SYSTEMS AND TECHNIQUES FOR AUTOMATED DRILLING

BACKGROUND

Modern drilling operations require coordination of many simultaneous systems and processes to monitor, among other things: drilling efficiency, safety, communication channels, fuel supply, power conservation, and preservation of tools and equipment. As these systems grow in size and complexity, additional pressure is put on human operators to ensure that various independent systems are coordinated and functioning properly. Further, a human operator is generally responsible for processing information provided by these systems and making the ultimate decisions on drill operation parameters and what actions to take. This dependence on human operators puts heavy reliance on the expertise of specific personnel. Further, even with experienced operators, many important parameters for performance are not weighed, which limits the performance capabilities of the drilling system. As such, inefficiencies and risks are present in the drilling operation by failing to optimize all available information between independent systems.

Various drilling systems have aspects that are presently automated. However, many of these systems do not automate configuration of the drilling system or optimization of the drilling system.

SUMMARY

Systems and methods are disclosed for optimizing drilling operations. The systems and methods can include receiving information, such as a drilling roadmap or drilling plan for a well to be drilled. The drilling roadmap can and usually does provide a great deal of information, including formation information, equipment information, geological information, well trajectory information, and so on. During drilling of a well, one or more computer and/or control systems usually receive a stream of data from downhole and surface sensors. Such data typically includes data that comprises data relating to a number of drilling parameters. In one or more embodiments, the sensor data relating to drilling parameters can be combined with additional data from a number of other sources to better monitor control and adjust the drilling of a well in real-time.

The systems and methods can include receiving a selection of one or more factors for optimizing drilling operations. The one or more factors can include environmental, social, governance (ESG) or greenhouse gas (GHG) measurements, such as for power generation for drilling operations. The one or more factors can include a top detection update and a landing target for the formation. The one or more factors can include a drilling dysfunction measurement or a drilling mechanical specific energy (MSE) measurement trend. The one or more factors for optimizing drilling operations can include a lifespan of bottom hole assembly (BHA) equipment.

The systems and methods can include generating one or more control signals based at least in part on the drilling roadmap, the plurality of operating parameters, and the one or more selected factors for optimizing drilling operations. The systems and methods can include transmitting the one or more instructions to a drilling controller. The systems and methods can include adjusting drilling operations.

In an aspect, the systems and methods of drilling operations can include receiving strategy information from a drilling roadmap. The drilling roadmap can provide formation and deposit information, as well as other geological information. The systems and methods can include receiving a plurality of operating parameters from one or more sensors.

The systems and methods can include generating a report based at least in part on the strategy information and the plurality of operating parameters. In various embodiments, the report comprises an automated status comprising information based at least in part on the strategy information and the plurality of operating parameters. In various embodiments, the report comprises a 3D forecast of the plurality of operating parameters including zones and restriction areas. In various embodiments, the report comprises a listing of all system configuration changes.

The report can include a graphical depiction of offset historical performance, real-time performance, adjacent rig performance, or theoretical best-case performance. The report can include a graphical depiction of lithology and anticipated changes in conjunction with application tools. A user interface or display can include a graphical depiction of ECD/hole cleaning based at least in part on all forms of cuttings tracking (e.g., PWD, shaker vision, volumetric measurement) to identify a hole cleaning status.

The systems and methods can include transmitting the report to an operator.

In an aspect, systems and methods can include determining a probability score of an unsafe condition based at least in part on the plurality of operating parameters. The systems and methods can include determining a severity score of the unsafe condition or event. The systems and methods can include calculating an overall risk score based at least on the probability score and risk score.

When the overall risk score exceeds a risk threshold, the technique can include implementing a mitigation strategy. The mitigation strategy can include employing a safe mode configuration. The mitigation strategy can include a configuration lockout for certain pre-defined drilling events. The mitigation strategy can include adjusting operations based at least in part on proximity of rig crews to a rig floor. A proximity can be determined using computer vision.

In various embodiments, the mitigation strategy can include employing safety oversight modes that allow increased visibility with remote operators. The mitigation strategy can include identifying and tracking one or more danger zones. The mitigation strategy can include using computer vision to determine when personal protective equipment is not being worn during heightened safety conditions.

The systems and methods can include determining an appropriate set of drilling parameters before or during drilling and transmitting the one or more updated parameters to a drilling controller, then drilling according to the one or more set of parameters.

The systems and methods can further include identifying a formation change or an operations change. The systems and methods can include determining one or more mud weight properties based at least in part on the formation change or the operations change. The systems and methods can include providing an operator a recommendation of the determined one or more mud weight properties.

The systems and methods can include detecting one or more operating parameters indicative of sliding operations. Based on said detecting, the systems and methods can include providing a recommendation of one or more additives in anticipation of sliding operations. The plurality of operating parameters can include bit information, determining bit TFS for one or more operating conditions to verify bit cleaning and cools. The system or method can include adjusting one or more operating parameters proactively in conjunction with borehole cleaning status.

The systems and methods can include detecting one or more operating parameters indicative of lost circulation zones. Based on said detecting, the systems and methods can include providing a recommendation of lost circulation materials into the mud.

In an aspect, the systems, and methods for optimizing drilling operations can include comparing the plurality of operating parameters to one or more sequenced tasks in the drilling roadmap. The systems and methods can include generating one or more control signals based at least in part on the comparing the plurality of operating parameters to one or more sequenced tasks in the drilling roadmap. The one or more control signals can provide real-time updates to anticipated project management events.

The systems and methods can include transmitting the one or more control signals to a scheduling module.

The systems and methods can include adjusting one or more drilling parameters based at least in part on logistics limitations.

The systems and methods can include tracking a number of crews present at a drilling site in conjunction with one or more drilling activities being performed.

The systems and methods can include scheduling one or more logistic events based at least in part on progress through the one or more sequenced tasks in the drilling roadmap.

The systems and methods can include scheduling one or more roaming crews based at least in part in a rig status.

According to one embodiment, a method of optimizing drilling operations including receiving, by a computer system located remotely at a location separate from a drilling rig, a drilling roadmap for drilling a wellbore, receiving, by the computer system located remotely at the location separate from the drilling rig, a plurality of operating parameters based on information from one or more sensors during drilling of the wellbore, receiving, by the computer system located remotely at the location separate from the drilling rig, a selection of one or more factors for optimizing drilling operations and generating, by a processor of the computer system located remotely at the location separate from the drilling rig, a report including one or more instructions for a drilling rig controller. The report is based at least in part on the plurality of operating parameters and the selection of one or more factors for optimizing drilling operations. The method further includes transmitting, by the processor of the computer system located remotely at the location separate from the drilling rig, the report to an operator located remotely at the location separate from the drilling rig. The one or more instructions are editable by the operator prior to transmitting the one or more instructions to the drilling rig controller. The method includes receiving, by the drilling rig controller, the report including the one or more instructions, from the operator and implement, by the drilling rig controller, the one or more instructions as modified by the operator, or the instructions as originally generated.

The method may include various optional embodiments. The method may further include storing the report and any edited versions of the report. The one or more operating parameters may be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. The plurality of operating parameters from the one or more sensors may be processed with computer vision. The one or more factors may concern environmental, social, governance (ESG) or greenhouse gas (GHG) measurements for power generation for a rig site. The one or more factors may concern a top detection update and a landing target for the formation. The one or more factors for optimizing drilling operations may concern a lifespan of bottom hole assembly (BHA) equipment.

According to another embodiment, a drilling rig control system located remotely at a location separate from a drilling rig includes a processor and memory coupled to the processor The memory stores instructions for receiving, by the processor, a drilling roadmap for drilling a wellbore, receiving, by the processor, a plurality of operating parameters based on information from one or more sensors during drilling of the wellbore, receiving, by the processor, a selection of one or more factors for optimizing drilling operations, and generating, by the processor, a report including one or more instructions for a drilling rig controller. The report is based at least in part on the plurality of operating parameters and the selection of one or more factors for optimizing drilling operations. The system further includes instructions for transmitting, by the processor, the report to an operator located remotely at the location separate from the drilling rig. The one or more instructions are editable by the operator prior to transmitting the one or more instructions to the drilling rig controller. The system further includes instructions for receiving, by the drilling rig controller, the report including the one or more instructions, from the operator, and implementing, by the drilling rig controller, the one or more instructions as modified by the operator, or the instructions as originally generated.

The system may include various optional embodiments. The system may include instructions to store, by the processor, the report and any edited versions of the report. The one or more operating parameters may be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. The plurality of operating parameters from the one or more sensors may be processed with computer vision. The one or more factors may concern environmental, social, governance (ESG) or greenhouse gas (GHG) measurements for power generation for a rig site. The one or more factors may concern a top detection update and a landing target for the formation. The one or more factors for optimizing drilling operations may concern a lifespan of bottom hole assembly (BHA) equipment.

According to another embodiment, a non-transitory computer-readable medium stores instructions that when executed by one or more processors performs operations for receiving, by the processor located remotely at a location separate from a drilling rig, a drilling roadmap for drilling a wellbore, a drilling roadmap for drilling a wellbore, receiving, by the processor located remotely at the location separate from the drilling rig, a plurality of operating parameters based on information from one or more sensors during drilling of the wellbore, receiving, by the processor located remotely at the location separate from the drilling rig, a selection of one or more factors for optimizing drilling operations, and generating, by the processor located remotely at the location separate from the drilling rig, a report including one or more instructions for a drilling rig controller. The report is based at least in part on the plurality of operating parameters and the selection of one or more factors for optimizing drilling operations. The instructions for the one or more processors performs operations for transmitting, by the processor located remotely at the location separate from the drilling rig, the report to an operator located remotely at the location separate from the drilling rig. The one or more instructions are editable by the operator prior to transmitting the one or more instructions to the drilling rig controller. The instructions for the one or more processors performs operations for receiving, by the drilling rig controller, the report including the one or more instructions, from the operator, and implementing, by the drilling rig controller, the one or more instructions as modified by the operator, or the instructions as originally generated.

The non-transitory computer-readable medium may include various optional embodiments. The non-transitory computer-readable medium may include further comprising instructions to store, by the processor, the report and any edited versions of the report. The one or more operating parameters may be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. The plurality of operating parameters from the one or more sensors may be processed with computer vision. The one or more factors may concern environmental, social, governance (ESG) or greenhouse gas (GHG) measurements for power generation for a rig site. The one or more factors may concern a top detection update and a landing target for the formation.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

FIG. 1 is a depiction of a drilling system for drilling a borehole;

FIG. 2A is a depiction of a drilling environment including the drilling system for drilling a borehole;

FIG. 2B is a depiction of a borehole generated in the drilling environment;

FIG. 3 illustrates one embodiment of a drilling environment in which a bit guidance steerable system may operate;

FIG. 4 is a depiction of a drilling architecture including the drilling environment;

FIG. 5 is a depiction of rig control systems included in the drilling system;

FIG. 6 is a depiction of algorithm modules used by the rig control systems;

FIG. 7 is a depiction of a steering control process used by the rig control systems;

FIG. 8 is a depiction of a graphical user interface provided by the rig control systems;

FIG. 9 is a depiction of a guidance control loop performed by the rig control systems;

FIG. 10 is a depiction of a controller usable by the rig control systems;

FIG. 11 is a depiction of one of several elements of a rig control and exchange platform;

FIG. 12 is a depiction of one of many embodiments of a system involving multiple video sources cameras for monitoring personnel location;

FIG. 13 shows one of many embodiments of the disclosed rig state estimation system utilizing multiple cameras;

FIG. 14 is a depiction of drill string and drill bit rotation using a rotary steerable BHA;

FIG. 15 illustrates one embodiment of possible communication channels used within a drilling environment that does not have the benefit of a surface steerable system;

FIG. 16 illustrates one embodiment of possible communication channels used within a drilling environment that has the benefit of a surface steerable system;

FIG. 17 illustrates one embodiment of data flow that may be supported by a surface steerable system;

FIG. 18 illustrates one embodiment of a convergence plan diagram with multiple convergence paths;

FIG. 19 illustrates one embodiment of a system architecture that may be used for a surface steerable system;

FIG. 20 illustrates one embodiment of a more detailed portion of the system architecture of FIG. 19;

FIG. 21 illustrates one embodiment of a guidance control loop that may be used within the system architecture of FIG. 19;

FIG. 22 illustrates one embodiment of an autonomous control loop that may be used within the system architecture of FIG. 19;

FIG. 23 illustrates one embodiment of a computer system that may be used within a surface steerable system;

FIG. 24 illustrates one embodiment of a graphical user interface that may be used to retrieve a log file and add, edit, or delete baseline markers;

FIG. 25 shows a perspective view of a drilling environment in accordance with at least some embodiments;

FIG. 26 shows a representation of a wellbore path in accordance with at least some embodiments;

FIG. 27 illustrates one embodiment of a three-dimensional borehole space;

FIG. 28 illustrates an exemplary embodiment of a mud additive system;

FIG. 29 illustrates a flowchart for an example process associated with systems and methods to optimize drilling operations;

FIG. 30 illustrates a flowchart for an example process for communication systems and methods for drilling operations;

FIG. 31 illustrates a flowchart for an example process for improved safety systems and methods for drilling operations;

FIG. 32 illustrates a flowchart for an example process for determining mud weight properties for drilling operations;

FIG. 33 illustrates a flowchart for an example process for improving logistics processes for drilling operations;

FIG. 34 illustrates a controller located remotely from the drilling rig at a central control location for multiple drilling rigs;

FIG. 35 illustrates a schematic for providing information and software updates in a drilling rig ecosystem; and

FIG. 36 illustrates a schematic of a user interface useful for improved drilling operations.

DETAILED DESCRIPTION OF THE DRAWINGS

The following detailed description of example implementations refers to the accompanying drawings. The same reference numbers in different drawings may identify the same or similar elements.

Referring now to the drawings, Referring to FIG. 1, a drilling system 100 is illustrated in one embodiment as a top drive system. As shown, the drilling system 100 includes a derrick 132 on the surface 104 of the earth and is used to drill a borehole 106 into the earth. Typically, drilling system 100 is used at a location corresponding to a geographic formation 102 in the earth that is known.

In FIG. 1, derrick 132 includes a crown block 134 to which a traveling block 136 is coupled via a drilling line 138. In drilling system 100, a top drive 140 is coupled to traveling block 136 and may provide rotational force for drilling. A saver sub 142 may sit between the top drive 140 and a drill pipe 144 that is part of a drill string 146. Top drive 140 may rotate drill string 146 via the saver sub 142, which in turn may rotate a drill bit 148 of a bottom hole assembly (BHA) 149 in borehole 106 passing through formation 102. Also visible in drilling system 100 is a rotary table 162 that may be fitted with a master bushing 164 to hold drill string 146 when not rotating.

A mud pump 152 may direct a fluid mixture 153 (e.g., a mud mixture) from a mud pit 154 into drill string 146. Mud pit 154 is shown schematically as a container, but it is noted that various receptacles, tanks, pits, or other containers may be used. Mud 153 may flow from mud pump 152 into a discharge line 156 that is coupled to a rotary hose 158 by a standpipe 160. Rotary hose 158 may then be coupled to top drive 140, which includes a passage for mud 153 to flow into borehole 106 via drill string 146 from where mud 153 may emerge at drill bit 148. Mud 153 may lubricate drill bit 148 during drilling and, due to the pressure supplied by mud pump 152, mud 153 may return via borehole 106 to surface 104.

In drilling system 100, drilling equipment (see also FIG. 5) is used to perform the drilling of borehole 106, such as top drive 140 (or rotary drive equipment) that couples to drill string 146 and BHA 149 and is configured to rotate drill string 146 and apply pressure to drill bit 148. Drilling system 100 may include control systems such as a WOB/differential pressure control system 522, a positional/rotary control system 524, a fluid circulation control system 526, and a sensor system 528, as further described below with respect to FIG. 5. The control systems may be used to monitor and change drilling rig settings, such as the WOB or differential pressure to alter the ROP or the radial orientation of the tool face, change the flow rate of drilling mud, and perform other operations. Sensor system 528 may be for obtaining sensor data about the drilling operation and drilling system 100, including the downhole equipment. For example, sensor system 528 may include MWD or logging while drilling (LWD) tools for acquiring information, such as tool face and formation logging information, that may be saved for later retrieval, transmitted with or without a delay using any of various communication means (e.g., wireless, wireline, or mud pulse telemetry), or otherwise transferred to steering control system 168. As used herein, an MWD tool is enabled to communicate downhole measurements without substantial delay to the surface 104, such as using mud pulse telemetry, while a LWD tool is equipped with an internal memory that stores measurements when downhole and can be used to download a stored log of measurements when the LWD tool is at the surface 104. The internal memory in the LWD tool may be a removable memory, such as a universal serial bus (USB) memory device or another removable memory device. It is noted that certain downhole tools may have both MWD and LWD capabilities. Such information acquired by sensor system 528 may include information related to hole depth, bit depth, inclination angle, azimuth angle, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary rotations per minute (RPM), bit speed, ROP, WOB, among other information. It is noted that all or part of sensor system 528 may be incorporated into a control system, or in another component of the drilling equipment. As drilling system 100 can be configured in many different implementations, it is noted that different control systems and subsystems may be used.

Sensing, detection, measurement, evaluation, storage, alarm, and other functionality may be incorporated into a downhole tool 166, or BHA 149, or elsewhere along drill string 146 to provide downhole surveys of borehole 106. Accordingly, downhole tool 166 may be an MWD tool or a LWD tool or both, and may accordingly utilize connectivity to the surface 104, local storage, or both. In different implementations, gamma radiation sensors, magnetometers, accelerometers, and other types of sensors may be used for the downhole surveys. Although downhole tool 166 is shown in singular in drilling system 100, it is noted that multiple instances (not shown) of downhole tool 166 may be located at one or more locations along drill string 146.

In some embodiments, formation detection and evaluation functionality may be provided via a steering control system 168 on the surface 104. Steering control system 168 may be located in proximity to derrick 132 or may be included with drilling system 100. In other embodiments, steering control system 168 may be remote from the actual location of borehole 106 (see also FIG. 4). For example, steering control system 168 may be a stand-alone system or may be incorporated into other systems included with drilling system 100.

In operation, steering control system 168 may be accessible via a communication network (see also FIG. 10) and may accordingly receive formation information via the communication network. In some embodiments, steering control system 168 may use the evaluation functionality to provide corrective measures, such as a convergence plan to overcome an error in the well trajectory of borehole 106 with respect to a reference, or a planned well trajectory. The convergence plans or other corrective measures may depend on a determination of the well trajectory, and therefore, may be improved in accuracy using surface steering, as disclosed herein.

In particular embodiments, at least a portion of steering control system 168 may be located in downhole tool 166 (not shown). In some embodiments, steering control system 168 may communicate with a separate controller (not shown) located in downhole tool 166. In particular, steering control system 168 may receive and process measurements received from downhole surveys and may perform the calculations described herein for surface steering using the downhole surveys and other information referenced herein.

In drilling system 100, to aid in the drilling process, data is collected from borehole 106, such as from sensors in BHA 149, downhole tool 166, or both. The collected data may include the geological characteristics of formation 102 in which borehole 106 was formed, the attributes of drilling system 100, including BHA 149, and drilling information such as weight-on-bit (WOB), drilling speed, and other information pertinent to the formation of borehole 106. The drilling information may be associated with a particular depth or another identifiable marker to index collected data. For example, the collected data for borehole 106 may capture drilling information indicating that drilling of the well from 1,000 feet to 1,200 feet occurred at a first rate of penetration (ROP) through a first rock layer with a first WOB, while drilling from 1,200 feet to 1,500 feet occurred at a second ROP through a second rock layer with a second WOB (see also FIG. 2). In some applications, the collected data may be used to virtually recreate the drilling process that created borehole 106 in formation 102, such as by displaying a computer simulation of the drilling process. The accuracy with which the drilling process can be recreated depends on a level of detail and accuracy of the collected data, including collected data from a downhole survey of the well trajectory.

The collected data may be stored in a database that is accessible via a communication network for example. In some embodiments, the database storing the collected data for borehole 106 may be located locally at drilling system 100, at a drilling hub that supports a plurality of drilling systems 100 in a region, or at a database server accessible over the communication network that provides access to the database (see also FIG. 4). At drilling system 100, the collected data may be stored at the surface 104 or downhole in drill string 146, such as in a memory device included with BHA 149 (see also FIG. 10). Alternatively, at least a portion of the collected data may be stored on a removable storage medium, such as using steering control system 168 or BHA 149, that is later coupled to the database in order to transfer the collected data to the database, which may be manually performed at certain intervals, for example.

In FIG. 1, steering control system 168 is located at or near the surface 104 where borehole 106 is being drilled. Steering control system 168 may be coupled to equipment used in drilling system 100 and may also be coupled to the database, whether the database is physically located locally, regionally, or centrally (see also FIGS. 4 and 5). Accordingly, steering control system 168 may collect and record various inputs, such as measurement data from a magnetometer and an accelerometer that may also be included with BHA 149.

