RIG TASK MANAGEMENT

FIELD OF THE DISCLOSURE

The present invention relates, in general, to the field of drilling and processing of wells. More particularly, present embodiments relate to a system and method for analyzing and scoring adherence of rig equipment and personnel to perform activities according to a well plan or rig plan.

BACKGROUND

During well construction operations, activities on a rig can be organized according to a well plan. The well plan can be converted to a rig plan (i.e., rig specific well construction plan) for implementation on a specific rig. Deviations from the well plan or rig plan can cause rig delays, increase well site operation costs, and cause other impacts to operations. Poorly performed well plan activities or rig plan tasks on the rig can cause delays or even unplanned activities or tasks if the activity or task is in a high priority path. Delays in identifying the poor performance can exacerbate these impacts. Therefore, improvements in rig activity monitoring and reporting are continually needed.

SUMMARY

A system of one or more computers can be configured to perform particular operations or actions by virtue of having software, firmware, hardware, or a combination of them installed on the system that in operation causes or cause the system to perform the actions. One or more computer programs can be configured to perform particular operations or actions by virtue of including instructions that, when executed by the data processing apparatus, cause the apparatus to perform the actions. One general method includes performing subterranean operations which may include executing a rig task that involves a fluid contained in a digital rig plan, obtaining sensor data from one or more sensors configured to monitor at least one parameter of the fluid associated with the rig task contained in the digital rig plan, and continuing or stopping the rig task based on the sensor data.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of present embodiments will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1A is a representative simplified front view of a rig being utilized for a subterranean operation, in accordance with certain embodiments.

FIG. 1B is a representative simplified view of a user using possible wearable devices for user input or identification, in accordance with certain embodiments.

FIG. 2 is a representative partial cross-sectional view of a rig being utilized for a subterranean operation, in accordance with certain embodiments.

FIG. 3 is a representative flow diagram of a method of performing a subterranean operation, in accordance with certain embodiments.

FIG. 4A is a representative list of well activities for an example digital well plan, in accordance with certain embodiments.

FIG. 4B is a representative functional diagram that illustrates the conversion of well plan activities to rig plan tasks, in accordance with certain embodiments.

FIG. 5 is a representative functional diagram that illustrates possible databases used by a rig controller to convert a digital well plan to a digital rig plan, in accordance with certain embodiments.

DETAILED DESCRIPTION

The following description in combination with the figures is provided to assist in understanding the teachings disclosed herein. The following discussion will focus on specific implementations and embodiments of the teachings. This focus is provided to assist in describing the teachings and should not be interpreted as a limitation on the scope or applicability of the teachings.

As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having,” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, method, article, or apparatus that comprises a list of features is not necessarily limited only to those features but may include other features not expressly listed or inherent to such process, method, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive-or and not to an exclusive-or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

The use of “a” or “an” is employed to describe elements and components described herein. This is done merely for convenience and to give a general sense of the scope of the invention. This description should be read to include one or at least one and the singular also includes the plural, or vice versa, unless it is clear that it is meant otherwise.

The use of the word “about”, “approximately”, or “substantially” is intended to mean that a value of a parameter is close to a stated value or position. However, minor differences may prevent the values or positions from being exactly as stated. Thus, differences of up to four percent (4%) for the value are reasonable differences from the ideal goal of exactly as described. A significant difference can be when the difference is greater than four percent (4%).

As used herein, “tubular” refers to an elongated cylindrical tube and can include any of the tubulars manipulated around a rig, such as tubular segments, tubular stands, tubulars, and tubular string, but not limited to the tubulars shown in FIG. 1A. Therefore, in this disclosure, “tubular” is synonymous with “tubular segment,” “tubular stand,” and “tubular string,” as well as “pipe,” “pipe segment,” “pipe stand,” “pipe string,” “casing,” “casing segment,” or “casing string.”

FIG. 1A is a representative simplified front view of a rig 10 at a rig site 11 being utilized for a subterranean operation (e.g., tripping in or out a tubular string to or from a wellbore), in accordance with certain embodiments. The rig site 11 can include the rig 10 with its rig equipment, along with equipment and work areas that support the rig 10 but are not necessarily on the rig 10. The rig 10 can include a platform 12 with a rig floor 16 and a derrick 14 extending up from the rig floor 16. The derrick 14 can provide support for hoisting the top drive 18 as needed to manipulate tubulars. A catwalk 20 and V-door ramp 22 can be used to transfer horizontally stored tubular segments 50 to the rig floor 16. A tubular segment 52 can be one of the horizontally stored tubular segments 50 that is being transferred to the rig floor 16 via the catwalk 20. A pipe handler 30 with articulating arms 32, 34 can be used to grab the tubular segment 52 from the catwalk 20 and transfer the tubular segment 52 to the top drive 18, the vertical storage area 36, the wellbore 15, etc. However, it is not required that a pipe handler 30 be used on the rig 10. The top drive 18 can transfer tubulars directly to and directly from the catwalk 20 (e.g., using an elevator coupled to the top drive).

The tubular string 58 can extend into the wellbore 15, with the wellbore 15 extending through the surface 6, and optionally a rotating control device (RCD) or wellhead 66, and into the subterranean formation 8. When tripping the tubular string 58 into the wellbore 15, tubulars 54 are sequentially added to the tubular string 58 to extend the length of the tubular string 58 into the earthen formation 8. FIG. 1A shows a land-based rig. However, it should be understood that the principles of this disclosure are equally applicable to off-shore rigs where “off-shore” refers to a rig with water between the rig floor and the earth surface 6.

