Apparatus, systems, and methods for drilling fluid management

Abstract

A drilling fluid management system may receive a measurement of a measured drilling fluid characteristic of a drilling fluid. The drilling fluid management system may compare a measured value of the measured drilling fluid characteristic to the setpoint drilling fluid characteristic to generate a difference between the measured value and the setpoint drilling fluid characteristic. The drilling fluid management system may prepare a recommendation to return the drilling fluid to the setpoint drilling fluid characteristic based at least in part on a difference between the measured value and the setpoint drilling fluid characteristic.

Description

[0001] Cross - reference to related applications

[0002] This application claims priority and the benefit of U.S. Provisional Patent Application No. 63 / 381,033, filed on October 26, 2022, the entire content of which is incorporated herein by reference. Background Art

[0003] Downhole drilling typically involves degrading a formation by rotating a drill bit against the formation at the bottom of a wellbore. A drilling fluid or drilling mud is typically circulated through the wellbore from a mud pit on the surface to the drill bit. The drilling fluid can cool the drill bit, collect the chips generated by the drill bit, and transport the chips to the surface. The formulation of the drilling fluid is typically designed to have specific properties, such as shear strength, density, viscosity, etc. These properties relate to the drilling effectiveness of the drilling operation. When the drilling fluid collects chips and interacts with the formation, the properties of the drilling fluid may change. Changing the properties of the drilling fluid may result in a reduction in the effectiveness of the drilling operation, which may lead to damage to downhole drilling components.

[0004] Conventionally, when the drilling fluid is circulated back to the surface, a drilling fluid engineer can provide additives to the drilling fluid to maintain its desired properties. The drilling fluid engineer typically directly manages the analysis of the properties of the returned fluid. Then, the drilling fluid engineer uses a combination of trial - and - error methods 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 a reduction in the effectiveness of the drilling operation and an increase in the cost of the drilling fluid. In particular, a drilling engineer may have multiple additives to change the drilling fluid properties. Each additive can change multiple properties, and the combination of additives and additive dosages may have unpredictable consequences on the drilling fluid properties. Summary of the Invention

[0005] In some embodiments, a drilling fluid management system receives measurements of the measured drilling fluid properties of a drilling fluid. The drilling fluid management system compares the measured values of the measured drilling fluid properties with set - point drilling fluid properties to generate a difference between the measured values and the set - point drilling fluid properties. At least in part based on the difference between the measured values and the set - point drilling fluid properties, the drilling fluid management system prepares a recommendation to return the drilling fluid to the set - point drilling fluid properties.

[0006] In some embodiments, a drilling fluid management system monitors the drilling fluid properties of the drilling fluid at a surface location. The system determines whether the drilling fluid properties are within the set - point drilling fluid properties. The system generates a recommendation to return the drilling fluid to the set - point drilling fluid properties.

[0007] The present invention content is provided to introduce a selection of concepts further described in the detailed implementation. The present invention content is not intended to identify the key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter. Additional features and aspects of the embodiments of the present disclosure will be set forth herein, and in part will be apparent from the description, or can be learned by practicing such embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] To describe the manner in which the above and other features of the present disclosure can be obtained, a more specific description will be presented by referring to its specific embodiments shown in the drawings. For better understanding, in the various drawings, the same elements are denoted by the same reference numerals. Although some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings can be drawn to scale. It should be understood that the drawings depict some example embodiments, and the embodiments will be described and explained by using the drawings with additional features and details. In the drawings:

[0009] Figure 1 Shows an example of a drilling system for drilling a formation to form a wellbore according to at least one embodiment of the present disclosure;

[0010] Figure 2 Is a representation of a drilling fluid management system according to at least one embodiment of the present disclosure.

[0011] Figure 3 Is a flowchart of a method for managing drilling fluid according to at least one embodiment of the present disclosure;

[0012] Figure 4 Is a flowchart of a method for managing drilling fluid according to at least one embodiment of the present disclosure;

[0013] Figure 5 Is a flowchart of a method for managing drilling fluid according to at least one embodiment of the present disclosure;

[0014] Figure 6 Is a flowchart of a method for managing drilling fluid according to at least one embodiment of the present disclosure; and

[0015] Figure 7 Shows certain components that can be included in a computer system according to at least one embodiment of the present disclosure. DETAILED DESCRIPTION

[0016] The present disclosure generally relates to apparatuses, systems, and methods for managing drilling fluids of a drilling system. A drilling fluid management system can monitor drilling fluid properties of the drilling fluid. A drilling fluid manager can 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 can prepare a recommendation to return the drilling fluid to the setpoint drilling fluid properties. The recommendation can include mechanisms for returning the drilling fluid to the setpoint drilling fluid properties, including the use of additives, adjustments to surface drilling parameters, volume recommendations for adjusting the total drilling fluid volume, any other adjustments to the drilling fluid properties, and combinations thereof. The drilling fluid management system can implement the recommendation. In this manner, the drilling fluid management system can keep the drilling fluid within the setpoint drilling fluid properties. This can help improve the quality of the drilling system and can help improve the rate of penetration ("ROP").