Steering control system 168 may further be used as a surface steerable system, along with the database, as described above. The surface steerable system may enable an operator to plan and control drilling operations while drilling is being performed. The surface steerable system may itself also be used to perform certain drilling operations, such as controlling certain control systems that, in turn, control the actual equipment in drilling system 100 (see also FIG. 5). The control of drilling equipment and drilling operations by steering control system 168 may be manual, manual-assisted, semi-automatic, or automatic, in different embodiments.

Manual control may involve direct control of the drilling rig equipment, albeit with certain safety limits to prevent unsafe or undesired actions or collisions of different equipment. To enable manual-assisted control, steering control system 168 may present various information, such as using a graphical user interface (GUI) displayed on a display device (see FIG. 8), to a human operator, and may provide controls that enable the human operator to perform a control operation. The information presented to the user may include live measurements and feedback from the drilling rig and steering control system 168, or the drilling rig itself, and may further include limits and safety-related elements to prevent unwanted actions or equipment states, in response to a manual control command entered by the user using the GUI.

To implement semi-automatic control, steering control system 168 may itself propose or indicate to the user, such as via the GUI, that a certain control operation, or a sequence of control operations, should be performed at a given time. Then, steering control system 168 may enable the user to imitate the indicated control operation or sequence of control operations, such that once manually started, the indicated control operation or sequence of control operations is automatically completed. The limits and safety features mentioned above for manual control would still apply for semi-automatic control. It is noted that steering control system 168 may execute semi-automatic control using a secondary processor, such as an embedded controller that executes under a real-time operating system (RTOS), that is under the control and command of steering control system 168. To implement automatic control, the step of manual starting the indicated control operation or sequence of operations is eliminated, and steering control system 168 may proceed with only a passive notification to the user of the actions taken.

In order to implement various control operations, steering control system 168 may perform (or may cause to be performed) various input operations, processing operations, and output operations. The input operations performed by steering control system 168 may result in measurements or other input information being made available for use in any subsequent operations, such as processing or output operations. The input operations may accordingly provide the input information, including feedback from the drilling process itself, to steering control system 168. The processing operations performed by steering control system 168 may be any processing operation associated with surface steering, as disclosed herein. The output operations performed by steering control system 168 may involve generating output information for use by external entities, or for output to a user, such as in the form of updated elements in the GUI, for example. The output information may include at least some of the input information, enabling steering control system 168 to distribute information among various entities and processors.

In particular, the operations performed by steering control system 168 may include operations such as receiving drilling data representing a drill path, receiving other drilling parameters, calculating a drilling solution for the drill path based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Accordingly, steering control system 168 may receive input information either before drilling, during drilling, or after drilling of borehole 106. The input information may comprise measurements from one or more sensors, as well as survey information collected while drilling borehole 106. The input information may also include a well plan, a regional formation history, drilling engineer parameters, downhole tool face/inclination information, downhole tool gamma/resistivity information, economic parameters, reliability parameters, among various other parameters. Some of the input information, such as the regional formation history, may be available from a drilling hub 410, which may have respective access to a regional drilling database (DB) 412 (see FIG. 4). Other input information may be accessed or uploaded from other sources to steering control system 168. For example, a web interface may be used to interact directly with steering control system 168 to upload the well plan or drilling parameters.

As noted, the input information may be provided to steering control system 168. After processing by steering control system 168, steering control system 168 may generate control information that may be output to drilling rig 210 (e.g., to rig controls 520 that control drilling equipment 530, see also FIGS. 2A and 5). Drilling rig 210 may provide feedback information using rig controls 520 to steering control system 168. The feedback information may then serve as input information to steering control system 168, thereby enabling steering control system 168 to perform feedback loop control and validation. Accordingly, steering control system 168 may be configured to modify its output information to the drilling rig, in order to achieve the desired results, which are indicated in the feedback information. The output information generated by steering control system 168 may include indications to modify one or more drilling parameters, the direction of drilling, the drilling mode, among others. In certain operational modes, such as semi-automatic or automatic, steering control system 168 may generate output information indicative of instructions to rig controls 520 to enable automatic drilling using the latest location of BHA 149. Therefore, an improved accuracy in the determination of the location of BHA 149 may be provided using steering control system 168, along with the methods and operations for surface steering disclosed herein.

Referring now to FIG. 2A, a drilling environment 200 is depicted schematically and is not drawn to scale or perspective. In particular, drilling environment 200 may illustrate additional details with respect to formation 102 below the surface 104 in drilling system 100 shown in FIG. 1. In FIG. 2A, drilling rig 210 may represent various equipment discussed above with respect to drilling system 100 in FIG. 1 that is located at the surface 104.

In drilling environment 200, it may be assumed that a drilling plan (also referred to as a well plan) has been formulated to drill borehole 106 extending into the ground to a true vertical depth (TVD) 266 and penetrating several subterranean strata layers. Borehole 106 is shown in FIG. 2A extending through strata layers 268A and 270A, while terminating in strata layer 272A. Accordingly, as shown, borehole 106 does not extend or reach underlying strata layers 274A and 276A. A target area 280 specified in the drilling plan may be located in strata layer 272A as shown in FIG. 2A. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272A. It is noted that target area 280 may be of any shape and size and may be defined using various different methods and information in different embodiments. In some instances, target area 280 may be specified in the drilling plan using subsurface coordinates, or references to certain markers, which indicate where borehole 106 is to be terminated. In other instances, target area may be specified in the drilling plan using a depth range within which borehole 106 is to remain. For example, the depth range may correspond to strata layer 272A. In other examples, target area 280 may extend as far as can be realistically drilled. For example, when borehole 106 is specified to have a horizontal section with a goal to extend into strata layer 272 as far as possible, target area 280 may be defined as strata layer 272A itself and drilling may continue until some other physical limit is reached, such as a property boundary or a physical limitation to the length of the drill string.

Also visible in FIG. 2A is a fault line 278 that has resulted in a subterranean discontinuity in the fault structure. Specifically, strata layers 268, 270, 272, 274, and 276 have portions on either side of fault line 278. On one side of fault line 278, where borehole 106 is located, strata layers 268A, 270A, 272A, 274A, and 276A are unshifted by fault line 278. On the other side of fault line 278, strata layers 268B, 270B, 272B, 274B, and 276B are shifted downwards by fault line 278.

Current drilling operations frequently include directional drilling to reach a target, such as target area 280. The use of directional drilling has been found to generally increase an overall amount of production volume per well, but also may lead to significantly higher production rates per well, which are both economically desirable. As shown in FIG. 2A, directional drilling may be used to drill the horizontal portion of borehole 106, which increases an exposed length of borehole 106 within strata layer 272A, and which may accordingly be beneficial for hydrocarbon extraction from strata layer 272A. Directional drilling may also be used alter an angle of borehole 106 to accommodate subterranean faults, such as indicated by fault line 278 in FIG. 2. Other benefits that may be achieved using directional drilling include sidetracking off of an existing well to reach a different target area or a missed target area, drilling around abandoned drilling equipment, drilling into otherwise inaccessible or difficult to reach locations (e.g., under populated areas or bodies of water), providing a relief well for an existing well, and increasing the capacity of a well by branching off and having multiple boreholes extending in different directions or at different vertical positions for the same well. Directional drilling is often not limited to a straight horizontal borehole 106 but may involve staying within a strata layer that varies in depth and thickness as illustrated by strata layer 272. As such, directional drilling may involve multiple vertical adjustments that complicate the trajectory of borehole 106.

Referring now to FIG. 2B, one embodiment of a portion of borehole 106 is shown in further detail. Using directional drilling for horizontal drilling may introduce certain challenges or difficulties that may not be observed during vertical drilling of borehole 106. For example, a horizontal portion 292 of borehole 106 may be started from a vertical portion 290. In order to make the transition from vertical to horizontal, a curve may be defined that specifies a so-called “build up” section 294. Build up section 294 may begin at a kickoff point 296 in vertical portion 290 and may end at a begin point 298 of horizontal portion 292. The change in inclination in buildup section 294 per measured length drilled is referred to herein as a “build rate” and may be defined in degrees per one hundred feet drilled. For example, the build rate may have a value of 6°/100 feet, indicating that there is a six degree change in inclination for everyone hundred feet drilled. The build rate for a particular build up section may remain relatively constant or may vary.

The build rate used for any given build up section may depend on various factors, such as properties of the formation (i.e., strata layers) through which borehole 106 is to be drilled, the trajectory of borehole 106, the particular pipe and drill collars/BHA components used (e.g., length, diameter, flexibility, strength, mud motor bend setting, and drill bit), the mud type and flow rate, the specified horizontal displacement, stabilization, and inclination, among other factors. An overly aggressive built rate can cause problems such as severe doglegs (e.g., sharp changes in direction in the borehole) that may make it difficult or impossible to run casing or perform other operations in borehole 106. Depending on the severity of any mistakes made during directional drilling, borehole 106 may be enlarged or drill bit 146 may be backed out of a portion of borehole 106 and redrilled along a different path. Such mistakes may be undesirable due to the additional time and expense involved. However, if the built rate is too cautious, additional overall time may be added to the drilling process because directional drilling generally involves a lower ROP than straight drilling. Furthermore, directional drilling for a curve is more complicated than vertical drilling and the possibility of drilling errors increases with directional drilling (e.g., overshoot and undershoot that may occur while trying to keep drill bit 148 on the planned trajectory).

Two modes of drilling, referred to herein as “rotating” and “sliding,” are commonly used to form borehole 106. Rotating, also called “rotary drilling,” uses top drive 140 or rotary table 162 to rotate drill string 146. Rotating may be used when drilling occurs along a straight trajectory, such as for vertical portion 290 of borehole 106. Sliding, also called “steering” or “directional drilling” as noted above, typically uses a mud motor located downhole at BHA 149. The mud motor may have an adjustable bent housing and is not powered by rotation of the drill string. Instead, the mud motor uses hydraulic power derived from the pressurized drilling mud that circulates along borehole 106 to and from the surface 104 to directionally drill borehole 106 in buildup section 294.

Thus, sliding is used in order to control the direction of the well trajectory during directional drilling. A method to perform a slide may include the following operations. First, during vertical or straight drilling, the rotation of drill string 146 is stopped. Based on feedback from measuring equipment, such as from downhole tool 166, adjustments may be made to drill string 146, such as using top drive 140 to apply various combinations of torque, WOB, and vibration, among other adjustments. The adjustments may continue until a tool face is confirmed that indicates a direction of the bend of the mud motor is oriented to a direction of a desired deviation (i.e., build rate) of borehole 106. Once the desired orientation of the mud motor is attained, WOB to the drill bit is increased, which causes the drill bit to move in the desired direction of deviation. Once sufficient distance and angle have been built up in the curved trajectory, a transition back to rotating mode can be accomplished by rotating the drill string again. The rotation of the drill string after sliding may neutralize the directional deviation caused by the bend in the mud motor due to the continuous rotation around a centerline of borehole 106.

Referring to FIG. 3, one embodiment of an environment 300 is illustrated with multiple wells 302, 304, 306, 308, and a drilling rig 310. In the present example, the wells 302 and 304 are located in a region 312, the well 306 is located in a region 314, the well 308 is located in a region 316, and the drilling rig 310 is located in a region 318. Each region 312, 314, 316, and 318 may represent a geographic area having similar geological formation characteristics. For example, region 312 may include particular formation characteristics identified by rock type, porosity, thickness, and other geological information. These formation characteristics affect drilling of the wells 302 and 304. Region 314 may have formation characteristics that are different enough to be classified as a different region for drilling purposes, and the different formation characteristics affect the drilling of the well 306. Likewise, formation characteristics in the regions 316 and 318 affect the well 308 and drilling rig 310, respectively.

It is understood the regions 312, 314, 316, and 318 may vary in size and shape depending on the characteristics by which they are identified. Furthermore, the regions 312, 314, 316, and 318 may be sub-regions of a larger region. Accordingly, the criteria by which the regions 312, 314, 316, and 318 are identified is less important for purposes of the present disclosure than the understanding that each region 312, 314, 316, and 318 includes geological characteristics that can be used to distinguish each region from the other regions from a drilling perspective. Such characteristics may be relatively major (e.g., the presence or absence of an entire rock layer in a given region) or may be relatively minor (e.g., variations in the thickness of a rock layer that extends through multiple regions).

Accordingly, drilling a well located in the same region as other wells, such as drilling a new well in the region 312 with already existing wells 302 and 304, means the drilling process is likely to face similar drilling issues as those faced when drilling the existing wells in the same region. For similar reasons, a drilling process performed in one region is likely to face issues different from a drilling process performed in another region. However, even the drilling processes that created the wells 302 and 304 may face different issues during actual drilling as variations in the formation are likely to occur even in a single region.

Drilling a well typically involves a substantial amount of human decision making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and the available information to make decisions on how to plan the drilling operation, how to accomplish the plan, and how to handle issues that arise during drilling. However, even the best geologists and drilling engineers perform some guesswork due to the unique nature of each borehole. Furthermore, a directional driller directly responsible for the drilling may have drilled other boreholes in the same region and so may have some similar experience, but it is impossible for a human to mentally track all the possible inputs and factor those inputs into a decision. This can result in expensive mistakes, as errors in drilling can add hundreds of thousands or even millions of dollars to the drilling cost and, in some cases, drilling errors may permanently lower the output of a well, resulting in substantial long-term losses.

In the present example, to aid in the drilling process, each well 302, 304, 306, and 308 has corresponding collected data 320, 322, 324, and 326, respectively. The collected data may include the geological characteristics of a particular formation in which the corresponding well was formed, the attributes of a particular drilling rig, including the bottom hole assembly (BHA), and drilling information such as weight-on-bit (WOB), drilling speed, and/or other information pertinent to the formation of that particular borehole. The drilling information may be associated with a particular depth or other identifiable marker so that, for example, it is recorded that drilling of the well 302 from 1000 feet to 1200 feet occurred at a first ROP through a first rock layer with a first WOB, while drilling from 1200 feet to 1500 feet occurred at a second ROP through a second rock layer with a second WOB. The collected data may be used to recreate the drilling process used to create the corresponding well 302, 304, 306, or 308 in the particular formation. It is understood that the accuracy with which the drilling process can be recreated depends on the level of detail and accuracy of the collected data.

The collected data 320, 322, 324, and 326 may be stored in a centralized database 328 as indicated by lines 330, 332, 334, and 336, respectively, which may represent any wired and/or wireless communication channel(s). The database 328 may be located at a drilling hub (not shown) or elsewhere. Alternatively, the data may be stored on a removable storage medium that is later coupled to the database 328 in order to store the data. The collected data 320, 322, 324, and 326 may be stored in the database 328 as formation data 338, equipment data 340, and drilling data 342 for example. Formation data 338 may include any formation information, such as rock type, layer thickness, layer location (e.g., depth), porosity, gamma readings, etc. Equipment data 340 may include any equipment information, such as drilling rig configuration (e.g., rotary table or top drive), bit type, mud composition, etc. Drilling data 342 may include any drilling information, such as drilling speed, WOB, differential pressure, toolface orientation, etc. The collected data may also be identified by well, region, and other criteria, and may be sortable to enable the data to be searched and analyzed. It is understood that many different storage mechanisms may be used to store the collected data in the database 328.

Referring now to FIG. 4, a drilling architecture 400 is illustrated in diagram form. As shown, drilling architecture 400 depicts a hierarchical arrangement of drilling hubs 410 and a central command 414, to support the operation of a plurality of drilling rigs 210 in different regions 402. Specifically, as described above with respect to FIGS. 1 and 2A, drilling rig 210 includes steering control system 168 that is enabled to perform various drilling control operations locally to drilling rig 210. When steering control system 168 is enabled with network connectivity, certain control operations or processing may be requested or queried by steering control system 168 from a remote processing resource. As shown in FIG. 4, drilling hubs 410 represent a remote processing resource for steering control system 168 located at respective regions 402, while central command 414 may represent a remote processing resource for both drilling hub 410 and steering control system 168.

Specifically, in a region 402-1, a drilling hub 410-1 may serve as a remote processing resource for drilling rigs 210 located in region 401-1, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, drilling hub 410-1 may have access to a regional drilling DB 412-1, which may be local to drilling hub 410-1. Additionally, in a region 402-2, a drilling hub 410-2 may serve as a remote processing resource for drilling rigs 210 located in region 402-2, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, drilling hub 410-2 may have access to a regional drilling DB 412-2, which may be local to drilling hub 410-2.

In FIG. 4, respective regions 402 may exhibit the same or similar geological formations. Thus, reference wells, or offset wells, may exist in a vicinity of a given drilling rig 210 in region 402, or where a new well is planned in region 402. Furthermore, multiple drilling rigs 210 may be actively drilling concurrently in region 402 and may be in different stages of drilling through the depths of formation strata layers at region 402. Thus, for any given well being drilled by drilling rig 210 in a region 402, survey data from the reference wells or offset wells may be used to create the well plan, and may be used for surface steering, as disclosed herein. In some implementations, survey data or reference data from a plurality of reference wells may be used to improve drilling performance, such as by reducing an error in estimating TVD or a position of BHA 149 relative to one or more strata layers, as will be described in further detail herein. Additionally, survey data from recently drilled wells, or wells still currently being drilled, including the same well, may be used for reducing an error in estimating TVD or a position of BHA 149 relative to one or more strata layers.

Also shown in FIG. 4 is central command 414, which has access to central drilling DB 416, and may be located at a centralized command center that is in communication with drilling hubs 410 and drilling rigs 210 in various regions 402. The centralized command 414 may have the ability to monitor drilling and equipment activity at any one or more drilling rigs 210. In some embodiments, central command 414 and drilling hubs 412 may be operated by a commercial operator of drilling rigs 210 as a service to customers who have hired the commercial operator to drill wells and provide other drilling-related services.

In FIG. 4, it is particularly noted that central drilling DB 416 may be a central repository that is accessible to drilling hubs 410 and drilling rigs 210. Accordingly, central drilling DB 416 may store information for various drilling rigs 210 in different regions 402. In some embodiments, central drilling DB 416 may serve as a backup for at least one regional drilling DB 412 or may otherwise redundantly store information that is also stored on at least one regional drilling DB 412. In turn, regional drilling DB 412 may serve as a backup or redundant storage for at least one drilling rig 210 in region 402. For example, regional drilling DB 412 may store information collected by steering control system 168 from drilling rig 210.

In some embodiments, the formulation of a drilling plan for drilling rig 210 may include processing and analyzing the collected data in regional drilling DB 412 to create a more effective drilling plan. Furthermore, once the drilling has begun, the collected data may be used in conjunction with current data from drilling rig 210 to improve drilling decisions. As noted, the functionality of steering control system 168 may be provided at drilling rig 210, or may be provided, at least in part, at a remote processing resource, such as drilling hub 410 or central command 414.

As noted, steering control system 168 may provide functionality as a surface steerable system for controlling drilling rig 210. Steering control system 168 may have access to regional drilling DB 412 and central drilling DB 416 to provide the surface steerable system functionality. As will be described in greater detail below, steering control system 168 may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. Steering control system 168 may be used to perform operations such as receiving drilling data representing a drill trajectory and other drilling parameters, calculating a drilling solution for the drill trajectory based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at drilling rig 210, monitoring the drilling process to gauge whether the drilling process is within a margin of error that is defined for the drill trajectory, or calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Referring now to FIG. 5, an example of rig control systems 500 is illustrated in schematic form. It is noted that rig control systems 500 may include fewer or more elements than shown in FIG. 5 in different embodiments. As shown, rig control systems 500 includes steering control system 168 and drilling rig 210. Specifically, steering control system 168 is shown with logical functionality including an autodriller 510, a bit guidance 512, and an autoslide 514. Drilling rig 210 is hierarchically shown including rig controls 520, which provide secure control logic and processing capability, along with drilling equipment 530, which represents the physical equipment used for drilling at drilling rig 210. As shown, rig controls 520 include WOB/differential pressure control system 522, positional/rotary control system 524, fluid circulation control system 526, and sensor system 528, while drilling equipment 530 includes a draw works/snub 532, top drive 140, a mud pumping 536, and an MWD/wireline 538.