When tripping the tubular string 58 out of the wellbore 15, tubulars 54 are sequentially removed from the tubular string 58 to reduce the length of the tubular string 58 in the wellbore 15. The pipe handler 30 can be used to remove the tubulars 54 from an iron roughneck 38 or a top drive 18 at a well center 24 and transfer the tubulars 54 to the catwalk 20, the vertical storage area 36, etc. The iron roughneck 38 can break a threaded connection between a tubular 54 being removed and the tubular string 58. A spinner assembly 40 (or pipe handler 30) can engage a body of the tubular 54 to spin a pin end 57 of the tubular 54 out of a threaded box end 55 of the tubular string 58, thereby unthreading the tubular 54 from the tubular string 58.

When tripping the tubular string 58 into the wellbore 15, tubulars 54 are sequentially added to the tubular string 58 to increase the length of the tubular string 58 in the wellbore 15. The pipe handler 30 can be used to deliver the tubulars 54 to a well center on the rig floor 16 in a vertical orientation and hand the tubulars 54 off to an iron roughneck 38 or a top drive 18. The iron roughneck 38 can make a threaded connection between the tubular 54 being added and the tubular string 58. A spinner assembly 40 or pipe handler 30 can engage a body of the tubular 54 to spin a pin end 57 of the tubular 54 into a threaded box end 55 of the tubular string 58, thereby threading the tubular 54 into the tubular string 58. The wrench assembly 42 can provide a desired torque to the threaded connection, thereby completing the connection.

While tripping a tubular string into or out of the wellbore 15 can be a significant part of the operations performed by the rig, many other rig tasks are also needed to perform a well construction according to a digital well plan. For example, pumping mud at desired rates, maintaining downhole pressures (as in managed pressure drilling), maintaining, and controlling rig power systems, coordinating, and managing personnel on the rig during operations, performing pressure tests on sections of the wellbore 15, cementing a casing string in the wellbore, performing well logging operations, as well as many other rig tasks.

A rig controller 250 can be used to control the rig 10 operations including controlling various rig equipment, such as the pipe handler 30, the top drive 18, the iron roughneck 38, the vertical storage area equipment, imaging systems, various other robots on the rig 10 (e.g., a drill floor robot), or rig power systems 26. The rig controller 250 can control the rig equipment autonomously (e.g., without periodic operator interaction), semi-autonomously (e.g., with limited operator interaction such as initiating a subterranean operation, adjusting parameters during the operation, etc.), or manually (e.g., with the operator interactively controlling the rig equipment via remote control interfaces to perform the subterranean operation). A score can be determined (e.g., by the rig controller 250) for personnel or rig equipment used in performing the subterranean operation to indicate an adherence of the personnel or rig equipment to perform the subterranean operation according to the well plan or rig plan. The scores for individuals can indicate proficiency of the individual to perform the needed tasks for the subterranean operation, or if the individual is performing the needed tasks on time and in the right location, or can indicate a need for additional skills training for the individual. The scores for the rig equipment can indicate that the equipment is operating correctly or that the equipment may need maintenance or repair.

The rig controller 250 can include one or more processors with one or more of the processors distributed about the rig 10, such as in an operator’s control hut 13, in the pipe handler 30, in the iron roughneck 38, in the vertical storage area 36, in the imaging systems, in various other robots, in the top drive 18, at various locations on the rig floor 16 or the derrick 14 or the platform 12, at a remote location off of the rig 10, at downhole locations, etc. It should be understood that any of these processors can perform control or calculations locally or can communicate to a remotely located processor for performing the control or calculations. Each of the processors can be communicatively coupled to a non-transitory memory, which can include instructions for the respective processor to read and execute to implement the desired control functions or other methods described in this disclosure. These processors can be coupled via a wired or wireless network. All data received and sent by the rig controller 250 is in a computer-readable format and can be stored in and retrieved from the non-transitory memory.

The rig controller 250 can collect data from various data sources around the rig (e.g., sensors, user input, local rig reports, etc.) and from remote data sources (e.g., suppliers, manufacturers, transporters, company men, remote rig reports, etc.) to monitor and facilitate the execution of a digital well plan. A digital well plan is generally designed to be independent of a specific rig, whereas a digital rig plan is a digital well plan that has been modified to incorporate the specific equipment available on a specific rig to execute the well plan on the specific rig, such as rig 10. Therefore, the rig controller 250 can be configured to monitor and facilitate the execution of the digital well plan by monitoring and executing rig tasks in the digital rig plan.

Examples of local data sources are shown in FIG. 1A where an imaging system can include the rig controller 250 and imaging sensors 72 positioned at desired locations around the rig and around the support equipment/material areas, such as mud pumps (see FIG. 2), horizontal storage area 56, power system 26, etc., to collect imagery of the desired locations. Also, various sensors 74 can be positioned at various locations around the rig 10 and the support equipment/material areas to collect information from the rig equipment (e.g., pipe handler 30, roughneck 38, top drive 18, vertical storage area36, etc.) and support equipment (e.g., crane 46, forklift 48, horizontal storage area 56, power system 26, etc.) to collect operational parameters of the equipment. Additional information can be collected from other data sources, such as reports and logs 28 (e.g., tour reports, daily progress reports, reports from remote locations, shipment logs, delivery logs, personnel logs, etc.).