[0017] Figure 1 An example of a drilling system 100 for drilling a formation 101 to form a wellbore 102 is shown. The drilling system 100 includes a rig 103 for rotating a drilling tool assembly 104 that extends downward into the wellbore 102. The drilling tool assembly 104 can include a drill string 105, a bottom hole assembly ("BHA") 106, and a drill bit 110 attached to the lower end of the drill string 105.

[0018] The drill string 105 can include a number of joints of drill pipe 108 that are connected end-to-end by tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the rig 103 to the BHA 106. In some embodiments, the drill string 105 can also include additional components, such as subs, short joints, etc. The drill pipe 108 provides a hydraulic passage through which the drilling fluid is pumped from the surface. The drilling fluid exits through selected-sized nozzles, jets, or other orifices in the drill bit 110 for the purpose of cooling the drill bit 110 and the cutting structure on the drill bit 110, and for lifting cuttings out of the wellbore 102 during drilling. The drilling fluid can be designed to have specific drilling fluid properties to facilitate cooling the drill bit 110, the cutting structure on the drill bit 110, lifting cuttings out of the wellbore, supporting the walls of the wellbore, etc.

[0019] The drilling fluid can be stored in the mud pit 112 at the surface location 111. The drilling fluid can be pumped out of the mud pit 112 and pumped into the drill string 105 using one or more mud pumps 114. When the drilling fluid flows out of the drill string 105, such as through the drill bit 110 or other locations, the drilling fluid can carry cuttings, debris, or other materials out of the wellbore 102. The cuttings, debris, and other materials can cause changes in the properties of the drilling fluid, such as changes in density, shear stress, viscosity, etc. When the drilling fluid returns to the surface location 111 (such as the mud pit 112), the properties of the drilling can be changed by introducing contaminants into the wellbore 102.

[0020] The measurement station 116 or the sensor station can measure the parameters of the drilling fluid. The drilling fluid can have set-point fluid properties. In some embodiments, when the measured parameters of the drilling fluid have deviated from the set-point fluid properties by more than a threshold amount, the drilling fluid may be less effective in cooling the drill bit 110, the cutting structure on the drill bit 110, lifting cuttings out of the wellbore, supporting the walls of the wellbore, etc. Generally, as discussed herein, when the measured parameters deviate from the set-point fluid properties, the drilling fluid engineer can add one or more additives to the drilling fluid. For example, the drilling fluid engineer can add the additive to the drilling fluid in the mud pit 112 and mix the drilling fluid and the additive.

[0021] The measurement station 116 can measure the parameters of the re-mixed drilling fluid and compare them with the set-point fluid properties. Using the measured parameters, the drilling fluid engineer can continue to add additives until the measured parameters are within the set-point fluid properties. This process is an effective trial-and-error method, adjusted by the experience of the drilling fluid engineer.

[0022] According to one or more embodiments of the present disclosure, the drilling fluid manager can generate recommendations for actions that the drilling operator can take to return the drilling fluid to the set-point fluid properties. For example, the drilling fluid manager can monitor the parameters of the drilling fluid and determine the combination of additives added to the drilling fluid. The drilling fluid manager can provide the recommendation to the additive manager, and the additive manager can add the additive to the drilling fluid. In some embodiments, the drilling fluid manager can provide the recommendation to the drilling operator, and the drilling operator can add the additive to the drilling fluid. This can help improve the accuracy of the drilling fluid returning to the set-point drilling fluid properties. In some embodiments, the recommendation may include additive volume and / or additive schedule. The drilling operator and / or the additive manager can add the additive according to the additive volume and / or additive schedule.

[0023] In some embodiments, the drilling fluid manager may analyze the total volume of fluid in the drilling system 100. For example, the drilling fluid manager may analyze the fluid volume in the mud pit 112. In some embodiments, the recommendation may include a volume recommendation to add and / or remove a volume of drilling fluid to maintain a set point volume of the drilling fluid. The volume recommendation may help maintain an appropriate volume of drilling fluid in the drilling system 100.

[0024] In some embodiments, the drilling fluid manager may receive wellbore information such as wellbore depth, formation information, etc. The drilling fluid manager may determine a recommendation based on the wellbore information. For example, the drilling fluid manager may determine the additive type, volume, schedule, etc. based on the formation of the BHA 106. This may help the drilling fluid manager generate a recommendation that can move the drilling fluid closer to the set point.