Steering control system 168 represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10. Also, WOB/differential pressure control system 522, positional/rotary control system 524, and fluid circulation control system 526 may each represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10, but for example, in a configuration as a programmable logic controller (PLC) that may not include a user interface but may be used as an embedded controller. Accordingly, it is noted that each of the systems included in rig controls 520 may be a separate controller, such as a PLC, and may autonomously operate, at least to a degree. Steering control system 168 may represent hardware that executes instructions to implement a surface steerable system that provides feedback and automation capability to an operator, such as a driller. For example, steering control system 168 may cause autodriller 510, bit guidance 512 (also referred to as a bit guidance system (BGS)), and autoslide 514 (among others, not shown) to be activated and executed at an appropriate time during drilling. In particular implementations, steering control system 168 may be enabled to provide a user interface during drilling, such as the user interface 850 depicted and described below with respect to FIG. 8. Accordingly, steering control system 168 may interface with rig controls 520 to facilitate manual, assisted manual, semi-automatic, and automatic operation of drilling equipment 530 included in drilling rig 210. It is noted that rig controls 520 may also accordingly be enabled for manual or user-controlled operation of drilling and may include certain levels of automation with respect to drilling equipment 530.

In rig control systems 500 of FIG. 5, WOB/differential pressure control system 522 may be interfaced with draw works/snubbing unit 532 to control WOB of drill string 146. Positional/rotary control system 524 may be interfaced with top drive 140 to control rotation of drill string 146. Fluid circulation control system 526 may be interfaced with mud pumping 536 to control mud flow and may also receive and decode mud telemetry signals. Sensor system 528 may be interfaced with MWD/wireline 538, which may represent various BHA sensors and instrumentation equipment, among other sensors that may be downhole or at the surface.

In rig control systems 500, autodriller 510 may represent an automated rotary drilling system and may be used for controlling rotary drilling. Accordingly, autodriller 510 may enable automate operation of rig controls 520 during rotary drilling, as indicated in the well plan. Bit guidance 512 may represent an automated control system to monitor and control performance and operation drilling bit 148.

In rig control systems 500, autoslide 514 may represent an automated slide drilling system and may be used for controlling slide drilling. Accordingly, autoslide 514 may enable automate operation of rig controls 520 during a slide and may return control to steering control system 168 for rotary drilling at an appropriate time, as indicated in the well plan. In particular implementations, autoslide 514 may be enabled to provide a user interface during slide drilling to specifically monitor and control the slide. For example, autoslide 514 may rely on bit guidance 512 for orienting a tool face and on autodriller 510 to set WOB or control rotation or vibration of drill string 146.

FIG. 6 illustrates one embodiment of control algorithm modules 600 used with steering control system 168. The control algorithm modules 600 of FIG. 6 include: a slide control executor 650 that is responsible for managing the execution of the slide control algorithms; a slide control configuration provider 652 that is responsible for validating, maintaining, and providing configuration parameters for the other software modules; a BHA & pipe specification provider 654 that is responsible for managing and providing details of BHA 149 and drill string 146 characteristics; a borehole geometry model 656 that is responsible for keeping track of the borehole geometry and providing a representation to other software modules; a top drive orientation impact model 658 that is responsible for modeling the impact that changes to the angular orientation of top drive 140 have had on the tool face control; a top drive oscillator impact model 660 that is responsible for modeling the impact that oscillations of top drive 140 has had on the tool face control; an ROP impact model 662 that is responsible for modeling the effect on the tool face control of a change in ROP or a corresponding ROP set point; a WOB impact model 664 that is responsible for modeling the effect on the tool face control of a change in WOB or a corresponding WOB set point; a differential pressure impact model 666 that is responsible for modeling the effect on the tool face control of a change in differential pressure (DP) or a corresponding DP set point; a torque model 668 that is responsible for modeling the comprehensive representation of torque for surface, downhole, break over, and reactive torque, modeling impact of those torque values on tool face control, and determining torque operational thresholds; a tool face control evaluator 672 that is responsible for evaluating all factors impacting tool face control and whether adjustments need to be projected, determining whether re-alignment off-bottom is indicated, and determining off-bottom tool face operational threshold windows; a tool face projection 670 that is responsible for projecting tool face behavior for top drive 140, the top drive oscillator, and auto driller adjustments; a top drive adjustment calculator 674 that is responsible for calculating top drive adjustments resultant to tool face projections; an oscillator adjustment calculator 676 that is responsible for calculating oscillator adjustments resultant to tool face projections; and an autodriller adjustment calculator 678 that is responsible for calculating adjustments to autodriller 510 resultant to tool face projections.

FIG. 7 illustrates one embodiment of a steering control process 700 for determining a corrective action for drilling. Steering control process 700 may be used for rotary drilling or slide drilling in different embodiments.

Steering control process 700 in FIG. 7 illustrates a variety of inputs that can be used to determine an optimum corrective action. As shown in FIG. 7, the inputs include formation hardness/unconfined compressive strength (UCS) 710, formation structure 712, inclination/azimuth 714, current zone 716, measured depth 718, desired tool face 730, vertical section 720, bit factor 722, mud motor torque 724, reference trajectory 730, vertical section 720, bit factor 722, torque 724 and angular velocity 726. In FIG. 7, reference trajectory 730 of borehole 106 is determined to calculate a trajectory misfit in a step 732. Step 732 may output the trajectory misfit to determine a corrective action to minimize the misfit at step 734, which may be performed using the other inputs described above. Then, at step 736, the drilling rig is caused to perform the corrective action.

It is noted that in some implementations, at least certain portions of steering control process 700 may be automated or performed without user intervention, such as using rig control systems 700 (see FIG. 7). In other implementations, the corrective action in step 736 may be provided or communicated (by display, SMS message, email, or otherwise) to one or more human operators, who may then take appropriate action. The human operators may be members of a rig crew, which may be located at or near drilling rig 210 or may be located remotely from drilling rig 210.

Referring to FIG. 8, one embodiment of a user interface 850 that may be generated by steering control system 168 for monitoring and operation by a human operator is illustrated. User interface 850 may provide many different types of information in an easily accessible format. For example, user interface 850 may be shown on a computer monitor, a television, a viewing screen (e.g., a display device) associated with steering control system 168.

As shown in FIG. 8, user interface 850 provides visual indicators such as a hole depth indicator 852, a bit depth indicator 854, a GAMMA indicator 856, an inclination indicator 858, an azimuth indicator 860, and a TVD indicator 862. Other indicators may also be provided, including a ROP indicator 864, a mechanical specific energy (MSE) indicator 866, a differential pressure indicator 868, a standpipe pressure indicator 870, a flow rate indicator 872, a rotary RPM (angular velocity) indicator 874, a bit speed indicator 876, and a WOB indicator 878.

In FIG. 8, at least some of indicators 864, 866, 868, 870, 872, 874, 876, and 878 may include a marker representing a target value. For example, markers may be set as certain given values, but it is noted that any desired target value may be used. Although not shown, in some embodiments, multiple markers may be present on a single indicator. The markers may vary in color or size. For example, ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). MSE indicator 866 may include a marker 867 indicating that the target value is 37 kilopounds per square inch (ksi) (or 255 Mega Pascals (MPa)). Differential pressure indicator 868 may include a marker 869 indicating that the target value is 200 psi (or 1.38 kPa). ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). Standpipe pressure indicator 870 may have no marker in the present example. Flow rate indicator 872 may include a marker 873 indicating that the target value is 500 gallons per minute (gpm) (or 31.5 Liters per second (L/s)). Rotary rotations per minute (RPM) indicator 874 may include a marker 875 indicating that the target value is 0 RPM (e.g., due to sliding). Bit speed indicator 876 may include a marker 877 indicating that the target value is 150 RPM. WOB indicator 878 may include a marker 879 indicating that the target value is 10 kilopounds (klbs) (or 4,500 kilograms (kg)). Each indicator may also include a colored band, or another marking, to indicate, for example, whether the respective gauge value is within a safe range (e.g., indicated by a green color), within a caution range (e.g., indicated by a yellow color), or within a danger range (e.g., indicated by a red color).

In FIG. 8, a log chart 880 may visually indicate depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, log chart 880 may have a Y-axis representing depth and an X-axis representing a measurement such as GAMMA count 881 (as shown), ROP 883 (e.g., empirical ROP and normalized ROP), or resistivity. An autopilot button 882 and an oscillate button 884 may be used to control activity. For example, autopilot button 882 may be used to engage or disengage autodriller 510, while oscillate button 884 may be used to directly control oscillation of drill string 146 or to engage/disengage an external hardware device or controller.

In FIG. 8, a circular chart 886 may provide current and historical tool face orientation information (e.g., which way the bend is pointed). For purposes of illustration, circular chart 886 represents three hundred and sixty degrees. A series of circles within circular chart 886 may represent a timeline of tool face orientations, with the sizes of the circles indicating the temporal position of each circle. For example, larger circles may be more recent than smaller circles, so a largest circle 888 may be the newest reading and a smallest circle 889 may be the oldest reading. In other embodiments, circles 889, 888 may represent the energy or progress made via size, color, shape, a number within a circle, etc. For example, a size of a particular circle may represent an accumulation of orientation and progress for the period of time represented by the circle. In other embodiments, concentric circles representing time (e.g., with the outside of circular chart 886 being the most recent time and the center point being the oldest time) may be used to indicate the energy or progress (e.g., via color or patterning such as dashes or dots rather than a solid line).

In user interface 850, circular chart 886 may also be color coded, with the color coding existing in a band 890 around circular chart 886 or positioned or represented in other ways. The color coding may use colors to indicate activity in a certain direction. For example, the color red may indicate the highest level of activity, while the color blue may indicate the lowest level of activity. Furthermore, the arc range in degrees of a color may indicate the amount of deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red with a relatively broad (e.g., three hundred degrees) arc of blue may indicate that most activity is occurring in a particular tool face orientation with little deviation. As shown in user interface 850, the color blue may extend from approximately 22-337 degrees, the color green may extend from approximately 15-22 degrees and 337-345 degrees, the color yellow may extend a few degrees around the 13 and 345 degree marks, while the color red may extend from approximately 347-10 degrees. Transition colors or shades may be used with, for example, the color orange marking the transition between red and yellow or a light blue marking the transition between blue and green. This color coding may enable user interface 850 to provide an intuitive summary of how narrow the standard deviation is and how much of the energy intensity is being expended in the proper direction. Furthermore, the center of energy may be viewed relative to the target. For example, user interface 850 may clearly show that the target is at 90 degrees, but the center of energy is at 45 degrees.

In user interface 850, other indicators, such as a slide indicator 892, may indicate how much time remains until a slide occurs or how much time remains for a current slide. For example, slide indicator 892 may represent a time, a percentage (e.g., as shown, a current slide may be 56% complete), a distance completed, or a distance remaining. Slide indicator 892 may graphically display information using, for example, a colored bar 893 that increases or decreases with slide progress. In some embodiments, slide indicator 892 may be built into circular chart 886 (e.g., around the outer edge with an increasing/decreasing band), while in other embodiments slide indicator 892 may be a separate indicator such as a meter, a bar, a gauge, or another indicator type. In various implementations, slide indicator 892 may be refreshed by autoslide 514.

In user interface 850, an error indicator 894 may indicate a magnitude and a direction of error. For example, error indicator 894 may indicate that an estimated drill bit position is a certain distance from the planned trajectory, with a location of error indicator 894 around the circular chart 886 representing the heading. For example, FIG. 8 illustrates an error magnitude of 15 feet and an error direction of 15 degrees. Error indicator 894 may be any color but may be red for purposes of example. It is noted that error indicator 894 may present a zero if there is no error. Error indicator may represent that drill bit 148 is on the planned trajectory using other means, such as being a green color. Transition colors, such as yellow, may be used to indicate varying amounts of error. In some embodiments, error indicator 894 may not appear unless there is an error in magnitude or direction. A marker 896 may indicate an ideal slide direction. Although not shown, other indicators may be present, such as a bit life indicator to indicate an estimated lifetime for the current bit based on a value such as time or distance.

It is noted that user interface 850 may be arranged in many different ways. For example, colors may be used to indicate normal operation, warnings, and problems. In such cases, the numerical indicators may display numbers in one color (e.g., green) for normal operation, may use another color (e.g., yellow) for warnings, and may use yet another color (e.g., red) when a serious problem occurs. The indicators may also flash or otherwise indicate an alert. The gauge indicators may include colors (e.g., green, yellow, and red) to indicate operational conditions and may also indicate the target value (e.g., an ROP of 100 feet/hour). For example, ROP indicator 868 may have a green bar to indicate a normal level of operation (e.g., from 10-300 feet/hour), a yellow bar to indicate a warning level of operation (e.g., from 300-360 feet/hour), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 feet/hour). ROP indicator 868 may also display a marker at 100 feet/hour to indicate the desired target ROP.

Furthermore, the use of numeric indicators, gauges, and similar visual display indicators may be varied based on factors such as the information to be conveyed and the personal preference of the viewer. Accordingly, user interface 850 may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, steering control system 168 may enable a user to customize the user interface 850 as desired, although certain features (e.g., standpipe pressure) may be locked to prevent a user from intentionally or accidentally removing important drilling information from user interface 850. Other features and attributes of user interface 850 may be set by user preference. Accordingly, the level of customization and the information shown by the user interface 850 may be controlled based on who is viewing user interface 850 and their role in the drilling process.

Referring to FIG. 9, one embodiment of a guidance control loop (GCL) 900 is shown in further detail GCL 900 may represent one example of a control loop or control algorithm executed under the control of steering control system 168. GCL 900 may include various functional modules, including a build rate predictor 902, a geo modified well planner 904, a borehole estimator 906, a slide estimator 908, an error vector calculator 910, a geological drift estimator 912, a slide planner 914, a convergence planner 916, and a tactical solution planner 918. In the following description of GCL 900, the term “external input” refers to input received from outside GCL 900, while “internal input” refers to input exchanged between functional modules of GCL 900.

In FIG. 9, build rate predictor 902 receives external input representing BHA information and geological information, receives internal input from the borehole estimator 906, and provides output to geo modified well planner 904, slide estimator 908, slide planner 914, and convergence planner 916. Build rate predictor 902 is configured to use the BHA information and geological information to predict drilling build rates of current and future sections of borehole 106. For example, build rate predictor 902 may determine how aggressively a curve will be built for a given formation with BHA 149 and other equipment parameters.

In FIG. 9, build rate predictor 902 may use the orientation of BHA 149 to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if a strata layer of rock is below a strata layer of sand, a formation transition exists between the strata layer of sand and the strata layer of rock. Approaching the strata layer of rock at a 90-degree angle may provide a good tool face and a clean drill entry, while approaching the rock layer at a 45 degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause drill bit 148 to skip off the upper surface of the strata layer of rock. Accordingly, build rate predictor 902 may calculate BHA orientation to account for formation transitions. Within a single strata layer, build rate predictor 902 may use the BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a strata layer. The BHA information may include bit characteristics, mud motor bend setting, stabilization, and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information may enable a calculation-based prediction of the build rates and ROP that may be compared to both results obtained while drilling borehole 106 and regional historical results (e.g., from the regional drilling DB 412) to improve the accuracy of predictions as drilling progresses. Build rate predictor 902 may also be used to plan convergence adjustments and confirm in advance of drilling that targets can be achieved with current parameters.

In FIG. 9, geo modified well planner 904 receives external input representing a well plan, internal input from build rate predictor 902 and geo drift estimator 912 and provides output to slide planner 914 and error vector calculator 910. Geo modified well planner 904 uses the input to determine whether there is a more desirable trajectory than that provided by the well plan, while staying within specified error limits. More specifically, geo modified well planner 904 takes geological information (e.g., drift) and calculates whether another trajectory solution to the target may be more efficient in terms of cost or reliability. The outputs of geo modified well planner 904 to slide planner 914 and error vector calculator 910 may be used to calculate an error vector based on the current vector to the newly calculated trajectory and to modify slide predictions. In some embodiments, geo modified well planner 904 (or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, a geologist may provide steering control system 168 with a target inclination as a set point for steering control system 168 to control. For example, the geologist may enter a target to steering control system 168 of 90.5-91.0 degrees of inclination for a section of borehole 106. Geo modified well planner 904 may then treat the target as a vector target, while remaining within the error limits of the original well plan. In some embodiments, geo modified well planner 904 may be an optional module that is not used unless the well plan is to be modified. For example, if the well plan is marked in steering control system 168 as non-modifiable, geo modified well planner 904 may be bypassed altogether or geo modified well planner 904 may be configured to pass the well plan through without any changes.

In FIG. 9, borehole estimator 906 may receive external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and may provide outputs to build rate predictor 902, error vector calculator 910, and convergence planner 916. Borehole estimator 906 may be configured to provide an estimate of the actual borehole and drill bit position and trajectory angle without delay, based on either straight-line projections or projections that incorporate sliding. Borehole estimator 906 may be used to compensate for a sensor being physically located some distance behind drill bit 148 (e.g., 50 feet) in drill string 146, which makes sensor readings lag the actual bit location by 50 feet. Borehole estimator 906 may also be used to compensate for sensor measurements that may not be continuous (e.g., a sensor measurement may occur every 100 feet). Borehole estimator 906 may provide the most accurate estimate from the surface to the last survey location based on the collection of survey measurements. In addition, borehole estimator 906 may take the slide estimate from slide estimator 908 (described below) and extend the slide estimate from the last survey point to a current location of drill bit 148. Using the combination of these two estimates, borehole estimator 906 may provide steering control system 168 with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process.

In FIG. 9, slide estimator 908 receives external inputs representing measured depth and differential pressure information, receives internal input from build rate predictor 902, and provides output to borehole estimator 906 and geo modified well planner 904. Slide estimator 908 may be configured to sample tool face orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantify/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the downhole survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by a distance of the sensor point from the drill bit tip (e.g., approximately 50 feet). Such a response lag may introduce inefficiencies in the slide cycles due to over/under correction of the actual trajectory relative to the planned trajectory.

In GCL 900, using slide estimator 908, each tool face update may be algorithmically merged with the average differential pressure of the period between the previous and current tool face readings, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during the period. As an example, the periodic rate may be between 10 and 60 seconds per cycle depending on the tool face update rate of downhole tool 166. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of slide estimator 908 may accordingly be periodically provided to borehole estimator 906 for accumulation of well deviation information, as well to geo modified well planner 904. Some or all of the output of the slide estimator 908 may be output to an operator, such as shown in the user interface 850 of FIG. 8.

In FIG. 9, error vector calculator 910 may receive internal input from geo modified well planner 904 and borehole estimator 906. Error vector calculator 910 may be configured to compare the planned well trajectory to an actual borehole trajectory and drill bit position estimate. Error vector calculator 910 may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the well plan. For example, error vector calculator 910 may calculate the error between the current bit position and trajectory to the planned trajectory and the desired bit position. Error vector calculator 910 may also calculate a projected bit position/projected trajectory representing the future result of a current error.

In FIG. 9, geological drift estimator 912 receives external input representing geological information and provides outputs to geo modified well planner 904, slide planner 914, and tactical solution planner 918. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of ROP and BHA 149. Geological drift estimator 912 is configured to provide a drift estimate as a vector that can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.

In FIG. 9, slide planner 914 receives internal input from build rate predictor 902, geo modified well planner 904, error vector calculator 910, and geological drift estimator 912, and provides output to convergence planner 916 as well as an estimated time to the next slide. Slide planner 914 may be configured to evaluate a slide/drill ahead cost calculation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the well plan trajectory. During drill ahead, slide planner 914 may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., fluorinated beads) are indicated for the next slide, and pumping the lubricants into drill string 146 has a lead time of 30 minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants. Functionality for a loss circulation material (LCM) planner may be provided as part of slide planner 914 or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives should be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.

In FIG. 9, slide planner 914 may also look at the current position relative to the next connection. A connection may happen every 90 to 100 feet (or some other distance or distance range based on the particulars of the drilling operation) and slide planner 914 may avoid planning a slide when close to a connection or when the slide would carry through the connection. For example, if the slide planner 914 is planning a 50 foot slide but only 20 feet remain until the next connection, slide planner 914 may calculate the slide starting after the next connection and make any changes to the slide parameters to accommodate waiting to slide until after the next connection. Such flexible implementation avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the tool face before finishing the slide. During slides, slide planner 914 may provide some feedback as to the progress of achieving the desired goal of the current slide. In some embodiments, slide planner 914 may account for reactive torque in the drill string. More specifically, when rotating is occurring, there is a reactional torque wind up in drill string 146. When the rotating is stopped, drill string 146 unwinds, which changes tool face orientation and other parameters. When rotating is started again, drill string 146 starts to wind back up. Slide planner 914 may account for the reactional torque so that tool face references are maintained, rather than stopping rotation and then trying to adjust to a desired tool face orientation. While not all downhole tools may provide tool face orientation when rotating, using one that does supply such information for GCL 900 may significantly reduce the transition time from rotating to sliding.

In FIG. 9, convergence planner 916 receives internal inputs from build rate predictor 902, borehole estimator 906, and slide planner 914, and provides output to tactical solution planner 918. Convergence planner 916 is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well trajectory. The convergence plan represents a path from the current drill bit position to an achievable and desired convergence target point along the planned trajectory. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by slide planner 914. Convergence planner 916 may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to build rate predictor 902. The solution provided by convergence planner 916 defines a new trajectory solution for the current position of drill bit 148. The solution may be immediate without delay, or planned for implementation at a future time that is specified in advance.