These data sources can be aggregated by the rig controller 250 and used to determine an estimated well activity of the rig and comparing it to the digital well plan to determine the progress and performance of the rig 10 in executing the digital well plan. The data collected from the data sources during a first time interval can be compared to reference data in a well activity database to determine the estimated well activity of the rig along with a confidence level that can indicate a level of confidence that the estimated well activity is the actual well activity being performed by the rig. A low confidence level may indicate that there is a low probability that the estimated well activity is the actual well activity being performed by the rig, and a high confidence level may indicate that there is a high probability that the estimated well activity is the actual well activity being performed by the rig. With the confidence level determined and the estimated well activity determined, the rig controller 250 can compare the estimated well activity to the expected well activity (which can be defined by the digital well plan) and determine if the estimated well activity is the actual well activity being performed on the rig 10.

If the confidence level is below a predetermined threshold, then data can be collected from the data sources during a second time interval and compared to reference data in a well activity database to confirm that the estimated well activity of the rig is the actual well activity being performed by the rig. The second time interval can be adjusted, based on the confidence level, to capture more or fewer data from the data sources. For example, if the confidence level is below a second predetermined threshold, then the second time interval can be increased to capture a larger amount of data from the data sources, but if the confidence level is above the second predetermined threshold, then the second time interval can be decreased to capture a smaller amount of data from the data sources. In either case, the second time interval can be adjusted as needed to confirm that the estimated well activity is the actual well activity being performed on the rig 10.

The data sources can also include wearables 70 (e.g., a smart wristwatch, a smartphone, a tablet, a laptop, an identification badge, a wearable transmitter, etc.) that can be worn by an individual 4 (or user 4) to identify the individual 4, deliver instructions to the individual 4, or receive inputs from the individual 4 via the wearable 70 to the rig controller 250 (see FIG. 1B). Network connections (wired or wireless) to the wearables 70 can be used for communication between the rig controller 250 and the wearables 70 for information transfer.

FIG. 2 is a representative partial cross-sectional view of a rig 10 being used to drill a wellbore 15 in an earthen formation 8. FIG. 2 shows a land-based rig, but the principles of this disclosure can equally apply to off-shore rigs, as well. The rig 10 can include a top drive 18 with a traveling block 19 used to raise or lower the top drive 18. A derrick 14 extending from the rig floor, can provide the structural support of the rig equipment for performing subterranean operations (e.g., drilling, treating, completing, producing, testing, etc.). The rig can be used to extend a wellbore 15 through the earthen formation 8 by using a tubular string 58 having a Bottom Hole Assembly (BHA) 60 at its lower end. The BHA 60 can include a drill bit 68 and multiple drill collars 62, with one or more of the drill collars including instrumentation 64 for LWD and MWD operations. During drilling operations, drilling mud can be pumped from the surface 6 into the tubular string 58 (e.g., via pumps 84 supplying mud to the top drive 18 via standpipe 86) to cool and lubricate the drill bit 68 and to transport cuttings to the surface via an annulus 17 between the tubular string 58 and the wellbore 15.

The returned mud can be directed to the mud pit 88 through the flow line 81 and the shale shaker 80. A fluid treatment system 82 can inject additives as desired to the mud to condition the mud appropriately for the current well activities and possibly future well activities as the mud is being pumped to the mud pit 88. The mud pump 84 can pull mud from the mud pit 88 and drive it to the top drive 18 via standpipe 86 to continue the circulation of the mud through the tubular string 58.

Sensors 74 and imaging sensors 72 can be distributed about the rig and downhole to provide information on the environments in these areas as well as operating conditions, health of equipment, well activity of equipment, fluid properties, WOB, ROP, RPM of the drill string, RPM of the drill bit 68, etc.

The rig 10 may generally be used to perform subterranean operations in a wellbore 15, such as the drilling of the wellbore 15, completion of the wellbore 15, and subsequently production of hydrocarbon fuels from the wellbore 15. In some embodiments, the rig 10 or the rig controller 250 may receive a digital rig plan which comprises a sequence of at least a subset of available rig tasks for the rig 10. In some embodiments, the rig 10 or the rig controller 250 may thereafter execute one or more rig tasks in the digital rig plan.

In implementing the rig tasks in the digital rig plan, the rig 10 or the rig controller 250 may control rig 10 equipment in accordance with the digital rig plan. The rig 10 equipment may include a top drive 18, a fluid pump 84, a fluid treatment system 82, a shale shaker 80, other rig 10 equipment, or any combination thereof. In some embodiments, the fluid pump 84 may be configured to pump drilling mud through the top drive 18 and into the wellbore 15. In some embodiments, the fluid treatment system 82, the shale shaker 80, or a combination thereof may be configured to treat the drilling mud returning from the wellbore 15 prior to the drilling mud returning to a mud pit 88 configured to store the drilling mud.

In some embodiments, one or more of the rig tasks in the digital rig plan may involve a fluid. In some embodiments, the rig task may comprise pumping a fluid, treating a fluid, or a combination thereof. In some embodiments, the fluid may comprise drilling mud. In some embodiments, the rig task may comprise pumping the drilling mud through the top drive 18 and into the wellbore 15. In some embodiments, a rig task may also include the return of the drilling mud from the wellbore 15 to the mud pit 88. In some embodiments, the rig task may comprise treating the drilling mud with a fluid treatment system, a shale shaker, or a combination thereof before returning to the mud pit 88 configured to store the drilling mud. In some embodiments, the rig task may occur during the drilling of the wellbore 15, tripping of tubular 54 into the wellbore 15, or one or more other rig operations utilized to execute the digital rig plan 102.