[0025] In some embodiments, the recommendation may include one or more adjustments to surface drilling parameters. For example, the recommendation may include adjustments to the rotational rate of the drill string 105 in revolutions per minute ("RPM"), the volumetric flow rate of the drilling fluid, the weight on bit ("WOB"), any other surface drilling parameters, and combinations thereof. In some cases, adjusting the surface drilling parameters may help increase the rate of penetration ("ROP") of the drilling system 100 for existing drilling fluid properties. In some embodiments, in addition to providing additives to adjust the drilling fluid properties, adjustments to the surface drilling parameters may also be performed. In some embodiments, adjustments to the surface drilling parameters may be performed as an alternative to providing additives to adjust the drilling fluid properties.

[0026] In some embodiments, the drilling fluid manager may review future drilling plans to prepare a recommendation. For example, the drilling fluid manager may look at the wellbore trajectory compared to the position of the drill bit 110 for an anticipated intercept with a particular formation, reservoir, or other geological feature. In some examples, the drilling fluid manager may review plans for terminating drilling activities, installing wellbore structures, any other future drilling plans, and combinations thereof. In some embodiments, if a change in wellbore conditions is imminent, the recommendation may be different than if no change were imminent. For example, the recommendation may not include additives, may include additives with a different volume or addition schedule, or may include additives different from those recommended if there were no predicted change in wellbore conditions. This may help reduce the addition of additives that may not have time to take effect. In some embodiments, a recommendation without additives may be more cost-effective than adding additives, as drilling with a drilling fluid having drilling fluid properties different from the set point may be less expensive than adding additives.

[0027] The BHA 106 may include a drill bit 110 or other components. An exemplary BHA 106 may include additional or other components (e.g., coupled between the drill string 105 and the drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, reamers, profile mills, hydraulic disconnects, shock subs, vibration or damping tools, other components, or combinations of the foregoing. The BHA 106 may also include a rotary steerable system (RSS). The RSS may include a directional drilling tool that changes the direction of the drill bit 110 and, thereby, changes the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame (e.g., gravity, magnetic north, and / or true north). Using measurements obtained with the geostationary position, the RSS may position the drill bit 110, change the route of the drill bit 110, and guide the directional drilling tool along a projected trajectory.

[0028] Generally, the drilling system 100 may include other drilling components and accessories, such as specialized valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered part of the drill tool assembly 104, the drill string 105, or the BHA 106, depending on their location within the drilling system 100.

[0029] The drill bit 110 in the BHA 106 may be any type of drill bit suitable for degrading downhole materials. For example, the drill bit 110 may be a drill bit suitable for drilling the formation 101. Exemplary types of drill bits for drilling formations are fixed cutter or drag bits. In other embodiments, the drill bit 110 may be a mill for removing metal, composite materials, elastomers, other materials, or combinations thereof downhole. For example, the drill bit 110 may be used with a whipstock to mill into a casing 107 that lines the wellbore 102. The drill bit 110 may also be a junk mill for milling away tools, plugs, cement, other materials, or combinations thereof within the wellbore 102. Debris or other cuttings formed by using the mill may be lifted to the surface or may be allowed to fall downhole.

[0030] Figure 2is a representation of a drilling fluid management system 218 in accordance with at least one embodiment of the present disclosure. Each component of the drilling fluid management system 218 can include software, hardware, or both. For example, a component can include one or more instructions stored on a computer-readable storage medium and executable by a processor of one or more computing devices, such as a client device or a server device. When executed by one or more processors, the computer-executable instructions of the drilling fluid management system 218 can cause the computing device to perform the methods described herein. Alternatively, a component can include hardware, such as a dedicated processing device for performing a particular function or group of functions. Alternatively, the components of the drilling fluid management system 218 can include a combination of computer-executable instructions and hardware.

[0031] In addition, the components of the drilling fluid management system 218 can be implemented, for example, as one or more operating systems, one or more stand-alone applications, one or more modules of an application, one or more plug-ins, one or more library functions, or functions and / or cloud computing models that can be invoked by other applications. Thus, a component can be implemented as a stand-alone application, such as a desktop or mobile application. Additionally, a component can be implemented as one or more web-based applications hosted on a remote server. The components can also be implemented in a suite of mobile device applications or "apps".

[0032] The drilling fluid management system 218 can be used in association with a drilling system, such as Figure 1 the drilling system 100. In some embodiments, the drilling fluid management system 218 can include one or more setpoint drilling fluid properties 220. The setpoint drilling fluid properties 220 can be included as part of the well design. For example, the setpoint drilling fluid properties 220 can be based on a target wellbore trajectory through a target or expected formation. The setpoint drilling fluid properties 220 can be determined during wellbore planning or scheduling. In some embodiments, the setpoint drilling fluid properties 220 can be designed to maintain drilling conditions that improve ROP.