In FIG. 9, tactical solution planner 918 receives internal inputs from geological drift estimator 912 and convergence planner 916 and provides external outputs representing information such as tool face orientation, differential pressure, and mud flow rate. Tactical solution planner 918 is configured to take the trajectory solution provided by convergence planner 916 and translate the solution into control parameters that can be used to control drilling rig 210. For example, tactical solution planner 918 may convert the solution into settings for control systems 522, 524, and 526 to accomplish the actual drilling based on the solution. Tactical solution planner 918 may also perform performance optimization to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by GCL 900 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole tool face. Accordingly, GCL 900 may receive information corresponding to the rotational position of the drill pipe on the surface. GCL 900 may use this surface positional information to calculate current and desired tool face orientations. These calculations may then be used to define control parameters for adjusting the top drive 140 to accomplish adjustments to the downhole tool face in order to steer the trajectory of borehole 106.

For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with GCL 900, or other functionality provided by steering control system 168. In GCL 900, a drilling model class may be defined to capture and define the drilling state throughout the drilling process. The drilling model class may include information obtained without delay. The drilling model class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a WOB/differential pressure model, a positional/rotary model, an MSE model, an active well plan, and control limits. The drilling model class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of GCL 900. The drill bit model may represent the current position and state of drill bit 148. The drill bit model may include a three dimensional (3D) position, a drill bit trajectory, BHA information, bit speed, and tool face (e.g., orientation information). The 3D position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination angle and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. The borehole model may include hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for current drilling of borehole 106. The borehole diameters may represent the diameters of borehole 106 as drilled over current drilling. The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents draw works or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active well plan represents the target borehole path and may include an external well plan and a modified well plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum RPMs to the defined level. The control output solution may represent the control parameters for drilling rig 210.

Each functional module of GCL 900 may have behavior encapsulated within a respective class definition. During a processing window, the individual functional modules may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the functional modules may be in the sequence of geo modified well planner 904, build rate predictor 902, slide estimator 908, borehole estimator 906, error vector calculator 910, slide planner 914, convergence planner 916, geological drift estimator 912, and tactical solution planner 918. It is noted that other sequences may be used in different implementations.

In FIG. 9, GCL 900 may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. While steering control system 168 may rely on timer and date calls driven by the programming environment, timing may be obtained from other sources than system time. In situations where it may be advantageous to manipulate the clock (e.g., for evaluation and testing), a programmable timer module may be used to alter the system time. For example, the programmable timer module may enable a default time set to the system time and a time scale of 1.0, may enable the system time of steering control system 168 to be manually set, may enable the time scale relative to the system time to be modified, or may enable periodic event time requests scaled to a requested time scale.

Referring now to FIG. 10, a block diagram illustrating selected elements of an embodiment of a controller 1000 for performing surface steering according to the present disclosure. In various embodiments, controller 1000 may represent an implementation of steering control system 168. In other embodiments, at least certain portions of controller 1000 may be used for control systems 510, 512, 514, 522, 524, and 526 (see FIG. 5).

In the embodiment depicted in FIG. 10, controller 1000 includes processor 1001 coupled via shared bus 1002 to storage media collectively identified as memory media 1010.

Controller 1000, as depicted in FIG. 10, further includes network adapter 1020 that interfaces controller 1000 to a network (not shown in FIG. 10). In embodiments suitable for use with user interfaces, controller 1000, as depicted in FIG. 10, may include peripheral adapter 1006, which provides connectivity for the use of input device 1008 and output device 1009. Input device 1008 may represent a device for user input, such as a keyboard or a mouse, or even a video camera. Output device 1009 may represent a device for providing signals or indications to a user, such as loudspeakers for generating audio signals.

Controller 1000 is shown in FIG. 10 including display adapter 1004 and further includes a display device 1005. Display adapter 1004 may interface shared bus 1002, or another bus, with an output port for one or more display devices, such as display device 1005. Display device 1005 may be implemented as a liquid crystal display screen, a computer monitor, a television, or the like. Display device 1005 may comply with a display standard for the corresponding type of display. Standards for computer monitors include analog standards such as video graphics array (VGA), extended graphics array (XGA), etc., or digital standards such as digital visual interface (DVI), definition multimedia interface (HDMI), among others. A television display may comply with standards such as NTSC (National Television System Committee), PAL (Phase Alternating Line), or another suitable standard. Display device 1005 may include an output device 1009, such as one or more integrated speakers to play audio content, or may include an input device 1008, such as a microphone or video camera.

In FIG. 10, memory media 1010 encompasses persistent and volatile media, fixed and removable media, and magnetic and semiconductor media. Memory media 1010 is operable to store instructions, data, or both. Memory media 1010 as shown includes sets or sequences of instructions 1024-2, namely, an operating system 1012 and surface steering control 1014. Operating system 1012 may be a UNIX or UNIX-like operating system, a Windows® family operating system, or another suitable operating system. Instructions 1024 may also reside, completely or at least partially, within processor 1001 during execution thereof. It is further noted that processor 1001 may be configured to receive instructions 1024A from instructions 1024-2 via shared bus 1002. In some embodiments, memory media 1010 is configured to store and provide executable instructions for executing GCL 900, as mentioned previously, among other methods and operations disclosed herein.

The systems and methods described above may be used together with systems and methods for planning one or more wells before drilling, planning a well path during drilling and/or updating that well plan and/or other well plans during the drilling of a well. Methods and systems for planning a field (comprising a plurality of wells to be drilled and/or a plurality of pads from each of which a plurality of wells are to be drilled), planning a pad (from which a plurality of wells are to be drilled), and planning a well both before and during drilling of the well are now described. As detailed below, it may be helpful to plan fields, pads, and wells before and during drilling so as to optimize the placement of each well in the earth relative to one or more other wells and relative to one or more geological zones so as to optimize production of hydrocarbons from the well and thereby optimize the return on investment of time and money. The systems and methods described below can be used to provide such benefits, including automatically updating one or more well plans based on information obtained during drilling of a well and/or automatically adjusting one or more drilling parameters or operations during drilling of a well based on information obtained during drilling of a well to optimize the expected production of hydrocarbons and thereby the return on investment.

In a further aspect, methods, and systems for iterative well planning for optimized results are disclosed. The disclosed methods and systems for iterative well planning for optimized results may provide various advantages and features. The disclosed methods and systems for iterative well planning for optimized results may define the geology as 3D cells of production probabilities, such that a high production probability may occur in the pay zone, while a lower production probability may occur in gas cut or water cut risk zones and may be zero outside the pay zone.

The disclosed methods and systems for iterative well planning for optimized results may define an expected drainage success based on a distance from the well and may combine the drainage success with the production amount likely from each cell to produce a Production Probability Percentages (PPP) for each well. A cell with a well nearby may have just the remaining PPP available after production has drained the nearby well. So, for two wells in close proximity to each other, the nearby well may have a greatly reduced PPP available. The consideration of PPP for adjacent or nearby wells may be used to improve well placement.

The disclosed methods and systems for iterative well planning for optimized results may calculate and display PPP and Time to Target (TTT) during a planning phase, and also during drilling without delay to inform decisions by drilling personnel, such as, but not limited to, a decision on when to trip to the surface. The inputs to TTT may include:

- Predicted torque and drag with estimated tortuosity from a reference well superimposed on the planned trajectory.
- Predicted optimal drilling parameters using an ROP model.
- Predicted slide/rotate sections to stay on plan including recovery curves.
- Accurately assessed slide and rotate curvatures.
- Predicted bit wear effects on ROP and anticipated trip time, when indicated.
- Predicted likelihood of NPT failures based on extrapolated tortuosity.

Starting with the assumption of a single BHA for the entire well, the disclosed methods and systems for iterative well planning for optimized results may find a design that minimizes tortuosity and assesses TTT for a planned well. Then, TTT may be reassessed assuming one trip for a bit change allowing a new more optimal BHA to be run for the second hole section. Further trips may be added until optimal TTT is achieved with expected drillable parameters.

The disclosed methods and systems for iterative well planning for optimized results may perform an automated adjustment of slot/target allocation, kick off depths, kick off rates, kick off directions, among various factors, to minimize collision risk (e.g., the risk that the well borehole will collide with an existing well borehole) in the initial plan.

The disclosed methods and systems for iterative well planning for optimized results may provide an algorithm to determine a direction to drill for maximum spacing between adjacent well trajectories. The algorithm to determine a direction to drill for maximum spacing may be used for iterative site planning after each well is drilled and certain adjustments for slot/target allocation and kick-off are made.

The disclosed methods and systems for iterative well planning for optimized results may provide a BHA stability index to determine the stability of BHA performance to allow like for like assessment of the sensitivity of any BHA design and select a BHA design that is expected to perform most consistently.

The disclosed methods and systems for iterative well planning for optimized results may enable an automated redesign of remaining wells on a pad to achieve maximum PPP and minimum TTT while remaining within the original lease boundaries. New azimuths and drain spacing may also be generated as a result of the redesign.

The disclosed methods and systems for iterative well planning for optimized results may use measured geological parameters including the true geometry encountered to optimize the design of the subsequent wells. The use of the measured geological parameters may include:

- Way points in the reservoir by step out, depth and thickness.
- Pressure, temperature, porosity, hardness, and friction factors. Pressure can inform casing design and hole section choices. Temperature can inform depth correction for accurate placement. Hardness and friction factors can inform ROP predictions. Porosity can inform production predictions.

The disclosed methods and systems for iterative well planning for optimized results may start with a tortuous well trajectory that results in a high PPP for the observed complex geometry of the reservoir encountered in the previous well. Then, the well trajectory may be incrementally smoothed to achieve a desired balance of PPP and TTT, such as based on torque and drag, NPT risk, and bit wear.

In some embodiments, a ‘balance’ between TTT and PPP may be generated as a numeric or quantitative factor for an evaluation, such as: well cost=TTT×(rig rate); and production gain=(overall PPP)×(asset value). For example, when an increase in well cost is less than about 10% of an increase in production gain, a change or alteration of drilling parameters, drilling equipment, the well trajectory, or various combinations thereof, may appear more justified. It is noted that the 10% increase in production gain is a non-limiting example, and that lower or higher values may be used in different embodiments.

Among other factors, success factors for a well being drilled, such as borehole 106, may include safety, cost, and production capacity. Typically, a well plan is initially produced to satisfy basic criteria that are based on certain assumptions, such as any one or more of the following assumptions:

- A kickoff depth for the well may be chosen based on an assumed depth at which curvature can be achieved in a stable geological formation.
- A kickoff direction for the well may be chosen based on an assumed safest direction to avoid collision with other wells.
- Nudge rates may be chosen based on an assumed torque and drag capacity of the drilling rig and any indication to create safe space under the pad.
- Build rates may be chosen based on an assumed hardness of the geological formation and the formation's ability to withstand grooving and the curvature capability of the drilling equipment.
- Hold sections may be chosen by hole cleaning considerations, final completion types such as electric submersible pump placement and any contingencies resulting from insufficient curvature when sliding
- Final build rates may be chosen based on an assumed balance between a so-called ‘production shadow’ (e.g., after the lateral kick off depth, as the build curve approaches the target reservoir depth) and the torque and drag generated by the curved well trajectory.
- Lateral section lengths may be chosen by lease line boundaries, assumed maximum pressure for successful circulation, and the ability to deliver WOB.
  
  However, the initial assumptions used at the start may be inaccurate and may lead to undesirable reductions in the operational efficiency of drilling the well.

The methods and systems for iterative well planning for optimized results disclosed herein may utilize certain technological improvements to provide an iterative method to generating a well plan for the well. For example, new algorithms have become available for numerically modelling the performance and behavior of BHA 149, as well as the performance and behavior of drill string 146. The algorithms may provide models based on the use of finite element analysis (FEA) models to determine a deflected shape of drill string 146 under the influences of weight, the flotation effect of the drilling fluid, WOB and any bend in the assembly that is constrained within the wellbore. From the FEA model results, the side forces at drill bit 148, and thus, the curvature of the wellbore, can be accurately predicted. Additionally, the ubiquity of cloud computing and high-speed networking has improved the ability to collect and process large amounts of data (e.g., “big data”) without delay, and has enabled more detailed and specific decisions to be made by personnel in the field, such as on drilling rig 210 that is drilling the well.

The methods and systems for iterative well planning for optimized results disclosed herein may incorporate various parameters that affect the Time to Target (TTT) and the Production Percentage Probability (PPP). The TTT and PPP parameters, along with actual measured data, may be used for the iterative well planning for optimized results disclosed herein. Due to the complex nature of the inputs and the modelling, including the estimation of the TTT and PPP parameters, certain individual decisions involved with attaining an optimal well plan that leads to an optimally drilled well may not be intuitive to a human operator, particularly during drilling of the well. Thus, the methods and systems for iterative well planning for optimized results disclosed herein may provide a user interface to inform the decisions of a human operator performing drilling of the well on drilling rig 210. The methods and systems for iterative well planning for optimized results disclosed herein may also enable an automated drilling system, such as steering control system 168, to optimally drill the well according to the well plan in an autonomous or semi-autonomous manner.

The methods and systems for iterative well planning for optimized results disclosed herein may be based on a well model that is capable of predicting TTT in order to minimize drilling time and, thus, to maximize production. For example, a perfectly drilled well aimed at the optimum production region in the reservoir with perfect drainage spacing from the well around could be considered an ideal goal, but such an idealized well may be expected to be very slow and expensive to drill. A slightly less than perfect well may therefore provide a more desirable overall economic result. Furthermore, the impact on production may also be considered during well planning.

In conventional well planning, any impact on production may often be ignored in view of the primary objective that appears sensible to the driller: to drill the well as cheaply as possible usually by drilling the well as quickly as possible. However, applying the fastest or the cheapest drilling operations for drilling the well may not be in the best interest of the well owner. For example, if drilling the well would have taken one extra day, but with the result that production from the well could have been extended over the life of the well (e.g., a useful production life of the well), such a consideration may lead to somewhat different choices for drilling that might not be apparent to personnel on the drilling rig.

In the methods and systems for iterative well planning for optimized results disclosed herein, the FEA models may rely on various information available such as friction factors, wellbore pressures, fluid types, BHA design, bit type, bit wear models, penetration rate models, rig trip times, survey information, expected production contours based on the reservoir model, and geological formation characteristics, among others, in order to predict an expected TTT, along with PPP. Thus, such modeling and prediction of drilling results, as disclosed herein, may demonstrate the economic advantages of allowing a greater investment for drilling (in terms of time and cost, and a slower TTT), in order to reap greater rewards with a higher PPP later in the production lifecycle of the well. For example, the investment in the well may be given by (rig time rate)*TTT, while the return on investment may be given by (recoverable asset value)*PPP. By considering the return on investment in the well during planning and drilling, in addition to the actual investment in the well, well planning and drilling decisions may be made with more complete information than by solely considering TTT during drilling and may result in an optimum balance between TTT and PPP, in order to maximize return on investment. For some low value wells, optimization based solely on TTT may provide an economically feasible solution. However, for higher value wells with larger potential paying target zones at stake, consideration of PPP may provide greater financial benefits than the savings from a fast TTT.

In the methods and systems for iterative well planning for optimized results disclosed herein, a computer implementation may receive the following information as input:

- An initial well trajectory design.
- Anticipated geological formations and their characteristics, such as locations, pressures, hardness, temperature and friction factors, pore pressures, fracture gradients, etc. Other formation characteristics may include a shape or an orientation, changes in dip, fault boundaries, and thicknesses.
- A BHA design and expected performance of the BHA design for each section of the wellbore. The BHA design may be an optimized BHA design that may be usable for drilling the entire well, as described above.
- Drill bit selections for each section of the wellbore.
- Production distribution in the payzone.
- Then during drilling, the following information may be measured by downhole sensors:
- Actual pressure and temperature.
- Actual location, shape, and 3-D geometry of the payzone formation.
- WOB.
- Downhole friction factors.
- Vibration and shock.
- Survey information along with current depth.
  
  In some implementations, survey information and current depth may be measured by dual sensor logging with a known distance between the sensors and matching formation response to determine how far drill bit 148 has actually travelled. In particular embodiments, the dual sensors may be about 20 feet apart along the BHA. As both sensors travel through the same formation, the signals from each of the sensors can be correlated with one another to calibrate actual measured depth and determine an actual distance that drill bit 148 has travelled. From the measured values, ROP can be measured and maximized as a formation-dependent function of WOB, fluid flow rate, and rotary drilling speed.

In the methods and systems for iterative well planning for optimized results disclosed herein, the output may be steering and drillstring control information to follow a planned well trajectory with the highest PPP and lowest TTT. Accordingly, the methods and systems for iterative well planning for optimized results disclosed herein may enable optimized drilling of the well, which may not be optimized drilling to achieve a fast delivery but may be optimized drilling to achieve the highest overall return on investment.

Referring now to FIG. 11, a rig control and exchange platform system 1100 (also known as a Blueprint system) is described according to the present disclosure. In general terms, The rig control and exchange platform system 1100 consists of a dynamic system to facilitate optimized drilling activities by monitoring a variety of different drill functions in some cases simultaneously. In one embodiment, the rig control and exchange platform system 1100 may comprise a computer system like controller 1000 shown in FIG. 10 and described above. Alternatively, the platform system 1100 may comprise one or more separate computers programmed to function as described in more detail below. In a traditional drilling operation, and as described elsewhere herein, various drilling systems often function independently of each other, for example including, road mapping, well planning, maintenance timing, and mud property detection (and others described further below). The rig control and exchange platform system 1100 can act as a central system to monitor and control drilling procedures by compiling data and system calculations of what would otherwise be independent operation systems. The function of the rig control and exchange platform system 1100 acts to optimize overall drilling function to increase automation of the drilling platform to decrease the need for user or operator adjustment, and to optimize the drilling process to be more efficient both in timing and cost. The rig control and exchange platform system 1100 can optionally be turned on and off by the drill operators, and for safety or manual adjustment the system can be turned off and replaced with traditional drilling operations.

In general, a standard drilling process has both a planning phase and a drilling and completion phase. Based on expected drilling conditions and geological formation information (often obtained from a number of sources, including nearby previously drilled wells, a plan can be created in advance of starting the drilling to create a drilling plan. Once drilling has started, an automated or semi-automated drilling plan can be executed according to the actual drilling conditions. As the drilling plan is performed, unexpected or differing conditions may require adjustment to the drilling plan. These variations from the drilling plan may be performed automatically or at least partially manually. The rig control and exchange platform system 1100 can allow for additional automation of the drilling parameters while compiling and measuring data from various sensors and relating to various types of information, including information about geological formations and/or the drilling systems. In this way, the rig control and exchange platform system 1100 can adjust to unexpected or differing conditions in real-time during drilling of the well. By compiling a wide range of data regarding the planned and actual drilling conditions, the rig control and exchange platform system 1100 can additionally provide increased communication between the drill rig system and the operators. For example, the rig control and exchange platform system 1100 can provide automated status reporting and/or alerts by email, text, or other similar systems. In addition, by the rig control and exchange platform system 1100 receiving and communicating a wide variety of data (which previously may have not been complied centrally) the rig control and exchange platform system 1100 may provide additional safety and accountability functions by identifying dangerous upcoming conditions, or record manual actions for later analysis and accountability recording.

In some embodiments, the rig control and exchange platform system 1100 acts as both a sensor receiver and controller. The rig control and exchange platform system 1100 can receive a drilling roadmap as well as historical information 1178, potentially based on GPS or other location information. Information on the condition of the drilling location can also include formation information 1182, such as top detection, lithology, bed dip, faults, and the like.

One feature of the rig control and exchange platform system 1100 is automation. The rig control and exchange platform system 1100 can be configured to automatically (or semi-automatically) adjust configurations for the equipment and/or its operation based on the data received from various drilling systems, including geosteering 1172, shaker vision (cutting status) 1168, and iterative well planning changes. Adjustments can also be made by the rig control and exchange platform system 1100 based on bottom hole detection characteristics that may be captured from machine vision systems. Further adjustments or adjustment recommendations can be made based on power generation and management from the rig site, including ESG/GHG generation. The rig control and exchange platform system 1100 can also receive data regarding formation top detection 1182 and associated BHA real-time updates. In the event of detection of drilling dysfunction or MSE calculations 1174, the rig control and exchange platform system 1100 can automatically (or semi-automatically) adjusting drilling parameters to cure or assist in fixing the dysfunction in the drilling system. In addition, regardless of dysfunction or out of normal conditions, the rig control and exchange platform system 1100 may also adjust drilling operation settings to maximize life of the BHA to finish a particular formation or reach a planned maintenance period. Such life maximization can be based both on historical and planned data or otherwise based on real-time experienced conditions.