In some embodiments, one or more of the rig tasks may comprise monitoring at least one parameter of the fluid during the execution of the rig task. The monitoring of the at least one parameter of the fluid can be accomplished via one or more sensors 74 disposed about the rig 10. The one or more sensors 74 may be communicatively coupled to the rig controller 250. In some embodiments, the one or more sensors 74 may comprise a fluid rheology sensor, a pressure sensor, a temperature sensor, environmental sensors (e.g., barometric pressure, dew point, atmospheric pressure, humidity, etc.), or a combination thereof. The monitoring of the at least one parameter of the fluid can be accomplished via one or more sensors 74 configured to measure the at least one parameter of the fluid at the fluid pump 84, at the top drive 18, at the fluid treatment system 82, at the shale shaker 80, in the mud pit 88, in the wellbore 15, or a combination thereof. In certain embodiments, the at least one parameter of the fluid may comprise a flow rate of the fluid, a pressure of the fluid, a temperature of the fluid, a chemical composition of the fluid, a presence or lack of presence of a particular chemical or substance in the fluid, a presence or lack of presence of solids in the fluid, a wellbore pressure, or a combination thereof.

The monitoring of the one or more parameters of the fluid may be used to control the rig task. The rig task can be continued or stopped based on the monitoring of the at least one parameter of the fluid. In some embodiments, the rig task may continue in response to the at least one parameter of the fluid not being at a desired or predetermined value. Accordingly, in some embodiments, continuing the rig task may comprise no change to the digital rig plan. In some embodiments, the rig task may be drilling of a wellbore, cleaning of a wellbore, cementing a wellbore, completing a wellbore, controlling inflow of production fluid from a wellbore, or a combination thereof.

In some embodiments, continuing the rig task may comprise adjusting one or more operational parameters of the digital rig plan. In some embodiments, adjusting the one or more operational parameters of the digital rig plan may be implemented automatically by the rig controller, manually by an operator of the rig controller (e.g., local or remote operators), interactively between the rig controller and the operator, or a combination thereof. In some embodiments, sensor data of the at least one parameter of the fluid may be obtained for a first time interval and compared to the digital rig plan, which may prompt the adjusting of at least one or more operational parameters of the digital rig plan. Thereafter, in some embodiments, sensor data of the at least one parameter of the fluid may be obtained for a second time interval after the first time interval and compared to the digital rig plan to ensure conformance with the digital rig plan.

It will be appreciated that the monitoring of the one or more parameters of the fluid or the adjustment of one or more operational parameters of the digital rig plan may be accomplished to change the operation of the rig 10 or control parameters of the wellbore 15. The monitoring of the one or more parameters of the fluid or the adjustment of the one or more operational parameters of the digital rig plan may occur in real time to bring about changes in real time. Further, in some embodiments, adjustment of the one or more operational parameters of the digital rig plan may attempt to eliminate waste, reduce the power requirement of the rig, conserve power utilized by the rig, or optimize the rig 10 equipment. Accordingly, in some embodiments, the one or more operational parameters of the digital rig plan may comprise a flow rate of the fluid, an operational pump capacity of the fluid pump, implementation of a fluid treatment, or a combination thereof.

In some embodiments, the rig task may be stopped in response to the at least one parameter of the fluid being at a desired or predetermined value. In some embodiments, the rig task may be stopped in response to the wellbore being “clean” or otherwise having minimal solids present in the drilling mud. Additionally, in some embodiments, stopping the rig task may comprise proceeding to a next rig task in the digital rig plan. In some embodiments, stopping the rig task or proceeding to the next rig task may be implemented automatically by the rig controller. In some embodiments, stopping the rig task or proceeding to the next rig task may be implemented manually by an operator (e.g., local or remote) of the rig controller.

FIG. 3 is a representative flow diagram of a method 300 of performing a subterranean operation, in accordance with certain embodiments. The method 300 may begin at block 302 with operations of receiving at the rig controller 250 a digital rig plan 102 which comprises a sequence of at least a subset of available rig tasks for a rig 10. Operations at block 304 may include executing a rig task in the digital rig plan 102 that involves a fluid. Operations at block 306 may include monitoring at least one parameter of the fluid during the execution of the rig task. Operations at block 308 may include comparing the at least one parameter of the fluid to an expected parameter. Operations at block 310 may include determining whether or not the rig task should be stopped or continued based on the comparing of the at least one parameter of the fluid. In certain embodiments, the method 300 may comprise operations of continuing the rig task in response to the at least one parameter of the fluid not being at a desired or predetermined value (e.g., returning to block 304 from block 310). In certain embodiments, the rig task can be stopped temporarily to adjust the at least one parameter of the fluid to the expected parameter value (such as indicated in block 312), or the method 300 may comprise stopping the rig task in response to the at least one parameter of the fluid being at a desired or predetermined value and proceeding to a next rig task in the digital rig plan (such as indicated in block 314) in response to the at least one parameter of the fluid being at a desired or predetermined value.