[0033] The drilling fluid management system 218 can include a drilling fluid manager 222. The drilling fluid manager 222 can receive the setpoint drilling fluid properties 220. A measurement collector 224 can collect and / or receive various measurements related to the drilling system. For example, the measurement collector 224 can collect one or more measured drilling fluid properties 226. The measured drilling fluid properties 226 can include any measurable drilling fluid parameter. For example, the measured drilling fluid properties 226 can include one or more of fluid density, fluid viscosity, fluid shear strength, clay concentration, oil-water ratio, lime concentration, pH, methylene blue (MBT) absorption, salinity, drilling solids content, product concentration, any other drilling fluid parameter, and combinations thereof.

[0034] 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 that is measured and / or measurable at the surface, including one or more of weight on bit (WOB), bit torque (“TOB”), drilling fluid flow rate, drilling fluid pressure, revolutions per minute (RPM), any other surface drilling parameter, and combinations thereof.

[0035] 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 aspect of the drilling fluid inventory. For example, the drilling fluid inventory 230 may include the total volume of fluid used in the drilling system. In some examples, the drilling fluid inventory 230 may include a list of drilling fluid additives located at the rig site and their associated amounts (e.g., weight and / or volume), 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 types and amounts of additives previously added to the drilling fluid.

[0036] The drilling fluid manager 222 may receive measurements from the measurement collector 224. The 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 drilling fluid properties that may contribute to improving the rate of penetration (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 the measured drilling fluid properties 226 deviate from the setpoint drilling fluid properties 220.

[0037] Based on the comparison between the measured drilling fluid properties 226 and the setpoint drilling fluid properties 220, the recommendation generator 234 of the drilling fluid manager 222 may prepare a recommendation for adjusting the drilling fluid management system 218. For example, the recommendation generator 234 may prepare a recommendation that may help 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 be added to the drilling fluid. The additives may change the properties of the drilling fluid. In some embodiments, the recommendation may include the type and amount (e.g., volume and / or weight) of the additive to change the properties of the drilling fluid. In some embodiments, the type and amount of the additive may change the properties of the drilling fluid to return to the setpoint drilling fluid properties 220.

[0038] According to at least one embodiment of the present disclosure, the recommendations prepared by the recommendation generator 234 can help keep the drilling fluid within the setpoint drilling fluid properties 220. In some embodiments, the recommendation generator 234 can prepare recommendations more accurately, precisely, and / or quickly than under conventional mechanisms. For example, the recommendation generator 234 can prepare recommendations that incorporate data from measured drilling fluid properties 226, compensated wellbore, chemical properties of the drilling fluid, and other factors. This can help improve the quality of the recommendations and / or the speed at which the drilling fluid returns to the setpoint drilling fluid properties 220.

[0039] In some embodiments, the recommendation generator 234 can incorporate any information about the drilling system into the recommendations. For example, the recommendation generator 234 can incorporate surface drilling parameters 228. The surface drilling parameters 228 can affect how additives and / or drilling fluid properties affect the drilling of the wellbore. In some embodiments, based on the surface drilling parameters 228, the recommendation generator 234 can generate recommendations based on the surface drilling parameters 228. This can help the additives move the drilling fluid to the setpoint drilling fluid properties 220 faster and / or more accurately.

[0040] In some embodiments, the recommendation generator 234 can incorporate the drilling fluid inventory 230 into the recommendations. For example, the recommendation generator 234 can check the available types and quantities of additives. Based on the drilling fluid inventory 230, the recommendation generator 234 can use the available additives and other materials to prepare recommendations. This can help the drilling fluid move back to the setpoint drilling fluid properties 220 without delay based on waiting for additives or other materials to be delivered or arrive at the drilling site.

[0041] In some embodiments, the recommendation generator 234 can receive future plans for the wellbore. For example, the recommendation generator 234 can receive information about changes in the wellbore state. Changes in the wellbore state can include changes in the setpoint drilling fluid properties 220. If the setpoint drilling fluid properties 220 are scheduled to change within a threshold time period, the recommendation generator 234 can modify the recommendations based on the threshold time period. For example, if the setpoint drilling fluid properties 220 are scheduled to change, the recommendations can include recommendations not to adjust the drilling parameters. In some embodiments, the recommendations can include recommendations to adjust the drilling fluid to reach the new setpoint drilling fluid properties 220. For example, if the duration of changing the drilling fluid properties will intersect or overlap with the change in the setpoint drilling fluid properties 220, the recommendations can include additives that can change the drilling fluid properties to the new setpoint drilling fluid properties 220.

[0042] In some embodiments, the future plan may include a change in the drilling status of the wellbore. For example, the future plan may include the end of the drilling activity. If the end of the drilling activity is within a threshold time period, the recommendation may be not to change the drilling fluid properties. In some embodiments, the recommendation may include an expected cost. For example, each additive has an associated cost. And not changing the drilling fluid parameters based on the future plan has an associated cost. The recommendation generator 234 may prepare a recommendation based on the associated cost. For example, the recommendation generator 234 may prepare a recommendation based on the lowest cost option.

