the drilling fluid at the setpoint drilling fluid properties 220 or within the range of parameters.
  • the recommendation generator 234 may prepare a recommendation to change the setpoint drilling fluid properties 220. For example, based on measurements received from the measurement collector 224, the recommendation generator 234 may determine that the setpoint drilling fluid properties 220 may be changed to improve the ROP. In this manner, the recommendation generator 234 may help to maintain the drilling fluid having drilling fluid properties that improve the ROP.
  • the drilling fluid management system 218 may be implemented at a surface location.
  • the surface location may include a drill rig and associated equipment and structures.
  • portions of the drilling fluid management system 218 may be performed remotely.
  • the drilling fluid manager 222 may be implemented on a remote computing device, such as a cloud server or a cloud computing device.
  • the drilling fluid manager 222 may be implemented on a local network, such as a network that is local to a single drill rig site.
  • FIGS. 3-6, the corresponding text, and the examples provide a number of different methods, systems, devices, and non-transitory computer-readable media of the drilling fluid management system 218 of FIG. 2.
  • one or more embodiments may also be described in terms of flowcharts comprising acts for accomplishing a particular result, as shown in the figures. Each of the methods described may be performed with more or fewer acts. Further, the acts may be performed in differing orders. Additionally, the acts described herein may be repeated or performed in parallel with one another or parallel with different instances of the same or similar acts.
  • FIG. 3 illustrates a flowchart of a series of acts for a method 338 for managing a drilling fluid composition in accordance with one or more embodiments. While FIG. 3 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 3. The acts of FIG. 3 may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 3. In some embodiments, a system may perform the acts of FIG. 3.
  • a drilling fluid manager may receive measurements of drilling fluid properties of a drilling fluid at 340.
  • the drilling fluid manager may receive as many or more measurements of the drilling fluid properties as the drilling system includes different additives.
  • a measurement collector may monitor measurements of the drilling fluid properties.
  • the measurement collector may monitor the measurements while a recommendation is being implemented (e.g., while the additive manager is implementing the recommendation, while the additive manager is adding the additives to the drilling fluid).
  • the drilling fluid manager may compare the measurements to setpoint fluid properties. At 342, the drilling fluid manager may determine whether the measured parameters are within a pre-determined threshold of the setpoint fluid properties. If the measured parameters are within the threshold, then the drilling fluid manager may continue to monitor the measured drilling fluid properties until the parameters are outside of the threshold.
  • the drilling fluid manager may determine a magnitude of a difference between the measured drilling fluid properties and the pre-determined setpoint at 344. Based on the difference and an additive model, the drilling fluid manager may prepare a recommendation to return the drilling fluid properties to the setpoint drilling fluid properties at 346. For example, the drilling fluid manager may include in the recommendation an additive amount for one or more additives in the drilling system. In some embodiments, an additive manager may add the amount of the additive to the drilling fluid. For example, the drilling fluid manager may instruct one or more valves or other control systems to automatically add the additive to the drilling fluid and mix them together. In some examples, the drilling fluid manager may provide an instruction to a drilling fluid engineer or other drilling operator to add the amounts of the additive to the drilling fluid.
  • the additive manager may include an additive control system that may physically add the additives to the drilling fluid.
  • a fluid additive including liquids, gels, slurries, and other fluids, may include one or more pipes, tanks, or other fluid conduits connected to the drilling fluid storage and/or a drilling fluid mixing chamber.
  • the fluid storage systems may be connected to the drilling fluid mixing chamber with a valve and a volume control system (e.g., a flow meter, a timer, or other volume control system). Based on the determined additive amount and schedule, the additive manager may cause the additive control system to add the amount of the additive in the identified schedule.
  • a fluid additive may include one or more solid materials, including powders, granules, bricks, or solid fluid additive.
  • the solid fluid additive may be stored in a storage system, such as a hopper.
  • the hopper may include an additive volume control.
  • the additive volume control may include one or more scales.
  • the hopper may feed the solid additive into a container on the scales, and the scales may weigh the additive to the additive amount.
  • the additive control system may then empty the container into the drilling fluid, such as in a drilling fluid mixing chamber.