In a non-limiting embodiment, the method 300 can include monitoring, via one or more sensors, one or more parameters of the fluid, determining actual values of the one or more parameters, and comparing the actual values to expected values included in the digital rig plan 102. If the actual values are substantially equal to the expected values, the rig controller 250 can proceed with executing additional tasks of the digital rig plan. However, if the actual values are not substantially equal to the expected values, then one or more of the following can be performed: 1) the current task can be stopped until the actual values are substantially equal to the expected values, 2) the digital rig plan 102 can be modified to manage the deviation from the digital rig plan 102 and return the rig operations to the desired rig operations of the unmodified portion of the digital rig plan 102 to get back on track regarding execution of the digital rig plan 102.

If the fluid is being pumped into the wellbore 15 via the tubular string 58 with one or more sensors monitoring one or more fluid parameters of the fluid being pumped into the tubular string 58 and an actual value does not substantially equal the expected value from the digital rig plan 102, then this may be an indication that the fluid is not being maintained properly.

In a non-limiting example, if the actual value of the weight of the fluid is detected to be 10.5 pounds per gallon (ppg), but the digital rig plan 102 indicates that the weight of the fluid should be 11 ppg, then the rig task being performed may need to be stopped until the weight of the fluid is adjusted until it is substantially equal to the expected value of 11 ppg. The rig task can be restarted when the weight of the fluid is substantially equal to the expected value. If the detected fluid parameters indicate possibly serious events, then the digital rig plan 102 can be modified to change or add rig tasks to mitigate the events. Modifying the digital rig plan 102 can be performed to mitigate the event and return the rig operations back to the original digital rig plan 102 tasks and continue executing the digital rig plan 102.

The one or more sensors can detect an actual value for one or more parameters of the fluid and compare the actual value to an expected value, wherein the one or more parameters can be at least one of a mud weight of the fluid, a pressure of the fluid in the wellbore, a viscosity of the fluid, a concentration of a treatment in the fluid, a temperature of the fluid, or a combination thereof.

If the fluid is being received from the wellbore 15 with one or more sensors monitoring one or more fluid parameters of the fluid being received from the wellbore 15 and an actual value does not substantially equal the expected value from the digital rig plan 102, this may indicate that an event has already occurred, is currently occurring, or will occur in the future (e.g., near future).

In a non-limiting example, if the actual value fails the comparison with the expected value when one of the fluid parameters is pressure. The actual value of the pressure can indicate an elevated pressure or a pressure drop, which can indicate that the tubular string 58 has penetrated an earth formation with more or less pressure than expected. An elevated pressure can indicate a kick or gas influx into the wellbore 15. An elevated pressure can indicate that cuttings are restricting the circulation of the fluid through the wellbore 15. A pressure drop can indicate a fluid loss in the wellbore 15. The digital rig plan 102 can be modified to mitigate the unexpected pressure and begin executing the modified rig plan 102. The digital rig plan 102 can be modified to determine the cause of the unexpected pressure, determine rig tasks or rig task modifications to mitigate the event and begin executing the modified rig plan 102.

In a non-limiting example, one or more sensors can indicate that a fluid level is not being properly maintained when tripping a tubular string 58 out of the wellbore 15. The digital rig plan 102 can be modified to determine the cause of the unexpected fluid level in the wellbore, determine rig tasks or rig task modifications to mitigate the event and begin executing the modified rig plan 102. The digital rig plan 102 can be modified to determine the cause of the unexpected fluid level, determine rig tasks or rig task modifications to mitigate the event and begin executing the modified rig plan 102.

FIG. 4A is a representative list of well plan activities 170 for an example digital well plan 100. This list of well plan activities 170 can represent the activities needed to execute a full digital well plan 100. However, in FIG. 4A the list of activities 170 is merely representative of a subset of a complete list of activities needed to execute a full digital well plan 100 to drill and complete a wellbore 15 to a target depth (TD). The digital well plan 100 can include well plan activities 170 with corresponding wellbore depths 172. However, these activities 170 are not required for the digital well plan 100. More or fewer activities 170 can be included in the digital well plan 100 in keeping with the principles of this disclosure. Therefore, the following discussion relating to the well plan activities 170 is merely an example to illustrate the concepts of this disclosure.

After the rig 10 has been utilized to drill the wellbore 15 to a depth of 75, at activity 112, a Prespud meeting can be held to brief all rig personnel on the goals of the digital well plan 100. At activity 114, the appropriate personnel and rig equipment can be used to make-up (M/U) 5 ½″ drill pipe (DP) stands in prep for the upcoming drilling operation. This can, for example, require a pipe handler, horizontal or vertical storage areas for tubular segments, or tubular stands.

At activity 118, the appropriate personnel and rig equipment can be used to pick up (P/up), makeup (M/up), and run-in hole (RIH) a BHA with a 36″ drill bit 68. This can, for example, require BHA components; a pipe handler to assist in the assembly of the BHA components; a pipe handler to deliver BHA to a top drive; and lowering the top drive to run the BHA into the wellbore 15.

At activity 120, the appropriate personnel and rig equipment can be used to drill 36″ hole to a TD of the section, such as 652 ft, to +/- 30 ft inside a known formation layer (e.g., Dammam), and perform a deviation survey at depths of 150′, 500′ and TD (i.e., 652′ in this example). At activity 122, the appropriate personnel and rig equipment can be used to pump a high-viscosity pill through the wellbore 15 via the tubular string 58 and then circulate wellbore 15 clean. At activity 124, the appropriate personnel and rig equipment can be used to perform a “wiper trip” by pulling the tubular string 58 out of the hole (Pull out of hole - POOH) to the surface 6; clean stabilizers on the tubular string 58; and run the tubular string 58 back into the hole (Run in hole -RIH) to the bottom of the wellbore 15.