[0043] In some embodiments, the drilling fluid manager 222 may check the total volume of the drilling fluid within the drilling system, including the total volume of the drilling fluid in tanks, wellbores, etc. The total volume of the fluid may change based on the fluid entering the wellbore, the advancement of the wellbore depth, fluid additives, etc. In some embodiments, the recommendation generator 234 may prepare a volume recommendation to adjust the total volume of the drilling fluid. For example, the volume recommendation may recommend reducing the total volume of the drilling fluid or increasing the total volume of the drilling fluid. This may help manage the total amount of the drilling fluid in the drilling system.

[0044] In some embodiments, the setpoint drilling fluid properties 220 may include a series of parameters. If the measured drilling fluid properties 226 are within the parameter range, the recommendation may be not to change the drilling fluid. In some embodiments, the comparison manager 232 may monitor the measurements received from the measurement results collector 224. When the comparison manager 232 determines that the measured drilling fluid properties have moved outside the parameter range, the recommendation generator 234 may prepare a recommendation to adjust the drilling fluid properties.

[0045] 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 an additive and the associated amount to the drilling fluid. In some embodiments, the additive manager 236 may include an automatic additive addition system. For example, the additive tank may be connected to the drilling fluid system, such as a drilling fluid tank (e.g., a mud pit), through a series of pipes, pumps, hoppers, any other systems, and combinations thereof. In some embodiments, the additive manager 236 may be connected to a valve or other actuating mechanism, and the additive manager 236 may cause the additive to flow from the additive tank to the drilling fluid system by actuating the actuating mechanism. In some embodiments, the additive manager 236 may actuate the actuating mechanism at a timed interval to add the recommended amount of the additive according to the recommendation on the recommended schedule.

[0046] In some embodiments, after the additive manager 236 implements a recommendation, the drilling fluid management system 218 can continue to monitor the drilling fluid state. For example, after the additive manager 236 implements a recommendation, the measurement collector 224 can collect and / or receive updated measurements, including one or more of the measured drilling fluid properties 226, surface drilling parameters 228, or the drilling fluid inventory 230. The drilling fluid manager 222 can receive the updated measurements, and the comparison manager 232 can monitor the comparison between the updated measurements and the setpoint drilling fluid properties 220. In some embodiments, this process can be performed in real time. This can allow the drilling fluid management system 218 to maintain the drilling fluid at the setpoint drilling fluid properties 220 or within a parameter range.

[0047] According to at least one embodiment of the present disclosure, the recommendation generator 234 can prepare a recommendation to change the setpoint drilling fluid properties 220. For example, based on the measurements received from the measurement collector 224, the recommendation generator 234 can determine that the setpoint drilling fluid properties 220 can be changed to improve the ROP. In this way, the recommendation generator 234 can help maintain the drilling fluid with drilling fluid properties that improve the ROP.

[0048] In some embodiments, the drilling fluid management system 218 can be implemented at a surface location. For example, the surface location can include a rig and associated equipment and structures. In some embodiments, portions of the drilling fluid management system 218 can be executed remotely. For example, the drilling fluid manager 222 can 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 can be implemented on a local network (such as a network local to a single rig site).

[0049] Figures 3 to 6 corresponding text and examples provide Figure 2 various different methods, systems, devices, and non-transitory computer-readable media of the drilling fluid management system 218. In addition to the foregoing, one or more embodiments can also be described according to a flowchart including actions for achieving a specific result, as shown. Each of the described methods can be performed with more or fewer actions. In addition, the actions can be performed in a different order. Additionally, the actions described herein can be repeated or performed in parallel with each other or in parallel with different examples of the same or similar actions.

[0050] As mentioned, Figure 3 shows a flowchart of a series of actions of a method 338 for managing drilling fluid components according to one or more embodiments. Although Figure 3 shows an action according to one embodiment, alternative embodiments can omit, add, reorder, and / or modify Figure 3Any action shown in Figure 3 The actions of Figure 3 can be performed as part of a method. Alternatively, a non-transitory computer-readable medium can include instructions that, when executed by one or more processors, cause a computing device to perform Figure 3 the actions of

[0051] In some embodiments, a drilling fluid manager can receive measurements of drilling fluid properties of a drilling fluid at 340. In some embodiments, the drilling fluid manager can receive as many or more measurements of drilling fluid properties as the drilling system includes different additives. For example, a measurement collector can monitor measurements of drilling fluid properties. In some examples, the measurement collector can monitor measurements when implementing a recommendation (e.g., when an additive manager implements a recommendation, when the additive manager adds an additive to the drilling fluid).

[0052] The drilling fluid manager can compare the measurements with set-point fluid properties. At 342, the drilling fluid manager can determine whether the measured parameter is within a predetermined threshold of the set-point fluid properties. If the measured parameter is within the threshold, the drilling fluid manager can continue to monitor the measured drilling fluid properties until the parameter is outside the threshold.