In some aspects, the rig control and exchange platform system 1100 may monitor the location of the wellbore and its current direction to be drilled. In addition, the rig control and exchange platform system 1100 may adjust offset well information to reflect drilling tendencies. To further monitor drilling function, the rig control and exchange platform system 1100 may automatically adjust or record information from the iterative well planning software with inputs received from various drilling parameters.

In some aspects, the rig control and exchange platform system 1100 may monitor and control drilling air compressor parameters, such as flow, pressure, and soap injection. The rig control and exchange platform system 1100 may also monitor wellbore parasite line pressure and flow and adjust according to information received regarding wellbore conditions. The rig control and exchange platform system 1100 may also monitor the Blooie line for discharge and inform operators and/or make adjustments when a discharge is recorded to alert of cutting behavior changes.

In some aspects, the rig control and exchange platform system 1100 may automatically (or semi-automatically) turn on and off and/or control the operation of various machinery on the drilling rig as needed by the drill operation. For example, when the operators need to use hydraulic winches to pick up pipe, the rig control and exchange platform system 1100 may automatically turn on the winches and accompanying hydraulic power units to perform the task, and to shut off these systems when their use is no longer needed. By automating when these machines are turned on and off, unnecessary damage and power consumption can be avoided.

One feature of the rig control and exchange platform system 1100 can be increased visualization. This visualization may include visualization for offset historical, real-time, and adjacent rig or theoretical best case performance. In addition, the rig control and exchange platform system 1100 may visualize bottom hole detection 1166 including equivalent circulating density (ECD) and hole cleaning based on forms of cuttings tracking, including pressure while drilling (PWD), shaker vision 1168, and volumetric measurements. The visualization of the rig control and exchange platform system 1100 may include visualization of lithology and anticipated changes in conjunction with other data received or compiled by the rig control and exchange platform system 1100.

Another aspect of the rig control and exchange platform system 1100 is communication. By compiling and computing a variety of data measurements, and by being coupled to a plurality of rig control systems, the rig control and exchange platform system 1100 can generate automated status reports in either digital or paper format for review by drill control personnel or clients. These status reports may include current status information as well as forecasting (including 3D forecasting) of operating parameters includes zones and restricted areas. Restricted areas may include areas known from historical or planning data to require more aggressive drilling parameters or areas known for lost circulation.

An additional aspect of communication capability of the rig control and exchange platform system 1100 can include tracking all manual changes performed that differ from a computed plan generated by the rig control and exchange platform system 1100 or other automation control system. The rig control and exchange platform system 1100 can further compute a rating to quantify the accuracy of the automated or human compliance with the rig control and exchange platform system 1100 plan. Such a rating can give an indication of the success of the drilling operation and compliance with desired outcomes.

A further communication aspect of the rig control and exchange platform system 1100 is recording, organizing, and scheduling events in a particular drill operation. This aspect can allow important events of a drilling operation to be input into a calendar or planning organization system so that managers and other personnel who are monitoring the drilling operation to monitor status and future potential issues or challenges.

The rig control and exchange platform system 1100 may also have a social media function, which allows various personnel or drill operators to communicate with one another regarding the successes or failures of a drilling operation. This function may allow nearby drill operators to engage with one another about progress on a particular project. Such a function can increase morale and encourage competition between drill operators to have a successful performance.

Another aspect of the rig control and exchange platform system 1100 is safety. One aspect of safety may include common-sense restrictions on what manual inputs to drilling control systems may be provided by drill operators, such as provided ranges of which various drill functions can operate, as well as providing pre-set or other automatically determined limits on drilling operations. To ensure safe performance, the rig control and exchange platform system 1100 may include settings to control who has access to certain control parameters, and arbitration rules in the event that multiple inputs are received from different sources (e.g., two drill operators simultaneously) to ensure that one input takes precedence over the other(s). In the functionality of who has the authority to perform overrides or other changes to the planned drill functions, the rig control and exchange platform system 1100 may allow adjustment of certain parameters without approval of a manager or other authorized user. Such limits may be based on which parameter is being adjusted and/or to what amount or percentage the parameter is being changed. For example, a particular user may be able to adjust the WOB only a certain percentage (i.e., 10%) before additional authorization or approval is required. Another aspect of safety controls of the rig control and exchange platform system 1100 is a “safe mode” set of parameters, which can act to revert systems to known safe parameters in event of a system failure, such as power failure.

Safety can also be increased with the rig control and exchange platform system 1100 by having default changes to the system or various alerts to drill personnel in the event of detection of dangerous conditions. Dangerous conditions may include, for example, rough drilling 1136, gas detection 1140 (such as hydrogen sulfide), engine data 1132, or managed pressure drilling (MPD) mud properties 1138. One such potentially dangerous condition to be actively monitored by the rig control and exchange platform system 1100 may be pore pressure, in which the rig control and exchange platform system 1100 may adjust operating parameters in response to well pressure, including equivalent circulating density (ECD) parameters to minimize or prevent break down of the formation or to avoid additional influx of hydrocarbons into the wellbore, (sometimes called a “kick”).

In some embodiments, the rig control and exchange platform system 1100 may allow for additional oversight modes so that onsite or remote team personnel can be alerted and increase engagement in the drilling operation when certain high risk or unsafe conditions are experienced in the drilling system. Such monitoring may include the presentation of information to the drill operators of trouble spots having high drag or lost circulation and performing updates to the drill plan in response to such recorded safety concerns. The rig control and exchange platform system 1100 may also monitor, using visual or other sensors on the drill rig, the lack of suitable personal protection equipment (PPE) based on current dangerous or heightened safety risk conditions in the drilling operation. In addition, the rig control and exchange platform system 1100 may restrict the ability of a certain change to the drilling operation to only circumstances where it is recognized that certain personnel are located in the vicinity to the rig floor. The system 1100 also may receive and monitor weather and other conditions and may use such information to predict potentially unsafe conditions (e.g., frostbite from cold, heat stroke from heat, tornadoes, hail, lightning, etc.).

In another aspect, the rig control and exchange platform system 1100 may monitor and control the mud control system. The rig control and exchange platform system 1100 may monitor and predict necessary mud weight and mud properties and make changes or suggestions to the mud control system accordingly. This may particularly be used in situations where there is a pending change in the formation being drilled or when other drilling parameters are also being changed for a change in drilling conditions. Such adjustment may go beyond changing the mud parameters and may include changes to the drilling parameters (such as drill speed) based on encountered mud conditions to avoid damage to machinery or to the formation. Where mud conditions are detected, the rig control and exchange platform system 1100 may make changes or suggest changes, such as activating the addition of Teflon beads or other additives to the well in anticipation of upcoming or current sliding conditions. Similarly, the rig control and exchange platform system 1100 may suggest or activate the addition of materials to the mud or more mud to address loss circulation material (LCM) in anticipation or reaction to a loss of drilling mud.

The rig control and exchange platform system 1100 may also make recommendations or changes in response to inputs related to hole cleaning status. For example, adjustments can be made to increase flow and slow down the drilling operation to avoid sticking or to verify proper bit cleaning and cooling. This can be beneficial to predict and plan for a necessary cleaning or cleanup cycle.

In another aspect, the rig control and exchange platform system 1100 can be utilized for logistics planning and scheduling. Based for example on real time updates, the rig control and exchange platform system 1100 can automate (or semi-automate) the timing of scheduling or requesting of drilling operations and/or events, such as ordering of cement trucks, ordering a BHA, or other processes of the drilling operation. In addition, when the rig control and exchange platform system 1100 determines that certain events, such as a cement truck being available, have not yet occurred, corresponding changes can be made to the drilling parameters to ensure that proper timing is restored. For example, if casing of the drill site is soon going to be necessary and a cement truck is not yet available, the rig control and exchange platform system 1100 can suggest or implement changes to slow down the drilling operation until a cement truck is available for casing.

In other aspects, the rig control and exchange platform system 1100 can be configured to optimize the timings of various maintenance operations and scheduled downtime. This automation can allow for down time cycles of various systems to be scheduled concurrently or sequentially such that when the drilling operation is changed to perform maintenance or cleaning that other necessary or forecasted maintenance items can be strategically scheduled to be performed simultaneously for minimized downtime and increased efficiency.

In further aspects, the rig control and exchange platform system 1100 can monitor, schedule, and/or manage workflow and crew presence at the drill site. The rig control and exchange platform system 1100 can be configured to track current crew presence and tasks being performed by the crew. In addition, based on the rig control and exchange platform system 1100 developed plan, including necessary upcoming tasks, the rig control and exchange platform system 1100 can manage crew rotations and number of necessary crew members at a certain time. This can include the scheduling of roaming crews according to the rig status, for example by increasing crew size and/or availability when critical or high risk functions are being performed.

In other aspects, the rig control and exchange platform system 1100 can actively monitor and control power generation. Such power control operations can be utilized to ensure that sufficient power is generated to respond to upcoming or current events taking place at the drill site. In addition, the rig control and exchange platform system 1100 can adjust power generation to improve fuel efficiency to avoid wasted or unused power. In determining how much power is to be used based on drilling operations, the rig control and exchange platform system 1100 can further provide feedback and system information to users to appreciate the tradeoffs in drilling speed and performance in comparison to fuel economy, optionally including feedback to the drill operators in the energy consumption changes that will result from adjustments to drilling parameters and associated cost tradeoffs.

Another aspect of power draw which may be controlled or monitored with the rig control and exchange platform system 1100 is battery recharging rate and function. The rig control and exchange platform system 1100 may be configured to monitor and/or control recharge rate of the rig batteries based on upcoming need for power. In circumstances where there is a requirement for additional power, and no time for optimized charging rates, the rig control and exchange platform system 1100 may suggest and/or implement a change from optimized smart charging to more rapid (less efficient) charging to meet the expected needs of the drilling operation. Such changes may be adjusted to optimize or preserve battery life.

Referring now to FIG. 12, a Personnel Video Monitoring system, “PVM” 1200 according to the present disclosure is illustrated. In various embodiments, the PVM 1200 consists of several parts. The PVM 1200 may include multiple individual cameras 1202 (which may provide still or video images), each of which may or may not view the same region, and each of which may have been calibrated so its location and pose relative to the other cameras 1202 is known. Each camera 1202 may contain or be connected to a computer 1206 which performs person detection on the scene viewed by that camera 1202 and may generate a “bounding box” (or other additional information) for each person 1201 in each frame. Each camera 1202 may transmit each bounding box to a central computing resource 1206, which aggregates possible person 1201 locations across all of the cameras 1202 (using each camera's bounding boxes, location, and pose information) to estimate actual person 1201 locations via triangulation, and false-alarm rejection. This process results in a final list of person 1201 coordinates in 2- or 3-Dimensions. The resulting information about person 1201 locations may then be presented to the end-user on a 2- or 3-D visualization of the environment, with specific icons representing each person's 1201 location or provided to machinery control systems 1208 to cause or inhibit certain automated activities. These automated activities often involve the automated movement of mechanical equipment 1212 which is capable of injuring a person 1201 who is in the vicinity. Examples of such equipment 1212 could be pipe conveyors, cranes, hoists, pumps, drilling equipment, carts, sleds, elevators, winches, top drives, industrial equipment, and many others.

For calibration, any number of fiducial objects with known X, Y, and Z locations can be used within the scene. Typical fiducial objects include a grid of black and white squares, or 3-dimensional objects with multiple distinctly colored parts. Alternatively, calibration can be accomplished with pre-existing fiducials in the scene (e.g., known locations of machinery). Points on these fiducials may be detected automatically, or manually identified (by clicking) in each camera view. Calibration can then proceed using any of a number of camera parameter optimization systems and methods (e.g., linear or non-linear least-squares, batch-least-squares, etc.).

Any of a number of person detection algorithms can be utilized on a per-camera basis (e.g., Histogram of Oriented Gradients (HOG) or Incremental Conic Functions (ICF)). Different algorithms provide different performances in terms of probability of detecting a person as well as probability of generating a bounding box when no person is present. Each approach also provides different sensitivities to lighting and occlusion and different algorithms have different computational requirements. As a result, the choice of person detection algorithm can be accomplished on a per-installation basis.

Person detections may consist of a “bounding box” surrounding the person in each frame, as well as additional information (e.g., the index of the current camera with the detection, features extracted from the image around the person, the raw red-green-blue (RGB) data inside and immediately surrounding the bounding box, the time and frame number of the person detection, other meta-data, as well as various other parameters estimated during the person detection process).

Person detection data (bounding boxes, RGB color data, or associated meta-data) may be transferred to the central tracking computer 1206 using TCP/IP, UDP, or any other suitable data transfer protocol.

Person detections can be aggregated temporally within a camera 1202 to reduce false alarms and improve the probability of detection by keeping track of person detection confidences over time within a camera view. This can prevent spurious false alarms and help to improve detection of difficult-to-see persons.

The bounding box from each camera 1202 may be combined with the information about each camera's pose and location to provide a global coordinate estimate of the person's location using either bearing-only or joint bearing-and-range-based triangulation.

For horizontally oriented cameras 1202, the only information about a person's distance from the camera is due to the height of the detected bounding box. This information may be combined with the bounding box location to estimate both a distance and a scale, though the box height is often too noisy to provide robust range estimation.

For cameras 1202 oriented somewhat vertically with respect to the horizon, person range can be estimated using the centroid of the person's bounding-box, and assuming that the mid-point of the person is in some reasonable range (e.g., waistline is above 24 inches and below 50 inches), which enables joint bearings (angle) and range measurements.

The bearings and range information from each camera 1202 may then be superimposed on a grid-representation of the area under consideration. This grid may take the form of a 2-D matrix of points, where each point represents a square region with nominal side length (e.g., 2 inches, 6 inches, 1 foot) (the grid can be adaptively re-sized to account for additional cameras or to increase processing speed). Each detection from each camera 1202 counts as a “vote” into all of the grid squares within a given distance of the line segment generated by projecting the bounding box centroid into the plan-view. Votes are aggregated across all the cameras 1202 and all the detections. The resulting vote plan-view may be smoothed using a Gaussian filter whose size is proportional to the expected size of persons in the scene. This smoothed image represents the spatial confidence map for person locations in the current frame.

The resulting current time spatial confidence map, c(t), is combined with the confidence map from the previous frame, c(t−1), in an IIR manner, to form the final confidence map, C(t). e.g.,

C(t)=ac(t)+(1−a)c(t−1),

where a.di-elect cons.[0,1] is chosen to provide adequate tradeoffs between fast adaptation (large a) and false alarm reduction (small a).

The final confidence map, C(t), is then transformed into discrete person locations using local maxima of the 2- or 3-D surface. Consistent person identification may be accomplished using Kalman filtering on the resulting discrete person locations over time, where the identity of each person is attached to the most likely current local maxima given the prediction of the Kalman filter. Persons can appear and be removed from the scene when the likelihood of their track is reduced below a threshold. Other tracking algorithms can be used in place of the Kalman filter, including particle filters, Markov chain Monte Carlo (MCMC) tracking approaches, and others.

Various ad-hoc parameters are used to enhance the person detection and tracking. For example, realistic human motion is highly constrained (persons are extremely unlikely to move faster than 40 km/h, or about 11 m/s). These velocity constraints can therefore be leveraged in the tracking by invalidating any human track that involves jumps in excess of ⅓ meters per frame (in a 30 Hz video), for example.

Persistent clutter (objects in the scene that cause person-detectors to “false alarm”) can pose a serious problem for accurate person tracking and localization. In the case of static background objects, performance may be significantly improved by incorporating either change-detection (via adaptive Gaussian Mixture Models), or static clutter rejection systems and methods (by training a person detection classifier to reject instances of the static background under consideration). These options are available at the user's specification and may be accessible from the main graphical user interface.

Determining when a new person has entered or left the scene can be accomplished in a number of ways. As discussed above, persons can be removed from the scene when the likelihood of their track has decreased below a certain level, or no person detections in any camera corresponding to that person have occurred in a given time. Person birth/death processes can also take into account egress and ingress points on the spatial rig representation. For example, persons may be expected to enter and exit the spatial map near doors, or stairwells, but are unlikely to disappear from the scene when standing in the middle of the room. These regions are used in the person tracking/birth/death processing and may be set by the user through the graphical user interface.

A graphical user interface (GUI) may enable the end-user to visualize the resulting person locations in the individual video streams, as well as in a 2- or 3-D representation of the space. A preferred embodiment of a GUI may consist of several parts, including a row of video feeds from each camera in the PVM system 1200. These images may be “clickable.” Clicking any video stream changes the main video visualization to correspond to that camera. This action makes the camera selected the “active camera.”

A GUI may also include a main video visualization showing the video from the active camera. Each video may be enhanced by drawing the detected bounding boxes for all person detections, as well as ellipses representing the person's estimated location projected onto the ground. The ellipses are generated by projecting a fixed-radius circle around each person location onto the ground plane using the camera parameters. Each circle on each detected person is assigned a color, and the color-to-person relationship is maintained throughout the video (e.g., the person with the green circle will always be represented by a green circle). The radius, thickness, and transparency of each person identification circle is proportional to the certainty with which that person is currently localized. As a person leaves a scene, or is occluded, the circle corresponding to their location will increase in size, decrease in thickness, and increase in transparency, until it disappears, and the person is “lost.”

A plan-view or 3-D map of the area under surveillance may show the locations of the persons in world-coordinates, as well as the locations of the cameras. Persons are represented as simplified icons and the colors in the map may be chosen to match the circles drawn around each person in the main frame. In the plan-view visualization, the active camera is identified by changing its color (e.g., the active camera icon may be red while the other camera icons are black).

The GUI may also include various options for saving, loading, exporting, starting, stopping, and changing parameters of the UI.

In addition, depending on needs, the outputs of the person localization information may be coupled into Supervisory Control and Data Acquisition (SCADA) control systems, and utilized to either raise an alarm 1210 if a person is in close proximity to moving equipment, or to inhibit automated actions when a person is in too close proximity to the equipment.

In FIG. 12, cameras 1202 are mounted with arbitrary pan, tilt and/or zoom settings in arbitrary locations around the scene to be surveyed. In a preferred embodiment, at least three cameras 1202 should be able to “view” each spatial location where people 1201 should be tracked and personnel at the maximum distance in each camera 1202 view should be at least 64 pixels in height. Complete overlap between camera 1202 views is not necessary as long as at least three cameras 1202 are able to view each spatial location where people should be tracked. Given enough cameras 1202 can view completely different regions. These cameras 1202 are connected to processor 1206 which is configured to monitor the location of the personnel 1201 as discussed. Processor 1206 is also connected to machinery control system 1208 which is configured to initiate or interrupt any automated actions of equipment 1212 based on the location of the personnel 1201.

Referring now to FIG. 13, the Rig State Estimation system (RSE) 1300 is illustrated. RSE 1300 may contain several parts including a model of rig state not as a single discrete “state” that can be entered and exited from, but as a collection of facts about a rig that may be estimated and updated in real-time. In addition to multiple sensors 1320, which may provide information such as measured surface readings or down-well measurements, RSE 1300 uses computer vision and machine learning algorithms specifically designed to estimate the rig state from cameras 1302. The resulting information about rig state may then be incorporated into a display, along with other relevant pieces of information (e.g., video frames) and the state information is used to improve algorithm performance by altering the relative importance of the variables under consideration and other algorithm-level modifications. The information may also be used to form time and motion (T&M) databases 1312 and reports, and to annotate the collected video with relevant T&M information. This would allow, for example, someone to immediately jump to all the instances of “roughneck engaged” or “adding barite to the pits” in a video feed. The information can help identify and flag uncommon events, presenting information about these events to the end-user in plain English. It may also be used to automate and generally improve rig behaviors. As a result, total rig performance may be significantly enhanced.

Classical estimates of rig “state” utilize a finite-set of discrete states corresponding to large-scale rig behavior, e.g., “Drilling,” “Pulling Out Of Hole,” “Out Of Hole,” “Running Into Hole,” etc. While these kinds of state models are useful when the number of states is small and can be easily described, in reality, the “state” of a rig is determined by at least dozens of interacting activities and behaviors. Complete enumeration of all of the possible combinations of activities and learning the probabilities of transitioning between all the states is typically intractable.

The rig state may consist entirely of binary valued variables, but a state may also include discrete variables having multiple possible values (e.g., the number of pipe-stands in the well), as well as real-valued states (e.g., hole depth).

Estimating rig state as a number of discrete variables has a number of benefits over classical state estimation and tracking, for example, to account for all the various rig behaviors in a classical system requires an exponentially increasing number of discrete states, and an even larger number of inter-state transition probabilities.