  • the additive control system may, to comply with the additive schedule and/or based on the container capacity, measure and add multiple batches of the additive. In this manner, the additive control system may help to automate the drilling fluid management process.
  • the method 338 may be repeated.
  • the measurement collector may continue to monitor the drilling fluid properties.
  • the recommendation may include an implementation time.
  • the measurement collector may monitor the drilling fluid properties throughout the implementation time.
  • the method 338 may be repeated. This may help to monitor whether the drilling fluid has returned to the setpoint drilling parameters.
  • the drilling fluid manager may help to maintain the drilling fluid within the setpoint drilling fluid properties.
  • the method 338 may be implemented in the drilling fluid management system 218 of FIG. 2. This may help to improve the responsiveness of the recommendations and their associated implementations.
  • FIG. 4 illustrates a flowchart of a series of acts for a method 448 for managing a drilling fluid composition in accordance with one or more embodiments. While FIG. 4 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 4. The acts of FIG. 4 may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 4. In some embodiments, a system may perform the acts of FIG. 4.
  • the method 448 may include drilling for a period of time at 450. Put another way, the method 448 may occur while performing drilling activities. While drilling, the drilling system may circulate drilling fluid through the wellbore until a portion of the drilling fluid returns to the surface location at 452. For example, drilling fluid may be circulated into the drill string while drilling, pass through the drill string to the wellbore bottom, and pass through the annulus between the drill string and the formation, and pass out of the wellbore to be deposited in a mud pit.
  • the drilling fluid properties of the drilling fluid may be measured at 454. As discussed herein, the properties of the drilling fluid may change based on the addition of cuttings and other material encountered while drilling.
  • a drilling fluid manager may compare and determine a difference between the measured drilling fluid properties and pre-determined setpoint fluid properties at 456. Based on the difference, the drilling fluid manager may prepare a recommendation at 458. The method 448 may then include implementing the recommendation at 460. For example, the additive manager may add the additive amount of the additives to the returned drilling fluid. This may cause the parameters of the returned drilling fluid to return to within the threshold of the setpoint fluid properties.
  • the re-mixed returned drilling fluid may be circulated through the wellbore again, and the method 448 may be repeated indefinitely.
  • the drilling operation may continue to drill and circulate the drilling fluid for a second period of time.
  • the drilling fluid properties of the circulated drilling fluid may be measured. Any differences between the measured fluid parameters used to determine an updated recommendation.
  • the updated recommendation may be implemented, and the drilling fluid circulated, with the re-circulated fluid analyzed and new updated recommendations presented. In this manner, the method 448 may help to automatically maintain the drilling fluid properties of the drilling fluid.
  • FIG. 5 illustrates a flowchart of a series of acts for a method 562 for managing a drilling fluid composition in accordance with one or more embodiments. While FIG. 5 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 5. The acts of FIG. 5 may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 5. In some embodiments, a system may perform the acts of FIG. 5.
  • a drilling fluid manager may receive a measurement of drilling fluid properties of a drilling fluid at 564.
  • the drilling fluid manager may compare the measurement of the drilling fluid properties to setpoint drilling fluid properties to generate a difference between the measurement and the setpoint drilling parameters at 566. Based at least in part on the difference between the measurement and the setpoint drilling fluid properties, the drilling fluid manager may prepare a recommendation to return the drilling fluid to the setpoint drilling fluid properties at 568.
  • FIG. 6 illustrates a flowchart of a series of acts for a method 670 for managing a drilling fluid composition in accordance with one or more embodiments. While FIG. 6 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 6. The acts of FIG. 6 may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 6. In some embodiments, a system may perform the acts of FIG. 6.
  • the method 670 may include monitoring drilling fluid properties.
  • a drilling fluid manager may monitor drilling fluid properties of a drilling fluid at a surface location at 672.
  • monitoring drilling fluid properties may include receiving measurements from one or more sensors.
  • monitoring drilling fluid properties may include collecting measurements from one or more sensors.
  • monitoring drilling fluid properties may include collecting the drilling fluid properties periodically.
  • monitoring drilling fluid properties may include collecting the drilling fluid properties episodically.
  • monitoring drilling fluid properties may occur at a surface location.
  • monitoring drilling fluid properties may occur downhole.