[0053] If the measured parameter is not within the threshold (e.g., if the measured parameter is outside the threshold of the set-point fluid properties), the drilling fluid manager can determine the magnitude of the difference between the measured drilling fluid property and the predetermined set-point at 344. Based on the difference and an additive model, the drilling fluid manager can prepare a recommendation at 346 to return the drilling fluid property to the set-point drilling fluid property. For example, the drilling fluid manager can include in the recommendation the dosage of one or more additives in the drilling system. In some embodiments, the additive manager can add the amount of additive to the drilling fluid. For example, the drilling fluid manager can instruct one or more valves or other control systems to automatically add the additives to the drilling fluid and mix them together. In some examples, the drilling fluid manager can provide instructions to a drilling fluid engineer or other drilling operator to add the amount of additive to the drilling fluid.

[0054] The additive manager may include an additive control system that can physically add additives to the drilling fluid. For example, fluid additives (including liquids, gels, slurries, and other fluids) may include one or more pipes, tanks, or other fluid conduits connected to a drilling fluid reservoir and / or a drilling fluid mixing chamber. The fluid storage system may be connected to the drilling fluid mixing chamber via valves and a volume control system (e.g., a flow meter, a timer, or other volume control systems). Based on the determined dosage and schedule of the additives, the additive manager may cause the additive control system to add the amount of additives in the identified schedule.

[0055] In some examples, the fluid additive may include one or more solid materials, including powders, granules, bricks, or solid fluid additives. The solid fluid additives may be stored in a storage system (e.g., 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 supply the solid additive into a container on the scale, and the scale may weigh the additive to the dosage. Then, the additive control system may empty the container into the drilling fluid, such as in a drilling fluid mixing chamber. To comply with the additive schedule and / or based on the container capacity, the additive control system may measure and add multiple batches of additives. In this way, the additive control system may help automate the drilling fluid management process.

[0056] In some embodiments, after adding the additives to the drilling fluid, 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 expires, method 338 may be repeated. This may help monitor whether the drilling fluid has returned to the set-point drilling parameters. In this way, the drilling fluid manager may help keep the drilling fluid within the set-point drilling fluid properties. In some embodiments, method 338 may be implemented in Figure 2 the drilling fluid management system 218. This may help improve the responsiveness of the recommendation and its associated implementation.

[0057] As mentioned, Figure 4 A flowchart showing a series of actions of a method 448 for managing drilling fluid components according to one or more embodiments is shown. Although Figure 4 shows an action according to one embodiment, alternative embodiments may omit, add, reorder, and / or modify Figure 4 any of the actions shown in Figure 4 The actions of may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may include instructions that, when executed by one or more processors, cause a computing device to performFigure 4 actions. In some embodiments, the system can perform Figure 4 actions.

[0058] Method 448 can include drilling for a period of time at 450. In other words, method 448 can occur while the drilling activity is being performed. While drilling, the drilling system can circulate drilling fluid through the wellbore until a portion of the drilling fluid returns to the surface location at 452. For example, the drilling fluid can be circulated into the drill string while drilling, through the drill string to the bottom of the wellbore, and through the annulus between the drill string and the formation, and out of the wellbore to deposit in the mud pit.

[0059] When the drilling fluid returns to the surface, the drilling fluid properties of the drilling fluid can be measured at 454. As discussed herein, the properties of the drilling fluid can change based on the addition of cuttings and other materials encountered during drilling. The drilling fluid manager can compare and determine the difference between the measured drilling fluid properties and the predetermined set point fluid properties at 456. Based on the difference, the drilling fluid manager can prepare a recommendation at 458. Then, method 448 can include implementing the recommendation at 460. For example, the additive manager can add the dosage of the additive to the returned drilling fluid. This may cause the parameters of the returned drilling fluid to return within the threshold of the set point fluid properties.

[0060] In some embodiments, after implementing the recommendation, such as by adding an additive to the returned drilling fluid, the remixed returned drilling fluid can be circulated through the wellbore again, and method 448 can be repeated indefinitely. For example, after implementing the recommendation, the drilling operation can continue drilling and circulate the drilling fluid for a second period of time. When the circulated drilling fluid returns to the surface, the drilling fluid properties of the circulated drilling fluid can be measured. Any differences between the measured fluid parameters are used to determine an updated recommendation. The updated recommendation can be implemented, along with the drilling fluid circulation, where the recycled fluid is analyzed and a new updated recommendation is presented. In this manner, method 448 can help automatically maintain the drilling fluid properties of the drilling fluid.

[0061] As mentioned, Figure 5 illustrates a flowchart of a series of actions of a method 562 for managing drilling fluid composition according to one or more embodiments. Although Figure 5 illustrates actions according to one embodiment, alternative embodiments can omit, add, reorder, and / or modify Figure 5 any of the actions shown in Figure 5 The actions can be performed as part of a method. Alternatively, a non-transitory computer-readable medium can include instructions that, when executed by one or more processors, cause a computing device to perform Figure 5actions. In some embodiments, the system may perform Figure 5 actions.

