DEVICES, SYSTEMS, AND METHODS FOR DRILLING FLUID MANAGEMENT

Abstract

A drilling fluid management system may receive a measurement of measured drilling fluid properties for a drilling fluid. A drilling fluid management system may compare 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. A drilling fluid management system may, based at least in part on the difference between the measurement and the setpoint drilling fluid properties, prep are a recommendation to return the drilling fluid to the setpoint drilling fluid properties.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63/381,033, filed on Oct. 26, 2022, which is hereby incorporated by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

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, is often circulated through the wellbore from a mud pit on the surface to the drill bit. 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.

Conventionally, as the drilling fluid circulates back to the surface, 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 then 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. In particular, 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.

SUMMARY

In some embodiments, 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.

In some embodiments, 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.

This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure may be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

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; and

FIG. 7 illustrates certain components that may be included within a computer system, according to at least one embodiment of the present disclosure.

DETAILED DESCRIPTION

This disclosure generally relates to devices, systems, and methods for managing a drilling fluid for a drilling system. 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. This may help to improve the quality of the drilling system, and may help to improve the rate of penetration (“ROP”).

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.

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. In some embodiments, 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. As the drilling fluid flows out of the drill string 105, such as through the bit 110 or other location, 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. When 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. In some embodiments, when the measured parameters of the drilling fluid have deviated from the setpoint fluid properties by more than a threshold amount, then 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. Conventionally, as discussed herein, when the measured parameters deviate from the setpoint fluid properties, 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.

In accordance with one or more embodiments of the present disclosure, 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. For example, 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. In some embodiments, 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. In some embodiments, 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.

In some embodiments, the drilling fluid manager may analyze a total volume of fluid in the drilling system 100. For example, the drilling fluid manager may analyze the volume of fluid in the mud pit 112. In some embodiments, 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.

In some embodiments, 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.

In some embodiments, the recommendation may include one or more adjustments to surface drilling parameters. For example, 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. In some situations, 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. In some embodiments, adjusting the surface drilling parameters may be performed in addition to providing an additive to adjust the drilling fluid properties. In some embodiments, adjusting the surface drilling parameters may be performed as an alternative to providing an additive to adjust the drilling fluid properties.

In some embodiments, 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. This may help to reduce the adding of additives that may not have time to be effective. In some embodiments, 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 110). Examples of 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.

In general, 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.

The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, 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. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, 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. For example, 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. Alternatively, the components may include hardware, such as a special-purpose processing device to perform a certain function or group of functions. Alternatively, the components of the drilling fluid management system 218 may include a combination of computer-executable instructions and hardware.

Furthermore, 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. Thus, the components may be implemented as a stand-alone application, such as a desktop or mobile application. Furthermore, 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. In some embodiments, 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. For example, 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. In some embodiments, 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. For example, 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. For example, 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.

In some examples, 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.

In some examples, 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. For example, the drilling fluid inventory 230 may include a total volume of the fluid used in the drilling system. In some examples, 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. In some examples, 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. As discussed herein, the setpoint drilling fluid properties 220 may be the drilling fluid properties that may help to improve the ROP. In some embodiments, 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.

Based on the comparison between the measured drilling fluid properties 226 and the setpoint drilling fluid properties 220, a recommendation generator 234 of the drilling fluid manager 222 may prepare a recommendation for adjustments to the drilling fluid management system 218. For example, the recommendation generator 234 may prepare a recommendation that may help to maintain the drilling fluid at the setpoint drilling fluid properties 220. In some examples, 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. In some embodiments, 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. In some embodiments, the type and quantity of the additives may change the properties of the drilling fluid to return to the setpoint drilling fluid properties 220.

In accordance with at least one embodiment of the present disclosure, the recommendation prepared by the recommendation generator 234 may help to maintain the drilling fluid within the setpoint drilling fluid properties 220. In some embodiments, the recommendation generator 234 may prepare a recommendation more accurately, precisely, and/or quickly than under conventional mechanisms. For example, 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.

In some embodiments, the recommendation generator 234 may incorporate any information about the drilling system into the recommendation. For example, 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. In some embodiments, based on the surface drilling parameters 228, 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.

In some embodiments, 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.

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. If the setpoint drilling fluid properties 220 are scheduled to change within a threshold period of time, then the recommendation generator 234 may modify the recommendation based on the threshold period of time. For example, the recommendation may include a recommendation not to adjust the drilling parameters if the setpoint drilling fluid properties 220 are scheduled to change. In some embodiments, the recommendation may include a recommendation to adjust the drilling fluid 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.

In some embodiments, the future plans may include a change in the drilling status of the wellbore. For example, 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. In some embodiments, 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.

In some embodiments, 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. In some embodiments, 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.

In some embodiments, the setpoint drilling fluid properties 220 may include a range of parameters. If the measured drilling fluid properties 226 are within the range of parameters, then the recommendation may be to make no change to the drilling fluid. In some embodiments, 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. In some embodiments, the additive manager 236 may implement the recommendation. For example, the additive manager 236 may add the additives and the associated quantities to the drilling fluid. In some embodiments the additive manager 236 may include an automatic additive adding system. For example, 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. In some embodiments, 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.

In some embodiments, after the additive manager 236 implements the recommendation, the drilling fluid management system 218 may continue to monitor the drilling fluid status. For example, after the additive manager 236 implements the recommendation, 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.

In accordance with at least one embodiment of the present disclosure, 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.

In some embodiments, the drilling fluid management system 218 may be implemented at a surface location. For example, the surface location may include a drill rig and associated equipment and structures. In some embodiments, portions of the drilling fluid management system 218 may be performed remotely. For example, the drilling fluid manager 222 may be implemented on a remote computing device, such as a cloud server or a cloud computing device. In some examples, 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. In addition to the foregoing, 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.