At activities 126 thru 168, the appropriate personnel and rig equipment can be used to perform the indicated well plan activities. Well activities can include the personnel, equipment, or materials needed to directly execute the well plan activities using the specific rig 10, and those activities that ensure the personnel, equipment, or materials are available and configured to support the primary activities.

FIG. 4B is a functional diagram that can illustrate the conversion of well plan activities 170 to rig plan tasks 190 of a rig specific digital rig plan 102. When a well plan 100 is designed, well plan activities 170 can be included to describe primary activities needed to construct a desired wellbore 15 to a TD. However, the well plan 100 activities 170 are not specific to a particular rig, such as rig 10. It may not be appropriate to use the well plan activities 170 to direct specific operations on a specific rig, such as rig 10. Therefore, a conversion of the well plan activities 170 can be performed to create a list of rig plan tasks 190 of a digital rig plan 102 to construct the desired wellbore 15 using a specific rig, such as rig 10. This conversion engine 180 (which can run on a computing system such as the rig controller 250) can take the non-rig specific well plan activities 170 as an input and convert each of the non-rig specific well plan activities 170 to one or more rig specific tasks 190 to create a digital rig plan 102 that can be used to direct tasks on a specific rig, such as rig 10, to construct the desired wellbore 15.

As a way of example, a high-level description of the conversion engine 180 will be described for a subset of well plan activities 170 to demonstrate a conversion process to create the digital rig plan 102. The well plan activity 118 states, in abbreviated form, to pick up, make up, and run-in hole a BHA 60 with a 36″ drill bit. The conversion engine 180 can convert this single non-rig specific activity 118 into, for example, three rig-specific tasks 118.1, 118.2, 118.3. Task 118.1 can instruct the rig operators or rig controller 250 to pick up the BHA 60 (which has been outfitted with a 36″ drill bit) with a pipe handler. At task 118.2, the pipe handler can carry the BHA 60 and deliver it to the top drive 18, with the top drive 18 using an elevator 44 to grasp and lift the BHA 60 into a vertical position. At task 118.3, the top drive 18 can lower the BHA 60 into the wellbore 15 which has already been drilled to a depth of 75′ for this example. The top drive 18 can lower the BHA 60 to the bottom of the wellbore 15 to have the drill bit 68 in position to begin drilling as indicated in the following well activity 120.

The well plan activity 120 states, in abbreviated form, to drill a 36″ hole to a target depth (TD) of the section, such as 652 ft, to +/- 30 ft inside a known formation layer (e.g., Dammam), and performing a deviation survey at depths of 150′, 500′ and TD (i.e., 652′ in this example). The conversion engine 180 can convert this single non-rig specific activity 120 into, for example, seven rig-specific tasks 120.1 to 120.7. Task 120.1 can instruct the rig operators or rig controller 250 to circulate mud through the top drive 18, through the tubular string 58, through the BHA 60, and exiting the tubular string 58 through the drill bit 68 into the annulus 17. For this example, the mud flow requires two mud pumps 84 to operate at “NN” strokes per minute, where “NN” is a desired value that delivers the desired mud flow and pressure. At task 120.2, the shaker tables can be turned on in preparation for cuttings that should be coming out of the annulus 17 when the drilling begins. At task 120.3, a mud engineer can verify that the mud characteristics are appropriate for the current tasks of drilling the wellbore 15. If the rheology indicates that mud characteristics should be adjusted, then additives can be added to adjust the mud characteristics as needed.

At task 120.4, rotary drilling can begin by lowering the drill bit into contact with the bottom of the wellbore 15 and rotating the drill bit by rotating the top drive 18 (e.g., rotary drilling). The drilling parameters can be set to be “XX” ft/min for the rate of penetration (ROP), “YY” lbs. for weight on bit (WOB), and “ZZ” revolutions per minute (RPM) of the drill bit 68.

At task 120.5, as the wellbore 15 is extended by the rotary drilling when the top end of the tubular string 58 is less than “XX” ft above the rig floor 16, then a new tubular segment (e.g., tubular, tubular stand, etc.) can be added to the tubular string 58 by retrieving a tubular segment 50, 54 from tubular storage via a pipe handler, stop mud flow and disconnect the top drive from the tubular string 58, hold the tubular string 58 in place via the slips at well center, raise the top drive 18 to provide clearance for the tubular segment to be added, transfer tubular segment 50, 54 from the pipe handler 30 to the top drive 18, connect the tubular segment 50, 54 to the top drive 18, lower the tubular segment 50, 54 to the stump of the tubular string 58 and connect it to the tubular string 58 using a roughneck to torque the connection, then start mud flow. This can be performed each time the top end of the tubular string 58 is lowered below “XX” ft above the rig floor 16.

At task 120.6, add tubular segments 50, 54 to the tubular string 58 as needed in task 120.5 to drill wellbore 15 to a depth of 150 ft. Stop rotation of the drill bit 68 and stop mud pumps 84.

At task 120.7, perform a deviation survey by reading the inclination data from the BHA 60, comparing the inclination data to expected inclination data, and report deviations from the expected. Correct drilling parameters if deviations are greater than a pre-determined limit.

The conversion from a well plan 100 to a rig-specific rig plan 102 can be performed manually or automatically with the best practices and equipment recipes known for the rig that is to be used in the wellbore construction.