  • the drilling fluid manager may determine whether the drilling fluid properties are within setpoint drilling fluid properties at 674.
  • the drilling fluid manager may then generate a recommendation to return the drilling fluid to the setpoint drilling fluid properties at 676.
  • FIG. 7 illustrates certain components that may be included within a computer system 700.
  • One or more computer systems 700 may be used to implement the various devices, components, and systems described herein.
  • the computer system 700 includes a processor 701.
  • the processor 701 may be a general -purpose single or multi -chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc.
  • the processor 701 may be referred to as a central processing unit (CPU). Although just a single processor 701 is shown in the computer system 700 of FIG. 7, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.
  • the computer system 700 also includes memory 703 in electronic communication with the processor 701.
  • the memory 703 may be any electronic component capable of storing electronic information.
  • the memory 703 may be embodied as random access memory (RAM), read-only memory (ROM), magnetic disk storage media, optical storage media, flash memory devices in RAM, on-board memory included with the processor, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM) memory, registers, and so forth, including combinations thereof.
  • Instructions 705 and data 707 may be stored in the memory 703.
  • the instructions 705 may be executable by the processor 701 to implement some or all of the functionality disclosed herein. Executing the instructions 705 may involve the use of the data 707 that is stored in the memory 703. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 705 stored in memory 703 and executed by the processor 701. Any of the various examples of data described herein may be among the data 707 that is stored in memory 703 and used during execution of the instructions 705 by the processor 701.
  • a computer system 700 may also include one or more communication interfaces 709 for communicating with other electronic devices.
  • the communication interface(s) 709 may be based on wired communication technology, wireless communication technology, or both.
  • Some examples of communication interfaces 709 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.
  • USB Universal Serial Bus
  • IEEE Institute of Electrical and Electronics Engineers
  • IR infrared
  • a computer system 700 may also include one or more input devices 711 and one or more output devices 713.
  • input devices 711 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen.
  • output devices 713 include a speaker and a printer.
  • One specific type of output device that is typically included in a computer system 700 is a display device 715.
  • Display devices 715 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like.
  • a display controller 717 may also be provided, for converting data 707 stored in the memory 703 into text, graphics, and/or moving images (as appropriate) shown on the display device 715.
  • the various components of the computer system 700 may be coupled together by one or more buses, which may include a power bus, a control signal bus, a status signal bus, a data bus, etc.
  • buses may include a power bus, a control signal bus, a status signal bus, a data bus, etc.
  • the various buses are illustrated in FIG. 7 as a bus system 719.
  • drilling fluid management system has been primarily described with reference to wellbore drilling operations; the drilling fluid management systems described herein may be used in applications other than the drilling of a wellbore.
  • drilling fluid management systems according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources.
  • drilling fluid management systems of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
  • references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.
  • any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein.
  • Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure.
  • a stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result.
  • the stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
  • any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention concerne un système de gestion de fluide de forage pouvant recevoir une mesure de propriétés de fluide de forage mesurées pour un fluide de forage. Un système de gestion de fluide de forage peut comparer la mesure des propriétés de fluide de forage mesurées à des propriétés de fluide de forage de consigne pour générer une différence entre la mesure et les propriétés de fluide de forage de consigne. Un système de gestion de fluide de forage peut, en fonction, au moins en partie, de la différence entre la mesure et les propriétés de fluide de forage de consigne, préparer une recommandation pour ramener le fluide de forage aux propriétés de fluide de forage de consigne.
PCT/US2023/035703 2022-10-26 2023-10-23 Dispositifs, systèmes et procédés de gestion de fluide de forage Ceased WO2024091449A1 (fr)

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CN202380082040.2A CN120344749A (zh) 2022-10-26 2023-10-23 用于钻井流体管理的设备、系统和方法
EP23805297.1A EP4602243A1 (fr) 2022-10-26 2023-10-23 Dispositifs, systèmes et procédés de gestion de fluide de forage

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US20190055797A1 (en) * 2016-01-25 2019-02-21 Shell Oil Company Method and system for automated adjustment of drilling mud properties
WO2021010945A1 (fr) * 2019-07-12 2021-01-21 Halliburton Energy Services, Inc. Formulation dynamique de fluides de forage à base d'eau
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