[0062] The drilling fluid manager may receive a measurement of the drilling fluid properties of the drilling fluid at 564. The drilling fluid manager may compare the measurement of the drilling fluid properties with the setpoint drilling fluid properties at 566 to generate a difference between the measurement and the setpoint drilling parameters. At least partially based on the difference between the measurement and the setpoint drilling fluid properties, the drilling fluid manager may prepare a recommendation at 568 to return the drilling fluid to the setpoint drilling fluid properties.

[0063] As mentioned, Figure 6 FIG. shows a flow chart of a series of actions of a method 670 for managing drilling fluid composition according to one or more embodiments. Although Figure 6 shows actions according to one embodiment, alternative embodiments may omit, add, reorder, and / or modify Figure 6 any of the actions shown therein. Figure 6 The actions may be performed as part of a method. Alternatively, a non-transitory computer-readable medium may include instructions that, when executed by one or more processors, cause a computing device to perform Figure 6 the actions. In some embodiments, the system may perform Figure 6 the actions.

[0064] Method 670 may include monitoring drilling fluid properties. For example, the drilling fluid manager may monitor the drilling fluid properties of the drilling fluid at the surface location at 672. In some embodiments, monitoring the drilling fluid properties may include receiving measurements from one or more sensors. In some embodiments, monitoring the drilling fluid properties may include collecting measurements from one or more sensors. In some embodiments, monitoring the drilling fluid properties may include periodically collecting the drilling fluid properties. In some embodiments, monitoring the drilling fluid properties may include occasionally collecting the drilling fluid properties. In some embodiments, monitoring the drilling fluid properties may occur at the surface location. In some embodiments, monitoring the drilling fluid properties may occur downhole. The drilling fluid manager may determine at 674 whether the drilling fluid properties are within the setpoint drilling fluid properties. Then, the drilling fluid manager may generate a recommendation at 676 to return the drilling fluid to the setpoint drilling fluid properties.

[0065] Figure 7 FIG. shows 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.

[0066] The computer system 700 includes a processor 701. The processor 701 can be a general-purpose single-chip 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 can be referred to as a Central Processing Unit (CPU). Although only a single processor 701 is shown in the computer system 700 of Figure 7 , in an alternative configuration, a combination of processors (e.g., ARM and DSP) can be used.

[0067] The computer system 700 further includes a memory 703 that is in electronic communication with the processor 701. The memory 703 can be any electronic component capable of storing electronic information. For example, the memory 703 can be embodied as Random Access Memory (RAM), Read-Only Memory (ROM), magnetic disk storage media, optical storage media, flash devices in RAM, on-board memory including a processor, Erasable Programmable Read-Only Memory (EPROM), Electrically Erasable Programmable Read-Only Memory (EEPROM) memory, registers, etc., including combinations thereof.

[0068] Instructions 705 and data 707 can be stored in the memory 703. The instructions 705 can be executed by the processor 701 to implement some or all of the functions disclosed herein. Executing the instructions 705 can involve using the data 707 stored in the memory 703. Any of the various examples of modules and components described herein can be implemented, in part or in whole, as instructions 705 stored in the memory 703 and executed by the processor 701. Any example of the data described herein can be among the data 707 stored in the memory 703 and used during execution of the instructions 705 by the processor 701.

[0069] The computer system 700 can further include one or more communication interfaces 709 for communicating with other electronic devices. The communication interfaces 709 can be based on wired communication technologies, wireless communication technologies, or both. Some examples of the communication interfaces 709 include Universal Serial Bus (USB), Ethernet adapters, wireless adapters operating according to the Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, wireless communication adapters, and Infrared (IR) communication ports.

[0070] The 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 keyboards, mice, microphones, remote control devices, buttons, joysticks, trackballs, touchpads, and light pens. Some examples of output devices 713 include speakers and printers. A particular type of output device commonly included in the computer system 700 is the display device 715. The display device 715 used in conjunction with the embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal displays (LCDs), light emitting diodes (LEDs), gas plasmas, electroluminescence, etc. A display controller 717 may also be provided for converting the data 707 stored in the memory 703 into text, graphics, and / or moving images (as appropriate) to be displayed on the display device 715.

[0071] 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 clarity, the various buses are shown as a bus system 719 in Figure 7 the figure.

[0072] Embodiments of the drilling fluid management system have been described primarily with reference to wellbore drilling operations; the drilling fluid management systems described herein may be used in applications other than wellbore drilling. In other embodiments, the drilling fluid management system according to the present disclosure may be used outside of wellbores or other downhole environments for exploring or producing natural resources. For example, the drilling fluid management system of the present disclosure may be used in a borehole for placing utility pipelines. Thus, the terms "wellbore," "borehole," etc. should not be construed as limiting the tools, systems, components, or methods of the present disclosure to any particular industry, field, or environment.