Depending on the state specification, different algorithms making use of different data sources are implemented to detect different relative variables. These algorithms use features from the relevant sensor data, together with machine learning algorithms for decision making. For example, to determine whether the rig state is “pulling out of hole” an algorithm could utilize information from:

- the recent changes in bit depth and current hole depth,
- video of the pipe-stand, and pipe tracking outputs, and/or
- recent or ongoing roughneck engaged/disengaged measures.

Information from each of these sensing modalities may be extracted using feature extraction approaches to generate low-dimensional, information bearing representations of the data. Low-level or quickly changing states that are likely to occur in a repeated sequence can be further aggregated into temporal models of likely behaviors within each larger state.

Throughout processing, each video camera 1302 may incorporate human detection and tracking processing to identify the locations of people on the rig, flag any important occlusions (e.g., someone is blocking the camera's view of the drill hole), and/or record a person's motion and activities. These activities may then be utilized in automated time and materials reporting.

Information from the estimated rig state is also provided to systems for the identification of uncommon or potentially dangerous state transitions and automated rig control systems (discussed below). Information about the global rig state may then be directly utilized in improving automated alarm generation systems. For example, information that there is barite added to the pits is used to change the influx detection system to ignore pit volume measurements for the time being. Similarly, information about the states “pipe static” and/or “pumps off” indicates that any positive change in flow-out and pit-volume may be highly indicative of down-well influx, since no other activities should be influencing those measurements.

In addition to altering real-time processing and generally improving rig operations, computer vision based rig state detection and personnel tracking may also be used to automatically annotate visual data (still or video) as it is collected, along with the rig state, number of persons in scene, and other relevant sensor information. This processing may automatically add additional information to be attached to the video stream, to enable fast searching for discrete events (e.g., “show me every instance where tripping out of hole took more than 20 minutes but hole depth was less than 2000 ft”), which is currently intractable and extremely time-consuming with existing software. Embodiments of the system may show a prototype state visualization tool and sample frames from each “pipe-pulled” event found in the video. Each of these frames may provide a direct link to the corresponding point in the video.

Each state-vector is recorded as a function of time and/or as part of a relational database (or other suitable software, e.g., a spreadsheet). These state-vector data sets are then used to automatically generate reports and are made available to T&M analysts after data is collected. These data sets enable automatic searching over massive amounts of video that has been automatically tagged with T&M relevant information. For example, this enables identification of all events of type Y that took more than M minutes across all wells and rigs, using only already collected video and sensor data. This represents a large time savings and increase in the power and efficiency of T&M reporting. Data mining can be used to identify actions/events that have the most delays, or that occur most commonly, etc.

Each camera 1302 may also keep track of all people in the scene using automated person-detection algorithms. When multiple cameras are viewing the same region, person locations can be estimated and provided as part of the automated T&M reporting and database—e.g., “Person 1 detected at location (x1,y1), Person 2 detected at location (x2,y2).” Persons may be automatically anonymized by blurring of the pixels containing detected persons for privacy and reporting reasons.

By aggregating states into larger-picture states, or considering small sub-sets of states only it is possible to accurately enumerate likely and dangerous transition probabilities by incorporating a priori expert information about realistic state transitions and state transitions that should be rare or impossible (e.g., a transition from “drilling” directly to “out of hole” most likely indicates a sensor failure or error, other transitions may indicate dangerous or environmentally unsafe behaviors or situations).

Information from the computer vision and additional sensor state estimation systems and methods may also be used to determine appropriate rig control actions and automate rig behaviors and other processes through a supervisory control and data acquisition (“SCADA”) control system.

FIG. 13 shows one embodiment of the disclosed system in which multiple cameras 1302 may be used to monitor various aspects of the rig state. The cameras 1302 are operably connected to a processor 1310. In this particular embodiment, the processor 1310 is operably connected to a database 1312, alarm 1314, machinery control system 1316 and sensor 1320. In related embodiments one, some or all of these devices may be operably connected to the processor 1310. Additionally, other embodiments may include, for example, multiple sensors 1320.

Referring now to FIG. 14, an example of a rotary steerable BHA 149A and different methods of drill string and drill bit rotation is depicted. It is noted that the drawing in FIG. 14 is a schematic illustration and may not be drawn to scale or perspective.

In FIG. 14, drill string 146 is shown at a terminal portion relative to a surface direction 1406 and having a drill string axis 1408 in proximity to rotary steerable BHA 149A. Drill string 146 accordingly is enabled to rotate about drill string axis 1408 under power from top drive 140 (not shown in FIG. 14; see FIG. 1), as indicated by an angular velocity arrow 1410 representing an angular velocity (e.g., alpha) of drill string 146. Furthermore, rotary steerable BHA 149A is shown coupled to drill string 146 by means of a collar 1412, which may represent any type of generic threaded coupling.

In FIG. 14, an example of a drill string and drill bit rotation 1400 is shown with rotary steerable BHA 149A in a fixed angle configuration, similar to a bent sub. Accordingly, rotary steerable BHA 149A is shown including mechanism 1422 configured for bent sub functionality having a vertex 1424 along drill string axis 1408 and having an angle .theta. deflection about vertex 1424. As a result, drill bit 148 is coupled to mechanism 1422 along a drill bit axis 1428 that is deflected at angle .theta. from drill string axis 1408. In the fixed angle configuration of drill string and drill bit rotation 1400, drill string 148 does not rotate about drill bit axis 1428, but rather, angle .theta. rotates along with drill string 146 about drill string axis 1408, causing drill bit 148 to also rotate about drill string axis 1408, but in the fixed angle configuration with a fixed deflection of angle .theta., resulting in a larger diameter of borehole 106.

In drill string and drill bit rotation 1400 of FIG. 14, the source of rotational power in drill string and drill bit rotation 1400 of FIG. 14 is top drive 140. Accordingly, in drill string and drill bit rotation 1400, rotary steerable BHA 149A may transmit control indications generated during drill string and drill bit rotation 1400 to steering control system 168, which may receive the control indication and may control top drive 140 and mud pump 152 (as included in a mud circulation system) to control the rotational speed of drill bit 148. In some embodiments, steering control system 168 may also communicate with rotary steerable BHA 149A, such as to instruct rotary steerable BHA 149A to modify angle .theta., as desired.

Referring to FIG. 15, one embodiment of an environment 1500 illustrates multiple communication channels (indicated by arrows) that are commonly used in existing directional drilling. The communication channels couple various individuals involved in the drilling process. The communication channels may support telephone calls, emails, text messages, faxes, data transfers (e.g., file transfers over networks), and other types of communications.

The individuals involved in the drilling process may include a drilling engineer 1502, a geologist 1504, a directional driller 1506, a tool pusher 1508, a driller 1510, and a rig floor crew 1512. One or more company representatives (e.g., company men) 1514 may also be involved. The individuals may be employed by different organizations, which can further complicate the communication process. For example, the drilling engineer 1502, geologist 1504, and company man 1514 may work for an operator, the directional driller 1506 may work for a directional drilling service provider, and the tool pusher 1508, driller 1510, and rig floor crew 1512 may work for a rig service provider.

The drilling engineer 1502 and geologist 1504 are often located at a location remote from the drilling rig (e.g., in a home office/drilling hub). The drilling engineer 1502 may develop a well plan 1518 and may make drilling decisions based on drilling rig information. The geologist 1504 may perform such tasks as formation analysis based on seismic, gamma, and other data. The directional driller 1506 is generally located at the drilling rig and provides instructions to the driller 1510 based on the current well plan and feedback from the drilling engineer 1502. The driller 1510 handles the actual drilling operations and may rely on the rig floor crew 1512 for certain tasks. The tool pusher 1508 may be in charge of managing the entire drilling rig and its operation.

The following is one possible example of a communication process within the environment 1500, although it is understood that many communication processes may be used. The use of a particular communication process may depend on such factors as the level of control maintained by various groups within the process, how strictly communication channels are enforced, and similar factors. In the present example, the directional driller 1506 uses the well plan 1518 to provide drilling instructions to the driller 1510. The driller 1510 controls the drilling using control systems such as the control systems 522, 524, and 526 of FIG. 5. During drilling, information from sensor equipment such as downhole MWD equipment 1516 and/or rig sensors 1520 may indicate that a formation layer has been reached twenty feet higher than expected by the geologist 1504. This information is passed back to the drilling engineer 1502 and/or geologist 1504 through the company man 1514 and may pass through the directional driller 1506 before reaching the company man 1514.

The drilling engineer 1502/well planner (not shown), either alone or in conjunction with the geologist 1506, may modify the well plan 1518 or make other decisions based on the received information. The modified well plan and/or other decisions may or may not be passed through the company man 1514 to the directional driller 1506, who then tells the driller 1510 how to drill. The driller 1510 may modify equipment settings (e.g., toolface orientation) and, if needed, pass orders on to the rig floor crew 1512. For example, a change in WOB may be performed by the driller 1510 changing a setting, while a bit trip may require the involvement of the rig floor crew 1512. Accordingly, the level of involvement of different individuals may vary depending on the nature of the decision to be made and the task to be performed. The proceeding example may be more complex than described. Multiple intermediate individuals may be involved and, depending on the communication chain, some instructions may be passed through the tool pusher 1508.

The environment 1500 presents many opportunities for communication breakdowns as information is passed through the various communication channels, particularly given the varying types of communication that may be used. For example, verbal communications via phone may be misunderstood and, unless recorded, provide no record of what was said. Furthermore, accountability may be difficult or impossible to enforce as someone may provide an authorization but deny it or claim that they meant something else. Without a record of the information passing through the various channels and the authorizations used to approve changes in the drilling process, communication breakdowns can be difficult to trace and address. As many of the communication channels illustrated in FIG. 15 pass information through an individual to other individuals (e.g., an individual may serve as an information conduit between two or more other individuals), the risk of breakdown increases due to the possibility that errors may be introduced in the information.

Even if everyone involved does their part, drilling mistakes may be amplified while waiting for an answer. For example, a message may be sent to the geologist 1506 that a formation layer seems to be higher than expected, but the geologist 1506 may be asleep. Drilling may continue while waiting for the geologist 1506 and the continued drilling may amplify the error. Such errors can cost hundreds of thousands or millions of dollars. However, the environment 1500 provides no way to determine if the geologist 1504 has received the message and no way to easily notify the geologist 1504 or to contact someone else when there is no response within a defined period of time. Even if alternate contacts are available, such communications may be cumbersome and there may be difficulty in providing all the information that the alternate would need for a decision.

Referring to FIG. 16, one embodiment of an environment 1600 illustrates communication channels that may exist in a directional drilling operation having the benefit of the surface steerable system 1618. In the present example, the surface steerable system 1618 includes the drilling hub 1616, which includes the regional database 328 of FIG. 3 and processing unit(s) 1604 (e.g., computers). The drilling hub 1616 also includes communication interfaces (e.g., web portals) 1606 that may be accessed by computing devices capable of wireless and/or wireline communications, including desktop computers, laptops, tablets, smart phones, and personal digital assistants (PDAs). The on-site controller 344 includes one or more local databases 1610 (where “local” is from the perspective of the on-site controller 344) and processing unit(s) 1612.

The drilling hub 1616 is remote from the on-site controller 344, and various individuals associated with the drilling operation interact either through the drilling hub 1616 or through the on-site controller 344. In some embodiments, an individual may access the drilling project through both the drilling hub 1616 and on-site controller 344. For example, the directional driller 1506 may use the drilling hub 1616 when not at the drilling site and may use the on-site controller 344 when at the drilling site.

The drilling engineer 1502 and geologist 1504 may access the surface steerable system 1618 remotely via the portal 1606 and set various parameters such as rig limit controls. Other actions may also be supported, such as granting approval to a request by the directional driller 1506 to deviate from the well plan and evaluating the performance of the drilling operation. The directional driller 1506 may be located either at the drilling rig 210 or off-site. Being off-site (e.g., at the drilling hub 1616 or elsewhere) enables a single directional driller to monitor multiple drilling rigs. When off-site, the directional driller 1506 may access the surface steerable system 1618 via the portal 1606. When on-site, the directional driller 1506 may access the surface steerable system via the on-site controller 344.

The driller 1510 may get instructions via the on-site controller 344, thereby lessening the possibly of miscommunication and ensuring that the instructions were received. Although the tool pusher 1508, rig floor crew 1512, and company man 1514 are shown communicating via the driller 1510, it is understood that they may also have access to the on-site controller 344. Other individuals, such as a MWD hand 1608, may access the surface steerable system 1618 via the drilling hub 1616, the on-site controller 344, and/or an individual such as the driller 1510.

As illustrated in FIG. 16, many of the individuals involved in a drilling operation may interact through the surface steerable system 1618. This enables information to be tracked as it is handled by the various individuals involved in a particular decision. For example, the surface steerable system 1618 may track which individual submitted information (or whether information was submitted automatically), who viewed the information, who made decisions, when such events occurred, and similar information-based issues. This provides a complete record of how particular information propagated through the surface steerable system 1618 and resulted in a particular drilling decision. This also provides revision tracking as changes in the well plan occur, which in turn enables entire decision chains to be reviewed. Such reviews may lead to improved decision making processes and more efficient responses to problems as they occur.

In some embodiments, documentation produced using the surface steerable system 1618 may be synchronized and/or merged with other documentation, such as that produced by third party systems such as the WellView product produced by Peloton Computer Enterprises Ltd. of Calgary, Canada. In such embodiments, the documents, database files, and other information produced by the surface steerable system 1618 is synchronized to avoid such issues as redundancy, mismatched file versions, and other complications that may occur in projects where large numbers of documents are produced, edited, and transmitted by a relatively large number of people.

The surface steerable system 1618 may also impose mandatory information formats and other constraints to ensure that predefined criteria are met. For example, an electronic form provided by the surface steerable system 1618 in response to a request for authorization may require that some fields are filled out prior to submission. This ensures that the decision maker has the relevant information prior to making the decision. If the information for a required field is not available, the surface steerable system 1618 may require an explanation to be entered for why the information is not available (e.g., sensor failure). Accordingly, a level of uniformity may be imposed by the surface steerable system 1618, while exceptions may be defined to enable the surface steerable system 1618 to handle various scenarios.

The surface steerable system 1618 may also send alerts (e.g., email or text alerts) to notify one or more individuals of a particular problem, and the recipient list may be customized based on the problem. Furthermore, contact information may be time-based, so the surface steerable system 1618 may know when a particular individual is available. In such situations, the surface steerable system 1618 may automatically attempt to communicate with an available contact rather than waiting for a response from a contact that is likely not available.

As described previously, the surface steerable system 1618 may present a customizable display of various drilling processes and information for a particular individual involved in the drilling process. For example, the drilling engineer 1502 may see a display that presents information relevant to the drilling engineer's tasks, and the geologist 1504 may see a different display that includes additional and/or more detailed formation information. This customization enables each individual to receive information needed for their particular role in the drilling process while minimizing or eliminating unnecessary information.

Referring to FIG. 17, one embodiment of an environment 1700 illustrates data flow that may be supported by the surface steerable system 1618 of FIG. 16. The data flow 1700 begins at block 1702 and may move through two branches, although some blocks in a branch may not occur before other blocks in the other branch. One branch involves the drilling hub 1616 and the other branch involves the on-site controller 344 at the drilling rig 210.

In block 1704, a geological survey is performed. The survey results are reviewed by the geologist 1504 and a formation report 1706 is produced. The formation report 1706 details formation layers, rock type, layer thickness, layer depth, bit depth, faults, and similar information that may be used to develop a well plan. In block 1708, a well plan is developed by a well planner 1724 and/or the drilling engineer 1502 based on the formation report and information from the regional database 328 at the drilling hub 1616. Block 1708 may include selection of a BHA and the setting of control limits for various drilling operations and equipment. The well plan is stored in the database 328. The drilling engineer 1502 may also set drilling operation parameters in step 1710 that are also stored in the database 328.

In the other branch, the drilling rig 210 is constructed in block 1712. At this point, as illustrated by block 1726, the well plan, BHA information, control limits, historical drilling data, and control commands may be sent from the database 328 to the local database 1610. Using the receiving information, the directional driller 1506 inputs actual BHA parameters in block 1714. The company man 1514 and/or the directional driller 1506 may verify performance control limits in block 1716, and the control limits are stored in the local database 1610 of the on-site controller 344. The performance control limits may include multiple levels such as a warning level and a critical level corresponding to no action taken within feet/minutes.

Once drilling begins, a diagnostic logger (described later in greater detail) 1720 that is part of the on-site controller 344 logs information related to the drilling such as sensor information and maneuvers and stores the information in the local database 1610 in block 1726. The information is sent to the database 328. Alerts are also sent from the on-site controller 344 to the drilling hub 1616. When an alert is received by the drilling hub 1616, an alert notification 1722 is sent to defined individuals, such as the drilling engineer 1502, geologist 1504, and company man 1514. The actual recipient may vary based on the content of the alert message or other criteria. The alert notification 1722 may result in the well plan and the BHA information and control limits being modified in block 1708 and/or drilling parameters being modified in block 1710. These modifications are saved to the database 328 and transferred to the local database 1610. The BHA may be modified by the directional driller 1506 in block 1718, and the changes propagated through blocks 1714 and 1716 with possible updated control limits. Accordingly, the surface steerable system 1618 may provide a more controlled flow of information than may occur in an environment without such a system.

The flow charts described herein illustrate various exemplary functions and operations that may occur within various environments. Accordingly, these flow charts are not exhaustive and that various steps may be excluded to clarify the aspect being described. For example, it is understood that some actions, such as network authentication processes, notifications, and handshakes, may have been performed prior to the first step of a flow chart. Such actions may depend on the particular type and configuration of communications engaged in by the on-site controller 344 and/or drilling hub 1616. Furthermore, other communication actions may occur between illustrated steps or simultaneously with illustrated steps.

The surface steerable system 1618 includes large amounts of data specifically related to various drilling operations as stored in databases such as the databases 328 and 1610. This data may include data collected from many different locations and may correspond to many different drilling operations. The data stored in the database 328 and other databases may be used for a variety of purposes, including data mining and analytics, which may aid in such processes as equipment comparisons, drilling plan formulation, convergence planning, recalibration forecasting, and self-tuning (e.g., drilling performance optimization). Some processes, such as equipment comparisons, may not be performed in real time using incoming data, while others, such as self-tuning, may be performed in real time or near real time. Accordingly, some processes may be executed at the drilling hub 1616, other processes may be executed by the on-site controller 344, and still other processes may be executed by both the drilling hub 1616 and the on-site controller 344 with communications occurring before, during, and/or after the processes are executed. As described below in various examples, some processes may be triggered by events (e.g., recalibration forecasting) while others may be ongoing (e.g., self-tuning).

For example, in equipment comparison, data from different drilling operations (e.g., from drilling a plurality of wells) may be normalized and used to compare equipment wear, performance, and similar factors. For example, the same bit may have been used to drill two different wells, but the drilling may have been accomplished using different parameters (e.g., rotation speed and WOB). By normalizing the data, the two bits can be compared more effectively. The normalized data may be further processed to improve drilling efficiency by identifying which bits are most effective for particular rock layers, which drilling parameters resulted in the best ROP for a particular formation, ROP versus reliability tradeoffs for various bits in various rock layers, and similar factors. Such comparisons may be used to select a bit for another drilling operation based on formation characteristics or other criteria. Accordingly, by mining and analyzing the data available via the surface steerable system 1618, an optimal equipment profile may be developed for different drilling operations. The equipment profile may then be used when planning future wells or to increase the efficiency of a well currently being drilled. This type of drilling optimization may become increasingly accurate as more data is compiled and analyzed.

In drilling plan formulation, the data available via the surface steerable system 1618 may be used to identify likely formation characteristics and to select an appropriate equipment profile. For example, the geologist 1504 may use local data obtained from the planned location of the drilling rig 210 in conjunction with regional data from the database 328 to identify likely locations of the layers 268A-276A (FIG. 2A). Based on that information, the drilling engineer 1502 can create a well plan that will include the build curve of FIG. 2B.

Referring to FIG. 18, the estimated bit position is indicated by position 1843 relative to the desired bit position 1841 along the planned path 1842. It is understood that the estimated bit position and trajectory may not be calculated exactly but may represent an estimate the current location of the drill bit based on the feedback information.

In some embodiments, a projected bit position (not shown) may also be used. For example, the estimated bit position 1843 may be extended via calculations to determine where the bit is projected to be after a certain amount of drilling (e.g., time and/or distance). This information may be used in several ways. If the estimated bit position 1843 is outside the margin of error, the projected bit position 1843 may indicate that the current bit path will bring the bit within the margin of error without any action being taken. In such a scenario, action may be taken only if it will take too long to reach the projected bit position when a more optimal path is available. If the estimated bit position is inside the margin of error, the projected bit position may be used to determine if the current path is directing the bit away from the planned path. In other words, the projected bit position may be used to proactively detect that the bit is off course before the margin of error is reached. In such a scenario, action may be taken to correct the current path before the margin of error is reached.