FIG. 5 is a representative functional block diagram of the rig plan engine 180 that can include possible databases used by a rig controller 250 to convert a digital well plan 100 to a digital rig plan 102 and for identifying individuals detected in work zones on the rig 10. The rig plan engine 180 can be a program (i.e., list of instructions 268) that can be stored in the non-transitory memory 252 and executed by processor(s) 254 of the rig controller 250 to convert a digital well plan 100 to a digital rig plan 102 or identify individuals 4 on the rig 10.

A digital well plan 100 can be received at an input to the rig controller 250 via a network interface 256. The digital well plan 100 can be received by the processor(s) 254 and stored in the memory 252. The processor(s) 254 can then begin reading the sequential list of well plan activities 170 of the digital well plan 100 from the memory 252. The processor(s) 254 can process each well plan activity 170 to create rig-specific tasks to implement the respective activity 170 on a specific rig (e.g., rig 10).

To convert each well plan activity 170 to rig-specific tasks for a rig 10, processor(s) 254 must determine the equipment available on the rig 10, the best practices, operations, and parameters for running each piece of equipment, and the operations to be run on the rig to implement each of the well plan activities 170.

Referring again to FIG. 5, the processor(s) 254 are communicatively coupled to the non-transitory memory 252 which can store multiple databases for converting the well plan 100 into the rig plan 102. A rig operations database 260 includes rig operations for implementing each of the well plan activities 170. Each of the rig operations can include one or more tasks to perform the rig operation. The processor(s) 254 can retrieve those operations for implementing the first rig activity 170 from the rig operations database 260 including the task lists for each operation. The processor(s) 254 can receive a rig type RT from a user input or the network interface 256. With the rig type RT, the processor(s) 254 can retrieve a list of equipment available on the rig 10 from the rig type database 262, which can contain equipment lists for a plurality of rig types. The available equipment can be determined from the rig equipment database 264.

The processor(s) 254 can then convert the operational tasks to rig specific tasks to implement the operations on the rig 10. The rig specific tasks can include the appropriate equipment for rig 10 to perform the operation task. The processor(s) 254 can then collect the recipes for operating each of the available equipment for rig 10 from the recipes database 266, where the recipes can include best practices on operating the equipment, preferred parameters for operating the equipment, and operational tasks for the equipment (such as turn ON procedures, ramp up procedures, ramp down procedures, shutdown procedures, etc.). A full set of available rig tasks can be stored in the rig tasks database 267. A full set of available well activities can be stored in the well activities database 258. Parameters for all rig equipment, including best practices for the rig equipment can be stored in the parameters database 276.

Therefore, the processor(s) 254 can retrieve each of the well plan activities 170 and convert them to a list of rig specific tasks that can perform the respective well plan activity 170 on the rig 10. After converting all of the well plan activities 170 to rig specific tasks 190 and creating a sequential list of the tasks 190, the processor(s) 254 can store the resulting digital rig plan 102 in the memory 252. When the rig 10 is operational and positioned at the proper location to drill a wellbore 15, the rig controller 250, via the processor(s) 254, can begin executing the list of tasks in the digital rig plan 102 by sending control signals and messages to the equipment control 270.

The rig controller 250 can also receive user input from an input device 272 or display information to a user or individual 4 via a display 274. The input device 272 in cooperation with the display 274 can be used to input well plan activities, initiate processes (such as converting the digital well plan 100 to the digital rig plan 102), select alternative activities, or rig tasks during the execution of digital well plan 100 or digital rig plan 102, or monitor operations during well plan execution. The input device 272 can also include the sensors 74 and the imaging sensors 72, which can provide sensor data (e.g., image data, temperature sensor data, pressure sensor data, operational parameter sensor data, etc.) to the rig controller 250 for determining the actual well activity of the rig.

VARIOUS EMBODIMENTS

Embodiments of a rig 10, a rig controller 250, a method 300, or other methods disclosed herein may include one or more of the following:

Embodiment 1. A method of performing a subterranean operation, comprising: receiving a digital rig plan which comprises a sequence of at least a subset of available rig tasks for a rig; executing a rig task in the digital rig plan that involves a fluid; monitoring at least one parameter of the fluid during the execution of the rig task; and continuing or stopping the rig task based on the monitoring of the at least one parameter of the fluid.

Embodiment 2. The method of embodiment 1, wherein the digital rig plan is received into a rig controller.

Embodiment 3. The method of embodiment 2, wherein the rig controller is configured to control rig equipment in accordance with the digital rig plan.

Embodiment 4. The method of embodiment 3, wherein the rig equipment comprises a top drive, a fluid pump, a fluid treatment system, a shale shaker, or a combination thereof.

Embodiment 5. The method of embodiment 4, wherein the fluid pump is configured to pump drilling mud from the rig, through a tubular string, and into a wellbore.

Embodiment 6. The method of embodiment 5, wherein the fluid treatment system, the shale shaker, or a combination thereof are configured to treat the drilling mud returning from the wellbore prior to the drilling mud returning to a mud pit configured to store the drilling mud.

Embodiment 7. The method of any one of embodiments 1 to 6, wherein the rig task comprises pumping a fluid, treating a fluid, or a combination thereof.

Embodiment 8. The method of embodiment 7, wherein the fluid comprises drilling mud.

Embodiment 9. The method of embodiment 8, wherein the rig task comprises pumping the drilling mud from the rig, through a tubular string, and into the wellbore.