[0073] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed technology. Additionally, in order to provide a concise description of these embodiments, all features of the actual embodiments may not 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 implementation-specific decisions will be made to achieve the developer's specific goals, such as meeting system-related and business-related constraints, which may vary from one embodiment to another. Furthermore, it should be understood that such development efforts may be complex and time-consuming, but would still be a routine task of design, fabrication, and manufacture for those of ordinary skill in the art who would benefit from the present disclosure.

[0074] In addition, it should be understood that references to "one embodiment" or "an embodiment" of the present disclosure are not intended to be construed as precluding the existence of additional embodiments that also incorporate the recited features. For example, any element described with respect to an embodiment herein can be combined with any element of any other embodiment described herein. The numerical values, percentages, ratios, or other values described herein are intended to include that value, as well as other values that are "about" or "approximately" the recited value, as would be understood by one of ordinary skill in the art as encompassed by the embodiments of the present disclosure. Accordingly, the values should be construed broadly enough to cover at least values that are sufficiently close to the recited value to perform the desired function or achieve the desired result. The values include at least the variations expected in a suitable manufacturing or production process, and can include values within 5%, 1%, 0.1%, or 0.01% of the recited value.

[0075] In view of the present disclosure, one of ordinary skill in the art should recognize that equivalent structures do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations can be made to the embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent structures that include functional "means-plus-function" clauses are intended to cover structures described herein as performing the recited function, including structural equivalents that operate in the same manner and equivalent structures that provide the same function. Except for those claims in which the words "means for" appear in conjunction with the associated function, the applicant's express intent is not to invoke means-plus-function or other functional recitations for any claim. Each addition, deletion, and modification to an embodiment that falls within the meaning and scope of the claims will be covered by the claims.

[0076] As used herein, the terms "about," "approximately," and "substantially" denote an amount close to the recited amount that is within standard manufacturing or process tolerances, or that still performs the desired function or achieves the desired result. For example, the terms "about," "approximately," and "substantially" can refer to amounts within less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the recited amount. Additionally, it should be understood that any direction or reference frame in the foregoing description is merely a relative direction or movement. For example, any reference to "up" and "down" or "above" or "below" is merely a description of the relative position or movement of the relevant elements.

[0077] Without departing from the spirit or characteristics of the present disclosure, the present disclosure can be implemented in other specific forms. The described embodiments are to be considered illustrative and not restrictive. Accordingly, the scope of the present disclosure is indicated by the appended claims rather than the foregoing description. Variations that fall within the meaning and scope of the equivalents of the claims will be included within the scope of the claims.

Claims

1. A method for managing drilling fluid, comprising: Receiving measured values of measured drilling fluid properties of the drilling fluid; Comparing the measured values of the measured drilling fluid properties with set-point drilling fluid properties to generate a difference between the measured values and the set-point drilling fluid properties; And Preparing a recommendation to return the drilling fluid to the set-point drilling fluid properties based at least in part on the difference between the measured values and the set-point drilling fluid properties.

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

3. The method according to claim 1 or claim 2, wherein the recommendation includes an amount of the additive and an additive schedule for the additive.

4. The method according to claim 3, further comprising adding the additive in the amount and according to the additive schedule.

5. The method according to any one of claims 1-4, wherein the measurement includes at least one of density, shear stress, or viscosity.

6. The method according to any one of claims 1 to 5, wherein the recommendation includes a recommendation to reduce the total volume of the drilling fluid.

7. The method according to any one of claims 1 to 6, wherein the recommendation includes a modification to the set-point drilling fluid properties.

8. The method according to any one of claims 1 to 7, further comprising receiving measured values of drilling parameters, and wherein preparing the recommendation includes preparing the recommendation based at least in part on the drilling parameters.

9. The method according to claim 8, wherein the measured values of the drilling parameters include at least one of a drilling rate, revolutions per minute, drilling fluid flow rate, or drilling fluid pressure.

10. The method according to any one of claims 1 to 9, wherein the recommendation includes a volume recommendation.

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

12. A drilling system, comprising: A processor; And A memory including instructions that, when accessed by the processor, cause the processor to: Receive measured values of measured drilling fluid properties of the drilling fluid; Compare the measured values of the measured drilling fluid properties with set-point drilling fluid properties to generate a difference between the measured values and the set-point drilling fluid properties; And Prepare a recommendation to return the drilling fluid to the set-point drilling fluid properties based at least in part on the difference between the measured values and the set-point drilling fluid properties.

13. The drilling system according to 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 add an additive from the additive tank to the drilling fluid tank based on the recommendation.

14. The drilling system according to 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 in the additive volume and according to the additive schedule.

15. The drilling system according to claim 13 or claim 14, wherein the instructions further cause the processor to remove a certain volume of drilling fluid from the drilling fluid tank.

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