The convergence plan identifies a plan by which the bit can be moved from the estimated bit position 1843 to the planned path 1842. It is noted that the convergence plan may bypass the desired bit position 1841 entirely, as the objective is to get the actual drilling path back to the planned path 1842 in the most optimal manner. The most optimal manner may be defined by cost, which may represent a financial value, a reliability value, a time value, and/or other values that may be defined for a convergence path.

As illustrated in FIG. 18, a number of paths may be selected to return the bit to the planned path 1842. The paths may begin at the estimated bit position 1843 or may begin at other points along a projected path 1852 that may be determined by calculating future bit positions based on the current trajectory of the bit from the estimated bit position 1852. In the present example, a first path 1844 results in locating the bit at a position 1845 (e.g., a convergence point). The convergence points 1845 is outside of a lower limit 1853 defined by a most aggressive possible correction (e.g., a lower limit on a window of correction). This correction represents the most aggressive possible convergence path, which may be limited by such factors as a maximum directional change possible in the convergence path, where any greater directional change creates a dogleg that makes it difficult or impossible to run casing or perform other needed tasks. A second path 1846 results in a convergence point 1847, which is right at the lower limit 1853. A third path 1848 results in a convergence point 1849, which represents a mid-range convergence point. A third path 1850 results in a convergence point 1851, which occurs at an upper limit 1854 defined by a maximum convergence delay (e.g., an upper limit on the window of correction).

A fourth path 1856 may begin at a projected point or bit position 1855 that lies along the projected path 1852 and result in a convergence point 1857, which represents a mid-range convergence point. The path 1856 may be used by, for example, delaying a trajectory change until the bit reaches the position 1855. Many additional convergence options may be opened up by using projected points for the basis of convergence plans as well as the estimated bit position.

A fifth path 1858 may begin at a projected point or bit position 1860 that lies along the projected path 1850 and result in a convergence point 1859. In such an embodiment, different convergence paths may include similar or identical path segments, such as the similar or identical path shared by the convergence points 1851 and 1859 to the point 1860. For example, the point 1860 may mark a position on the path 1850 where a slide segment begins (or continues from a previous slide segment) for the path 1858 and a straight line path segment begins (or continues) for the path 1850. The surface steerable system 1618 may calculate the paths 1850 and 1858 as two entirely separate paths or may calculate one of the paths as deviating from (e.g., being a child of) the other path. Accordingly, any path may have multiple paths deviating from that path based on, for example, different slide points and slide times.

Each of these paths 1844, 1846, 1848, 1850, 1856, and 1858 may present advantages and disadvantages from a drilling standpoint. For example, one path may be longer and may require more sliding in a relatively soft rock layer, while another path may be shorter but may require more sliding through a much harder rock layer. Accordingly, tradeoffs may be evaluated when selecting one of the convergence plans rather than simply selecting the most direct path for convergence. The tradeoffs may, for example, consider a balance between ROP, total cost, dogleg severity, and reliability. While the number of convergence plans may vary, there may be hundreds or thousands of convergence plans in some embodiments and the tradeoffs may be used to select one of those hundreds or thousands for implementation. The convergence plans from which the final convergence plan is selected may include plans calculated from the estimated bit position 1843 as well as plans calculated from one or more projected points along the projected path.

In some embodiments, straight line projections of the convergence point vectors, after correction to the well plan 1842, may be evaluated to predict the time and/or distance to the next correction requirement. This evaluation may be used when selecting the lowest total cost option by avoiding multiple corrections where a single more forward thinking option might be optimal. As an example, one of the solutions provided by the convergence planning may result in the most cost effective path to return to the well plan 1842 but may result in an almost immediate need for a second correction due to a pending deviation within the well plan. Accordingly, a convergence path that merges the pending deviation with the correction by selecting a convergence point beyond the pending deviation might be selected when considering total well costs.

It is understood that the diagram 1840 of FIG. 18 is a two dimensional representation of a three dimensional environment. Accordingly, the illustrated convergence paths in the diagram 1840 of FIG. 18 may be three dimensional. In addition, although the illustrated convergence paths all converge with the planned path 1842, is it understood that some convergence paths may be calculated that move away from the planned path 1842 (although such paths may be rejected). Still other convergence paths may overshoot the actual path 1842 and then converge (e.g., if there isn't enough room to build the curve otherwise). Accordingly, many different convergence path structures may be calculated.

Referring to FIG. 19, one embodiment of a system architecture 1900 is illustrated that may be used for the on-site controller 344 of FIG. 3. The system architecture 1900 includes interfaces configured to interact with external components and internal modules configured to process information. The interfaces may include an input driver 1902, a remote synchronization interface 1904, and an output interface 1918, which may include at least one of a graphical user interface (GUI) 1906 and an output driver 1908. The internal modules may include a database query and update engine/diagnostic logger 1910, a local database 1912 (which may be similar or identical to the database 1610 of FIG. 16), a guidance control loop (GCL) module 1914, and an autonomous control loop (ACL) module 1916. It is understood that the system architecture 1900 is merely one example of a system architecture that may be used for the on-site controller 344 and the functionality may be provided for the on-site controller 344 using many different architectures. Accordingly, the functionality described herein with respect to particular modules and architecture components may be combined, further separated, and organized in many different ways.

It is understood that the computer steerable system may perform certain computations to prevent errors or inaccuracies from accumulating and throwing off calculations. For example, as will be described later, the input driver 1902 may receive Wellsite Information Transfer Specification (WITS) input representing absolute pressure, while the surface steerable system 1618 may need differential pressure and needs an accurate zero point for the differential pressure. Generally, the driller will zero out the differential pressure when the drillstring is positioned with the bit off bottom and full pump flow is occurring. However, this may be a relatively sporadic event. Accordingly, the surface steerable system 1618 may recognize when the bit is off bottom and target flow rate has been achieved and zero out the differential pressure.

Another computation may involve block height, which needs to be calibrated properly. For example, block height may oscillate over a wide range, including distances that may not even be possible for a particular drilling rig. Accordingly, if the reported range is sixty feet to one hundred and fifty feet and there should only be one hundred feet, the surface steerable system 1618 may assign a zero value to the reported sixty feet and a one hundred foot value to the reported one hundred and fifty feet. Furthermore, during drilling, error gradually accumulates as the cable is shifted and other events occur. The surface steerable system 1618 may compute its own block height to predict when the next connection occurs and other related events and may also take into account any error that may be introduced by cable issues.

Referring specifically to FIG. 19, the input driver 1902 provides output to the GUI 1906, the database query and update engine/diagnostic logger 1910, the GCL 1914, and the ACL 1916. The input driver 1902 is configured to receive input for the on-site controller 344. It is understood that the input driver 1902 may include the functionality needed to receive various file types, formats, and data streams. The input driver 1902 may also be configured to convert formats if needed. Accordingly, the input driver 1902 may be configured to provide flexibility to the on-site controller 344 by handling incoming data without the need to change the internal modules. In some embodiments, for purposes of abstraction, the protocol of the data stream can be arbitrary with an input event defined as a single change (e.g., a real time sensor changes) of any of the given inputs.

The input driver 1902 may receive various types of input, including rig sensor input (e.g., from the rig sensors 1520 of FIG. 15), well plan data, and control data (e.g., engineering control parameters). For example, rig sensor input may include hole depth, bit depth, toolface, inclination, azimuth, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary RPMs, bit speed, ROP, and WOB. The well plan data may include information such as projected starting and ending locations of various geologic layers at vertical depth points along the well plan path, and a planned path of the borehole presented in a three dimensional space. The control data may be used to define maximum operating parameters and other limitations to control drilling speed, limit the amount of deviation permitted from the planned path, define levels of authority (e.g., can an on-site operator make a particular decision or should it be made by an off-site engineer), and similar limitations. The input driver 1902 may also handle manual input, such as input entered via a keyboard, a mouse, or a touch screen. In some embodiments, the input driver 1902 may also handle wireless signal input, such as from a cell phone, a smart phone, a PDA, a tablet, a laptop, or any other device capable of wirelessly communicating with the on-site controller 344 through a network locally and/or offsite.

The database query and update engine/diagnostic logger 1910 receives input from the input driver 1902, the GCL 1914, and ACL 1916, and provides output to the local database 1912 and GUI 1906. The database query and update engine/diagnostic logger 1910 is configured to manage the archiving of data to the local database 1912. The database query and update engine/diagnostic logger 1910 may also manage some functional requirements of a remote synchronization server (RSS) via the remote synchronization interface 1904 for archiving data that will be uploaded and synchronized with a remote database, such as the database 328 of FIG. 3. The database query and update engine/diagnostic logger 1910 may also be configured to serve as a diagnostic tool for evaluating algorithm behavior and performance against raw rig data and sensor feedback data.

The local database 1912 receives input from the database query and update engine/diagnostic logger 1910 and the remote synchronization interface 1904, and provides output to the GCL 1914, the ACL 1916, and the remote synchronization interface 1904. It is understood that the local database 1912 may be configured in many different ways. As described in previous embodiments, the local database 1912 may store both current and historic information representing both the current drilling operation with which the on-site controller 344 is engaged as well as regional information from the database 328.

The GCL 1914 receives input from the input driver 1902 and the local database 1912 and provides output to the database query and update engine/diagnostic logger 1910, the GUI 1906, and the ACL 1916. Although not shown, in some embodiments, the GCL 1906 may provide output to the output driver 1908, which enables the GCL 1914 to directly control third party systems and/or interface with the drilling rig alone or with the ACL 1916. An embodiment of the GCL 1914 is discussed below with respect to FIG. 21.

The ACL 1916 receives input from the input driver 1902, the local database 1912, and the GCL 1914, and provides output to the database query and update engine/diagnostic logger 1910 and output driver 1908. An embodiment of the ACL 1916 is discussed below with respect to FIG. 22.

The output interface 1918 receives input from the input driver 1902, the GCL 1914, and the ACL 1916. In the present example, the GUI 1906 receives input from the input driver 1902 and the GCL 1914. The GUI 1906 may display output on a monitor or other visual indicator. The output driver 1908 receives input from the ACL 1916 and is configured to provide an interface between the on-site controller 344 and external control systems, such as the control systems 522 (WOB/differential pressure control system), 524 (positional/rotary control system), and 526 (fluid circulation control system) of FIG. 5.

It should be understood that the system architecture 1900 of FIG. 19 may be configured in many different ways. For example, various interfaces and modules may be combined or further separated. Accordingly, the system architecture 1900 provides one example of how functionality may be structured to provide the on-site controller 344, but the on-site controller 344 is not limited to the illustrated structure of FIG. 19.

Referring to FIG. 20, one embodiment of the input driver 1902 of the system architecture 1900 of FIG. 19 is illustrated in greater detail. In the present example, the input driver 1902 may be configured to receive input via different input interfaces, such as a serial input driver 2002 and a Transmission Control Protocol (TCP) driver 2004. Both the serial input driver 2002 and the TCP input driver 2004 may feed into a parser 2006.

The parser 2006 in the present example may be configured in accordance with a specification such as WITS and/or using a standard such as Wellsite Information Transfer Standard Markup Language (WITSML). WITS is a specification for the transfer of drilling rig-related data and uses a binary file format. WITS may be replaced or supplemented in some embodiments by WITSML, which relies on eXtensible Markup Language (XML) for transferring such information. The parser 2006 may feed into the database query and update engine/diagnostic logger 1910, and also to the GCL 1914 and GUI 1906 as illustrated by the example parameters of block 2010. The input driver 1902 may also include a non-WITS input driver 2008 that provides input to the ACL 1916 as illustrated by block 2012.

Referring to FIG. 21, one embodiment of the GCL 1914 of FIG. 19 is illustrated in greater detail. In the present example, the GCL 1914 may include various functional modules, including a build rate predictor 2102, a geo modified well planner 2104, a borehole estimator 2106, a slide estimator 2108, an error vector calculator 2110, a geological drift estimator 2112, a slide planner 2114, a convergence planner 2116, and a tactical solution planner 2118. In the following description of the GCL 1914, the term external input refers to input received from outside the GCL 1914 (e.g., from the input driver 1902 of FIG. 19), while internal input refers to input received by a GCL module from another GCL module.

The build rate predictor 2102 receives external input representing BHA and geological information, receives internal input from the borehole estimator 2106, and provides output to the geo modified well planner 2104, slide estimator 2108, slide planner 2114, and convergence planner 2116. The build rate predictor 2102 is configured to use the BHA and geological information to predict the drilling build rates of current and future sections of a well. For example, the build rate predictor 2102 may determine how aggressively the curve will be built for a given formation with given BHA and other equipment parameters.

The build rate predictor 2102 may use the orientation of the BHA to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if there is a layer of rock with a layer of sand above it, there is a formation transition from the sand layer to the rock layer. Approaching the rock layer at a ninety degree angle may provide a good face and a clean drill entry, while approaching the rock layer at a forty-five degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause the bit to skip off the upper surface of the rock layer. Accordingly, the build rate predictor 2102 may calculate BHA orientation to account for formation transitions. Within a single layer, the build rate predictor 2102 may use BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a layer.

The BHA information may include bit characteristics, mud motor bend setting, stabilization, and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information enables a calculation-based prediction of the build rates and ROP that may be compared to both real-time results (e.g., obtained while drilling the well) and regional historical results (e.g., from the database 328) to improve the accuracy of predictions as the drilling progresses. Future formation build rate predictions may be used to plan convergence adjustments and confirm that targets can be achieved with current variables in advance.

The geo modified well planner 2104 receives external input representing a well plan, internal input from the build rate predictor 2102 and the geo drift estimator 2112 and provides output to the slide planner 2114 and the error vector calculator 2110. The geo modified well planner 2104 uses the input to determine whether there is a more optimal path than that provided by the external well plan while staying within the original well plan error limits. More specifically, the geo modified well planner 2104 takes geological information (e.g., drift) and calculates whether another solution to the target may be more efficient in terms of cost and/or reliability. The outputs of the geo modified well planner 2104 to the slide planner 2114 and the error vector calculator 2110 may be used to calculate an error vector based on the current vector to the newly calculated path and to modify slide predictions.

In some embodiments, the geo modified well planner 2104 (or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, the geologist 1504 may provide the surface steerable system 1618 with a target inclination that the surface steerable system 1618 is to attempt to hold. For example, the geologist 1504 may provide a target to the directional driller 1506 of 90.5-91 degrees of inclination for a section of the well. The geologist 1504 may enter this information into the surface steerable system 1618 and the directional driller 1506 may retrieve the information from the surface steerable system 1618. The geo modified well planner 2104 may then treat the target as a vector target, for example, either by processing the information provided by the geologist 1504 to create the vector target or by using a vector target entered by the geologist 1504. The geo modified well planner 2104 may accomplish this while remaining within the error limits of the original well plan.

In some embodiments, the geo modified well planner 2104 may be an optional module that is not used unless the well plan is to be modified. For example, if the well plan is marked in the surface steerable system 1618 as non-modifiable, the geo modified well planner 2104 may be bypassed altogether or the geo modified well planner 2104 may be configured to pass the well plan through without any changes.

The borehole estimator 2106 receives external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and provides outputs to the build rate predictor 2102, the error vector calculator 2110, and the convergence planner 2116. The borehole estimator 2106 is configured to provide a real time or near real time estimate of the actual borehole and drill bit position and trajectory angle. This estimate may use both straight-line projections and projections that incorporate sliding. The borehole estimator 2106 may be used to compensate for the fact that a sensor is usually physically located some distance behind the bit (e.g., fifty feet), which makes sensor readings lag the actual bit location by fifty feet. The borehole estimator 2106 may also be used to compensate for the fact that sensor measurements may not be continuous (e.g., a sensor measurement may occur everyone hundred feet).

The borehole estimator 2106 may use two systems and methods to accomplish this. First, the borehole estimator 2106 may provide the most accurate estimate from the surface to the last survey location based on the collection of all survey measurements. Second, the borehole estimator 2106 may take the slide estimate from the slide estimator 2108 (described below) and extend this estimation from the last survey point to the real time drill bit location. Using the combination of these two estimates, the borehole estimator 2106 may provide the on-site controller 344 with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process. For example, the borehole estimator 2106 may calculate the current bit position and trajectory 1843 in FIG. 18.

The slide estimator 2108 receives external inputs representing measured depth and differential pressure information, receives internal input from the build rate predictor 2102, and provides output to the borehole estimator 2106 and the geo modified well planner 2104. The slide estimator 2108, which may operate in real time or near real time, is configured to sample toolface orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantify/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the MWD survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by the distance of the sensor point from the drill bit tip (e.g., approximately fifty feet). This lag introduces inefficiencies in the slide cycles due to over/under correction of the actual path relative to the planned path.

With the slide estimator 2108, each toolface update is algorithmically merged with the average differential pressure of the period between the previous and current toolfaces, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during that period. As an example, the periodic rate may be between ten and sixty seconds per cycle depending on the tool face update rate of the MWD tool. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of the slide estimator 2108 is periodically provided to the borehole estimator 2106 for accumulation of well deviation information, as well to the geo modified well planner 2104. Some or all of the output of the slide estimator 2108 may be output via a display such as the display 850 of FIG. 8.

The error vector calculator 2110 receives internal input from the geo modified well planner 2104 and the borehole estimator 2106. The error vector calculator 2110 is configured to compare the planned well path to the actual borehole path and drill bit position estimate. The error vector calculator 2110 may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the plan. For example, the error vector calculator 2110 may calculate the error between the current position 1843 of FIG. 18 to the planned path 1842 and the desired bit position 1841. The error vector calculator 2110 may also calculate a projected bit position/projected path representing the future result of a current error as described previously with respect to FIG. 18.

The geological drift estimator 2112 receives external input representing geological information and provides outputs to the geo modified well planner 2104, slide planner 2114, and tactical solution planner 2118. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of drilling rate and BHA. The geological drift estimator 2112 is configured to provide a drift estimate as a vector. This vector can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.

The slide planner 2114 receives internal input from the build rate predictor 2102, the geo modified well planner 2104, the error vector calculator 2110, and the geological drift estimator 2112, and provides output to the convergence planner 2116 as well as an estimated time to the next slide. The slide planner 2114 is configured to evaluate a slide/drill ahead cost equation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the well plan path. During drill ahead, the slide planner 2114 may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., beads) are needed for the next slide and pumping the lubricants into the drill string needs to begin thirty minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants.

Functionality for a loss circulation material (LCM) planner may be provided as part of the slide planner 2114 or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives need to be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.

The slide planner 2114 may also look at the current position relative to the next connection. A connection may happen every ninety to one hundred feet (or some other distance or distance range based on the particulars of the drilling operation) and the slide planner 2114 may avoid planning a slide when close to a connection and/or when the slide would carry through the connection. For example, if the slide planner 2114 is planning a fifty foot slide but only twenty feet remain until the next connection, the slide planner 2114 may calculate the slide starting after the next connection and make any changes to the slide parameters that may be needed to accommodate waiting to slide until after the next connection. This avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the toolface before finishing the slide. During slides, the slide planner 2114 may provide some feedback as to the progress of achieving the desired goal of the current slide.

In some embodiments, the slide planner 2114 may account for reactive torque in the drillstring. More specifically, when rotating is occurring, there is a reactional torque wind up in the drillstring. When the rotating is stopped, the drillstring unwinds, which changes toolface orientation and other parameters. When rotating is started again, the drillstring starts to wind back up. The slide planner 2114 may account for this reactional torque so that toolface references are maintained rather than stopping rotation and then trying to adjust to an optimal tool face orientation. While not all MWD tools may provide toolface orientation when rotating, using one that does supply such information for the GCL 1914 may significantly reduce the transition time from rotating to sliding.

The convergence planner 2116 receives internal inputs from the build rate predictor 2102, the borehole estimator 2106, and the slide planner 2114, and provides output to the tactical solution planner 2118. The convergence planner 2116 is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well path. The convergence plan represents a path from the current drill bit position to an achievable and optimal convergence target point along the planned path. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by the slide planner 2114. The convergence planner 2116 may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to the build rate predictor 2102. The solution provided by the convergence planner 2116 defines a new trajectory solution for the current position of the drill bit. The solution may be real time, near real time, or future (e.g., planned for implementation at a future time). For example, the convergence planner 2116 may calculate a convergence plan as described previously with respect to FIG. 18.

The tactical solution planner 2118 receives internal inputs from the geological drift estimator 2112 and the convergence planner 2116 and provides external outputs representing information such as toolface orientation, differential pressure, and mud flow rate. The tactical solution planner 2118 is configured to take the trajectory solution provided by the convergence planner 2116 and translate the solution into control parameters that can be used to control the drilling rig 110. For example, the tactical solution planner 2118 may take the solution and convert the solution into settings for the control systems 522 (WOB/differential pressure control system), 524 (positional/rotary control system), and 526 (fluid circulation control system) to accomplish the actual drilling based on the solution. The tactical solution planner 2118 may also perform performance optimization as described previously. The performance optimization may apply to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by the GCL 1914 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole toolface. Accordingly, the GCL 1914 may receive information corresponding to the rotational position of the drill pipe on the surface. The GCL 1914 may use this surface positional information to calculate current and desired toolface orientations. These calculations may then be used to define control parameters for adjusting the top drive or Kelly drive to accomplish adjustments to the downhole toolface in order to steer the well.