As mentioned, 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.

In some embodiments, a drilling fluid manager may receive measurements of drilling fluid properties of a drilling fluid at 340. In some embodiments, the drilling fluid manager may receive as many or more measurements of the drilling fluid properties as the drilling system includes different additives. For example, a measurement collector may monitor measurements of the drilling fluid properties. In some examples, 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.

If the measured parameters are not within the threshold (e.g., if the measured parameters are outside of a threshold of the setpoint fluid properties) then 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. For example, 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.

In some examples, 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. For example, 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.

In some embodiments, after the additives have been added to the drilling fluid, the method 338 may be repeated. For example, 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. After the implementation time has expired, the method 338 may be repeated. This may help to monitor whether the drilling fluid has returned to the setpoint drilling parameters. In this manner, the drilling fluid manager may help to maintain the drilling fluid within the setpoint drilling fluid properties. In some embodiments, 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.

As mentioned, 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.

When the drilling fluid returns to the surface, 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.

In some embodiments, after implementing the recommendation, such as by adding the additives to the returned drilling fluid, the re-mixed returned drilling fluid may be circulated through the wellbore again, and the method 448 may be repeated indefinitely. For example, after implementing the recommendation, the drilling operation may continue to drill and circulate the drilling fluid for a second period of time. When the circulated drilling fluid is returned to the surface, 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.

As mentioned, 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.

As mentioned, 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. For example, a drilling fluid manager may monitor drilling fluid properties of a drilling fluid at a surface location at 672. In some embodiments, monitoring drilling fluid properties may include receiving measurements from one or more sensors. In some embodiments, monitoring drilling fluid properties may include collecting measurements from one or more sensors. In some embodiments, monitoring drilling fluid properties may include collecting the drilling fluid properties periodically. In some embodiments, monitoring drilling fluid properties may include collecting the drilling fluid properties episodically. In some embodiments, monitoring drilling fluid properties may occur at a surface location. In some embodiments, 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. For example, 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.

A computer system 700 may also include one or more input devices 711 and one or more output devices 713. Some examples of input devices 711 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of 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. For the sake of clarity, the various buses are illustrated in FIG. 7 as a bus system 719.

The embodiments of the drilling fluid management system have 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. In other embodiments, 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. For instance, 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.

One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Additionally, it should be understood that 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. For example, 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.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

1. A method for managing a drilling fluid, comprising:

receiving a measurement of measured drilling fluid properties for a drilling fluid;

comparing 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; and

based at least in part on the difference between the measurement and the setpoint drilling fluid properties, preparing a recommendation to return the drilling fluid to the setpoint drilling fluid properties.

2. The method of claim 1, further comprising implementing the recommendation by adding an additive to the drilling fluid.

3. The method of claim 1, wherein the recommendation includes a quantity of an additive and an additive schedule of the additive.

4. The method of claim 3, further comprising adding the additive with the quantity and the additive schedule.

5. The method of claim 1, wherein the measurement includes at least one of density, shear stress, or viscosity.

6. The method of claim 1, wherein the recommendation includes a recommendation to reduce total volume of the drilling fluid.

7. The method of claim 1, wherein recommendation includes a modification to the setpoint drilling fluid properties.

8. The method of claim 1, further comprising receiving a measurement of drilling parameters, and wherein preparing the recommendation includes preparing the recommendation based at least in part on the drilling parameters.

9. The method of claim 8, wherein the measurement of the drilling parameters includes at least one of rate of penetration, rotations per minute, drilling fluid flow rate, or drilling fluid pressure.

10. The method of claim 1, wherein the recommendation includes a volume recommendation.

11. The method of claim 10, wherein the volume recommendation includes removing a volume of the drilling fluid.

12. A drilling system, comprising:

a processor; and

memory, the memory including instructions which, when accessed by the processor, cause the processor to: receive a measurement of measured drilling fluid properties for a drilling fluid; compare 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; and based at least in part on the difference between the measurement and the setpoint drilling fluid properties, prepare a recommendation to return the drilling fluid to the setpoint drilling fluid properties.

13. The drilling system of claim 12, further comprising:

a drilling fluid tank; and

an additive tank in communication with the drilling fluid tank, and wherein the instructions further cause the processor to, based on the recommendation, add an additive from the additive tank to the drilling fluid tank.

14. The drilling system of claim 13, wherein the recommendation includes an additive volume and an additive schedule, and wherein adding the additive to the drilling fluid tank includes adding the additive with the additive volume and the additive schedule.

15. The drilling system of claim 13, wherein the instructions further cause the processor to remove a volume of the drilling fluid from the drilling fluid tank.

16. A method for managing a drilling fluid, comprising:

monitoring drilling fluid properties of a drilling fluid at a surface location;

determining whether the drilling fluid properties are within setpoint drilling fluid properties; and

generating a recommendation to return the drilling fluid to the setpoint drilling fluid properties.

17. The method of claim 16, wherein the recommendation includes a volume of an additive, and further comprising adding the volume of the additive to the drilling fluid at the surface location.

18. The method of claim 17, wherein adding the volume of the additive to the drilling fluid includes automatically adding the volume of additive with an additive control system.

19. The method of claim 16, further comprising:

implementing the recommendation at the drilling fluid; and

circulating the drilling fluid through a drilling system.

20. The method of claim 19, further comprising:

monitoring the drilling fluid properties of the circulated drilling fluid;

determining whether the drilling fluid properties of the circulated drilling fluid are within the setpoint drilling fluid properties; and

generating an updated recommendation to return the circulated drilling fluid to the setpoint drilling fluid properties.