Embodiment 10. The method of any one of embodiments 8 to 9, wherein the rig task comprises treating the drilling mud with a fluid treatment system, a shale shaker, or a combination thereof.

Embodiment 11. The method of any one of embodiments 7 to 10, wherein the rig task occurs during drilling of the wellbore, tripping of tubular into the wellbore, or a combination thereof.

Embodiment 12. The method of any one of embodiments 1 to 11, wherein the monitoring of the at least one parameter of the fluid is accomplished via one or more sensors.

Embodiment 13. The method of embodiment 12, wherein the one or more sensors are communicatively coupled to a rig controller.

Embodiment 14. The method of any one of embodiments 12 to 13, wherein the one or more sensors comprise a fluid rheology sensor, a pressure sensor, a temperature sensor, or a combination thereof.

Embodiment 15. The method of any one of embodiments 12 to 14, wherein the monitoring of the at least one parameter of the fluid is accomplished via one or more sensors configured to measure the at least one parameter of the fluid at the fluid pump, at the top drive, at the fluid treatment system, at the shale shaker, in the mud pit, in the wellbore, or a combination thereof.

Embodiment 16. The method of any one of embodiments 1 to 15, wherein the at least parameter of the fluid comprises a flow rate of the fluid, a pressure of the fluid, a temperature of the fluid, a chemical composition of the fluid, a presence or lack of presence of a particular chemical or substance in the fluid, a presence or lack of presence of solids in the fluid, a wellbore pressure, or a combination thereof.

Embodiment 17. The method of any one of embodiments 1 to 16, wherein the continuing the rig task occurs in response to the at least one parameter of the fluid not being at a desired or predetermined value.

Embodiment 18. The method of any one of embodiments 1 to 17, wherein the continuing the rig task comprises no change to the digital rig plan.

Embodiment 19. The method of any one of embodiments 1 to 17, wherein the continuing the rig task comprises adjusting one or more operational parameters of the digital rig plan.

Embodiment 20. The method of embodiment 19, wherein the adjusting the one or more operational parameters of the digital rig plan is implemented automatically by the rig controller, manually by an operator of the rig controller, interactively between the rig controller and the operator, or a combination thereof.

Embodiment 21. The method of any one of embodiments 1 to 20, wherein the one or more adjusted operational parameters of the digital rig plan comprises a flow rate of the fluid, an operational pump capacity of the fluid pump, a number of fluid pumps employed, implementation of a fluid treatment, or a combination thereof.

Embodiment 22. The method of any one of embodiments 1 to 21, wherein the stopping the rig task occurs in response to the at least one parameter of the fluid being at a desired or predetermined value.

Embodiment 23. The method of embodiment 22, wherein the stopping the rig task comprises proceeding to a next rig task in the digital rig plan.

Embodiment 24. The method of any one of embodiments 22 to 23, wherein the stopping the rig task is implemented automatically by the rig controller, manually by an operator of the rig controller, interactively between the rig controller and the operator, or a combination thereof.

Embodiment 25. A system for performing a subterranean operation, comprising: a rig controller configured to receive a digital rig plan and implement the steps of any one of embodiments 1 to 24.

Embodiment 26. A method of performing a subterranean operation, comprising:

receiving a digital rig plan which comprises a sequence of at least a subset of available rig tasks for a rig;
executing a rig task in the digital rig plan that involves a fluid;
monitoring at least one parameter of the fluid during execution of the rig task; and
adjusting the digital rig plan based on the monitoring of the at least one parameter of the fluid.

Embodiment 27. The method of embodiment 26, further comprising:

comparing an actual value of the at least one parameter of the fluid to an expected value in the digital rig plan.

Embodiment 28. The method of embodiment 27, further comprising:

adjusting the fluid to cause the actual value of the at least one parameter to substantially equal the expected value.

Embodiment 29. The method of embodiment 28, further comprising:

stopping the rig task until the actual value substantially equals the expected value; and
resuming the rig task after the actual value substantially equals the expected value.

Embodiment 30. The method of embodiment 29, wherein the fluid is being pumped into a tubular string in a wellbore, wherein the at least one parameter is at least one of:

a mud weight of the fluid;
a pressure of the fluid in the wellbore;
a viscosity of the fluid;
a concentration of a treatment in the fluid; and
a combination thereof.

Embodiment 31. The method of embodiment 27, wherein the comparing of the actual value with the expected value indicates that an event in a wellbore has occurred, is occurring, or will occur.

Embodiment 32. The method of embodiment 31, wherein the event is at least one of:

an unexpected spike in pressure in the wellbore;
an unexpected drop in the pressure in the wellbore;
a build-up of cuttings is restricting circulation of the fluid;
gas influx into the wellbore;
gas present in the cuttings;
fluid loss into the wellbore;
low fluid level in the wellbore; and
a combination thereof.

Embodiment 33. The method of embodiment 31, further comprising:

adjusting the digital rig plan to manage the event, via adjusting one or more rig tasks, adding one or more rig tasks, or combinations thereof.

Embodiment 34. A system for performing a subterranean operation, comprising:

a rig controller configured to receive a digital rig plan and implement the method of any one of embodiments 25 to 33.

While the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and tables and have been described in detail herein. However, it should be understood that the embodiments are not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims. Further, although individual embodiments are discussed herein, the disclosure is intended to cover all combinations of these embodiments.

RIG TASK MANAGEMENT

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