For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with the GCL 1914 and/or other components of the on-site controller 344. In the present embodiment, a drilling model class is defined to capture and define the drilling state throughout the drilling process. The class may include real-time information. This class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a WOB/differential pressure model, a positional/rotary model, an MSE model, an active well plan, and control limits. The class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of the GCL 1914.

The drill bit model may represent the current position and state of the drill bit. This model includes a three dimensional position, a drill bit trajectory, BHA information, bit speed, and toolface (e.g., orientation information). The three dimensional position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. This model includes hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for the current drilling job. The borehole diameters represent the diameters of the borehole as drilled over the current drill job.

The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents drawworks or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active well plan represents the target borehole path and may include an external well plan and a modified well plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum RPMs to the defined level. The control output solution represents the control parameters for the drilling rig 2102.

The main processing loop can be handled in many different ways. For example, the main processing loop can run as a single thread in a fixed time loop to handle rig sensor event changes and time propagation. If no rig sensor updates occur between fixed time intervals, a time only propagation may occur. In other embodiments, the main processing loop may be multi-threaded.

Each functional module of the GCL 1914 may have its behavior encapsulated within its own respective class definition. During its processing window, the individual units may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the modules may be in the sequence of geo modified well planner 2104, build rate predictor 2102, slide estimator 2108, borehole estimator 2106, error vector calculator 2110, slide planner 2114, convergence planner 2116, geological drift estimator 2112, and tactical solution planner 2118. It is understood that other sequences may be used.

In the present embodiment, the GCL 1914 may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. While the on-site controller 344 may rely purely on timer and date calls driven by the programming environment (e.g., java), this would limit timing to be exclusively driven by system time. In situations where it may be advantageous to manipulate the clock (e.g., for evaluation and/or testing), the programmable timer module may be used to alter the time. For example, the programmable timer module may enable a default time set to the system time and a time scale of 1.0, may enable the system time of the on-site controller 344 to be manually set, may enable the time scale relative to the system time to be modified, and/or may enable periodic event time requests scaled to the time scale to be requested.

Referring to FIG. 22, one embodiment of the ACL 1916 provides different functions to the on-site controller 344. The ACL 1916 may be considered a second feedback control loop that operates in conjunction with a first feedback control loop provided by the GCL 1914. The ACL 1916 may also provide actual instructions to the drilling rig 210, either directly to the drilling equipment 530 or via the control systems 522 (WOB/differential pressure control system), 524 (positional/rotary control system), and 526 (fluid circulation control system). The ACL 1916 may include a positional/rotary control logic block 2202, WOB/differential pressure control logic block 2204, fluid circulation control logic block 2206, and a pattern recognition/error detection block 2208.

One function of the ACL 1916 is to establish and maintain a target parameter (e.g., an ROP of a defined value of feet per hour) based on input from the GCL 1914. This may be accomplished via control loops using the positional/rotary control logic block 2202, WOB/differential pressure control logic block 2204, and fluid circulation control logic block 2206. The positional/rotary control logic block 2202 may receive sensor feedback information from the input driver 1902 and set point information from the GCL 1914 (e.g., from the tactical solution planner 2118). The differential pressure control logic block 2204 may receive sensor feedback information from the input driver 1902 and set point information from the GCL 1914 (e.g., from the tactical solution planner 2118). The fluid circulation control logic block 2206 may receive sensor feedback information from the input driver 1902 and set point information from the GCL 1914 (e.g., from the tactical solution planner 2118).

The ACL 1916 may use the sensor feedback information and the set points from the GCL 1914 to attempt to maintain the established target parameter. More specifically, the ACL 1916 may have control over various parameters via the positional/rotary control logic block 2202, WOB/differential pressure control logic block 2204, and fluid circulation control logic block 2206, and may modulate the various parameters to achieve the target parameter. The ACL 1916 may also modulate the parameters in light of cost-driven and reliability-driven drilling goals, which may include parameters such as a trajectory goal, a cost goal, and/or a performance goal. It is understood that the parameters may be limited (e.g., by control limits set by the drilling engineer 1502) and the ACL 1916 may vary the parameters to achieve the target parameter without exceeding the defined limits. If this is not possible, the ACL 1916 may notify the on-site controller 344 or otherwise indicate that the target parameter is currently unachievable.

In some embodiments, the ACL 1916 may continue to modify the parameters to identify an optimal set of parameters with which to achieve the target parameter for the particular combination of drilling equipment and formation characteristics. In such embodiments, the on-site controller 344 may export the optimal set of parameters to the database 328 for use in formulating drilling plans for other drilling projects.

Another function of the ACL 1916 is error detection. Error detection is directed to identifying problems in the current drilling process and may monitor for sudden failures and gradual failures. In this capacity, the pattern recognition/error detection block 2208 receives input from the input driver 1902. The input may include the sensor feedback received by the positional/rotary control logic block 2202, WOB/differential pressure control logic block 2204, and fluid circulation control logic block 2206. The pattern recognition/error detection block 2208 monitors the input information for indications that a failure has occurred or for sudden changes that are illogical.

For example, a failure may be indicated by an ROP shift, a radical change in build rate, or any other significant changes. As an illustration, assume the drilling is occurring with an expected ROP of 100 ft/hr. If the ROP suddenly drops to 50 feet per hour with no change in parameters and remains there for some defined amount of time, an equipment failure, formation shift, or another event has occurred. Another error may be indicated when MWD sensor feedback has been steadily indicating that drilling has been heading north for hours and the sensor feedback suddenly indicates that drilling has reversed in a few feet and is heading south. This change clearly indicates that a failure has occurred. The changes may be defined and/or the pattern recognition/error detection block 2208 may be configured to watch for deviations of a certain magnitude. The pattern recognition/error detection block 2208 may also be configured to detect deviations that occur over a period of time in order to catch more gradual failures or safety concerns.

When an error is identified based on a significant shift in input values, the on-site controller 344 may send an alert. This enables an individual to review the error and determine whether action needs to be taken. For example, if an error indicates that there is a significant loss of ROP and an intermittent change/rise in pressure, the individual may determine that mud motor chunking has likely occurred with rubber tearing off and plugging the bit. In this case, the BHA may be tripped, and the damage repaired before more serious damage is done. Accordingly, the error detection may be used to identify potential issues that are occurring before they become more serious and more costly to repair.

Another function of the ACL 1916 is pattern recognition. Pattern recognition is directed to identifying safety concerns for rig workers and to provide warnings (e.g., if a large increase in pressure is identified, personnel safety may be compromised) and also to identifying problems that are not necessarily related to the current drilling process but may impact the drilling process if ignored. In this capacity, the pattern recognition/error detection block 2208 receives input from the input driver 1902. The input may include the sensor feedback received by the positional/rotary control logic block 2202, WOB/differential pressure control logic block 2204, and fluid circulation control logic block 2206. The pattern recognition/error detection block 2208 monitors the input information for specific defined conditions. A condition may be relatively common (e.g., may occur multiple times in a single borehole) or may be relatively rare (e.g., may occur once every two years). Differential pressure, standpipe pressure, and any other desired conditions may be monitored. If a condition indicates a particular recognized pattern, the ACL 1916 may determine how the condition is to be addressed. For example, if a pressure spike is detected, the ACL 1916 may determine that the drilling needs to be stopped in a specific manner to enable a safe exit. Accordingly, while error detection may simply indicate that a problem has occurred, pattern recognition is directed to identifying future problems and attempting to provide a solution to the problem before the problem occurs or becomes more serious.

Referring to FIG. 23, one embodiment of a computer system 2300 is illustrated. The computer system 2300 is one possible example of a system component or device such as the on-site controller 344 of FIG. 3. In scenarios where the computer system 2300 is on-site, such as at the location of the drilling rig 210 of FIG. 2A, the computer system may be contained in a relatively rugged, shock-resistant case that is hardened for industrial applications and harsh environments.

The computer system 2300 may include a central processing unit (“CPU”) 2302, a memory unit 2304, an input/output (“I/O”) device 2306, and a network interface 2308. The components 2302, 2304, 2306, and 2308 are interconnected by a transport system (e.g., a bus) 2310. A power supply (PS) 2312 may provide power to components of the computer system 2300, such as the CPU 2302 and memory unit 2304. It is understood that the computer system 2300 may be differently configured and that each of the listed components may actually represent several different components. For example, the CPU 2302 may actually represent a multi-processor or a distributed processing system; the memory unit 2304 may include different levels of cache memory, main memory, hard disks, and remote storage locations; the I/O device 2306 may include monitors, keyboards, and the like; and the network interface 2308 may include one or more network cards providing one or more wired and/or wireless connections to a network 2314. Therefore, a wide range of flexibility is anticipated in the configuration of the computer system 2300.

The computer system 2300 may use any operating system (or multiple operating systems), including various versions of operating systems provided by Microsoft (such as WINDOWS), Apple (such as Mac OS X), UNIX, and LINUX, and may include operating systems specifically developed for handheld devices, personal computers, and servers depending on the use of the computer system 2300. The operating system, as well as other instructions (e.g., software instructions for performing the functionality described in previous embodiments) may be stored in the memory unit 2304 and executed by the processor 2302.

Referring to FIG. 24, one embodiment of a GUI 2400 illustrates an interface that may be used to retrieve a log file and add, edit, or delete baseline markers. It is understood that the GUI 2400 is for purposes of example and that many different GUIs may be used to provide some or all of the functionality shown with the GUI 2400. In the present example, the GUI 2400 includes a file selection panel 2402, a marker selection panel 2404, a quality display panel 2406, and a gamma log panel 2408.

In operation, a user may create or edit a marker archive file using section 2402. In the present example, the marker archive file is “Offset Well 126 archive.txt.” A corresponding offset well may be associated with the offset well if that has not already been done. The user may then highlight (e.g., using a mouse, keyboard, and/or other interfaces) one or more sections of the gamma log. As these are highlighted, they are added to the marker selection panel 2404. For example, the illustrated portion of the gamma log includes four selected portions 2410, 2412, 2414, and 2416. The marker selection panel 2404 illustrates eight markers 2418, 2420, 2422, 2424, 2426, 2428, 2830, and 2832, each of which has a name, a start depth, and an end depth. The start depth and end depth may be automatically entered based on the corresponding selected portion. For purposes of illustration, the selected portion 2410 corresponds to marker 2420, the selected portion 2412 corresponds to marker 2422, the selected portion 2414 corresponds to marker 2424, and the selected portion 2416 corresponds to marker 2426.

The quality display panel 2406 contains quality indicators that illustrate a quality level of the currently selected marker. The quality level represents the strength of the selected marker. For example, the quality display panel 2406 may include a graph that illustrates a qualitative analysis of the difference between the right side average and the left side average, as well as the difference between the left side average and the peak. The selected widths are also illustrated. Using this feedback, a user can select the marker differently to strengthen these attributes.

In the present example, the quality display panel 2406 plots left, right, and peak values against a vertical axis measured in API (the unit of radioactivity used for gamma logs) and a horizontal axis measured in width. The width may be represented as TVD in some embodiments. It is noted that in offset logs, the TVD generally equals the measured depth unless the log is a TVD converted log. A messages section may be used to comment on the quality of the currently selected marker. For example, the current message indicates that the peak value is small relative to the left side value.

Accordingly, using the GUI 2400, a user can scroll through a gamma log, select portions of the gamma log, and save those portions as baseline markers. In addition, previously saved baseline markers can be edited or deleted.

Referring now to FIG. 25, one embodiment of an environment 2500 in which a drilling rig 210 may be used to penetrate the surface 106 of the Earth is shown.

Environment 2500 may represent a terrestrial environment, where surface 106 represents land. In other embodiments, environment 2500 may represent a marine environment, where surface 106 represents the bottom of a body of water such as an ocean or lake. Below the surface 106, one or several targeted locations 2506 in subsurface 2504, may contain minerals or hydrocarbons that will be extracted. The targeted locations are generally positioned along the planned wellbore path trajectory intended to be drilled.

Drilling rig 210 is representative of any machine such as a drill, with an ability to drill holes into the earth's subsurface 2504 and create a wellbore path, such as wellbore path 110. Drilling rig 210 may represent equipment small enough to move manually or massive structures housing equipment used to drill boreholes. Drilling systems and methods used by drilling rig 210 may include directional drilling, which increases the number of reserves that may be reached and can also increase production rate.

Drilling rig 210 equipment such as drilling system 2522 includes drill string 2512, comprising a hollow drill pipe that transmits drilling fluid and torque to a drill bit 146 coupled on a distal end of the drill string 2512. In particular, the distal end of the drill string 2512 comprises a bottom hole assembly (BHA) 149 that extends from the drill pipe of the drill string 2512 to the drill bit 146. The BHA 149 may include drill collars, stabilizers, reamers, shocks, hole-openers, bit sub, and drill bit 146. Characteristics of BHA 149 help to determine the wellbore shape, direction, and other geometric characteristics. The BHA 149 can be of any type or variation currently used by a person of ordinary skill in the art and may include but not be limited to: a rotary assembly, a steerable mud motor, rotary steerable systems, or a fulcrum, stabilization, or pendulum assembly. The proper selection of a type of BHA 149 can ensure good directional behavior, borehole quality (smoothness of the well path as opposed to tortuous), high rate of penetration (ROP), and result in a drilling process being completed quickly and efficiently.

The directional behavior of the drilling system 2522 may be defined as the manner in which the drilling system may change direction and how effectively it is able to change direction. The directional behavior of the drill depends on a complex coupling of bit directional responsiveness (bit steerability), bit walk tendency (WALK), mechanical behavior of the directional system (BHA), and the rock formation characteristics of the subsurface being drilled into.

Given the complex coupling of at least these factors, although the drill string 2512 is capable of drilling a non-vertical well, or directional drilling, a resulting wellbore path 2510 may be tortuous while being directed toward a given targeted location 106. Information about the actual tortuous path of the drilled wellbore path 2510 may be unknown to an operator of the drilling system. An “operator” may refer to a person or people who operate or direct the operation of the drilling system and may also be known in the industry as a directional driller, a drilling engineer, or a driller.

As the wellbore path 2510 is drilled, survey data may be collected by a measurement-while-drilling (MWD) tool of the BHA 149. Survey data are comprised of measured depth, inclination, and azimuth of the well path at discrete positions (also known as survey stations) along the wellbore. For example, survey data are collected every 2500 feet or so (but can also be collected more or less frequently if necessary). Survey data can then be transmitted to an electronic drilling recorder (EDR) 2524 at various increments of time, distance, depth, etc. during the drilling process. In some embodiments, the EDR 2524 records at a 1 to 10 seconds time range based on drilling data coming from different sensors available on the rig 210, such as weight on bit (WOB), torque at surface, rotation speed, mud weight, hook load, flow rate, stand pipe pressure, differential pressure, rate of penetration, and other information pertinent to the drilling process. In FIG. 25, survey data is collected every hundred feet at locations 2518A, 2518B, and 2518C. Survey data are then utilized to reconstruct the well path using a mathematical model such as the minimum of curvature method, to estimate the position of the well path in the Earth. However, as survey data are only collected every hundred feet or so, the position of the wellbore is not known very accurately, as opposed to survey data that would be collected every foot or so.

Directional drilling data may include more specifically how the BHA steers or guides the well path, information such as toolface orientation (TFO) (e.g., mode sliding or rotating), activation level of the rotary steerable system, and other information pertinent to the steering mode of the BHA.

Additional information corresponding to locations from which drilling data is gathered may include geological characteristics surrounding the locations such as rock formation data including unconfined or confined compressive strength (UCS or CCS) of the rock, dip/strike, and gamma ray (GR). In various embodiments, the rock formation data may generally come from acoustic logs of wells being drilled or offset wells previously drilled. Survey data may include the measurements of three parameters, as noted above: measured depth (MD), inclination of the borehole, and azimuth of the borehole.

Next, an example describing a method of collecting survey and drilling data is described. At location 2518A, the drilling system 2522 may have drilled a few hundred or thousand feet since beginning at the surface 106 and various data (for example, survey data, drilling data, and directional data) at location 2518A are collected. At this juncture in the example, the drill bit 146 is located at location 2518A. The drilling system 2522 may proceed to drill for another hundred feet until the drill bit 146 reaches location 2518B at which point additional survey data are collected. Similarly, the drilling system 2522 continues to drill another hundred feet at which point the drill bit 146 is located at 2518C. Additional survey data at location 2518C are collected. Thus, with a survey taken every hundred feet, data about the survey locations 2518A, 2518B, and 2518C may be known, however, the actual path 2510 of the wellbore path between the survey locations 2518A, 2518B, and 2518C is unknown, because no survey data is collected between these survey locations. The distance of one hundred feet is an example of a measurement interval, and any measurement interval may be used between surveys.

The collected survey data, in particular, the measured depth, and inclination and azimuth of the wellbore path, may be used to recreate a representation of the wellbore path using a mathematical method, such as the method of minimum curvature. For example, between two consecutive survey points (e.g., between 2518A and 2518B), one single geometrical arc with a given radius of curvature is generally calculated to represent the shape of the well path. However, it is known that this is not completely true as many changes of well path may occur, creating multiple small arcs, leading to tortuosity. Given the tortuous path of the wellbore, an accurate understanding of the wellbore path may be beneficial to an operator to make a better determination of the actual position of the well path relative to the reservoir or pay zone.

In various embodiments the collected survey and drilling data may be accessed while drilling is taking place, and in other embodiments, the collected survey and drilling data may be stored in one or more databases 2520A, which are coupled to EDR 2524. The dashed lines 2525 represent any wired or wireless communication channels between equipment located at intermittent locations 2518A, 2518B, or 2518C and the database 2520A. Database 2520A may represent a single machine located in a single location or several machines located in the same or disparate locations. The database 2520A may be located at the drilling rig 210, at a drilling hub, or elsewhere.

In some embodiments, the survey and drilling data may be stored on a non-transitory storage media, where the storage media is computer readable. The non-transitory computer-readable storage media may be coupled to a database 2520A to transfer and store the survey data in database 2520A.

When the collected survey and drilling data and rock formation data is input into a drill model, the drill model may then be used to generate a display depicting the actual path 2510 of the wellbore path as well as various predictions of what a future wellbore path may be beyond the section of the earth's subsurface that has already been drilled. In various embodiments, a borehole path estimator 2526 which may run on computer system 2520B, may use the drill model to predict the future wellbore path. The borehole path estimator 2526 may comprise a program that is executable by a processor and that may be stored on a storage device and access the various data discussed throughout (e.g., survey data, drilling data, rock formation data, etc.) and data stored in database 2520A. The borehole path estimator 2526 may predict both projections of the future wellbore path as well as reconstruct an actual path in accordance with the methods discussed herein.

In some embodiments, the borehole path estimator 2526 is coupled to a drilling control system 2528. In embodiments comprising the drilling control system 2528, the drilling control system 2528 controls various parameters discussed further below, such as WOB, differential pressure, RPM, drilling mode, etc. The drilling control system 2528 may apply path information provided by the borehole path estimator 2526 to keep the wellbore path on target. In some embodiments, the output of a borehole path estimator 2526 may be shown to an operator on a display. This display is discussed now in relation to FIG. 26.

Referring now to FIG. 26, aspects of a display 2600 representing results from a drilling model are discussed. In various embodiments, the display 2600 may be provided to a directional driller or drilling engineer to aid in determining a steering mode of the drilling system 2522 and BHA 149 when drilling the next segment of the wellbore path 2510. A method flow for running the drill model which generates the results shown in graph 2602.

In a first portion of the display 2600, the graph 2602 depicts measured depth (MD) along the x-axis 2604 and a true vertical depth (TVD) along the y-axis 2606. Various layers of the rock may also be depicted in graph 2602 (e.g., layers 2618A, 2618B, and 2618C). In the embodiment shown, the display 2600 is in two dimensions or 2-D, but other embodiments include a display in three dimensions or 3-D to represent the wellbore path in 3-D space.

In graph 2602 a planned path 2608 and an actual path 2610 are shown. In the example shown in FIG. 26, the planned path 2608 is less tortuous than the actual path 2610 as is often the case. In various instances, an operator is aware of the planned path 2608 but the operator has inaccurate knowledge of the actual path the wellbore has taken during drilling because of the unknown tortuosity. Increased knowledge of the actual path 2610 may be useful in decisions related to the vertical and horizontal position of the wellbore in the Earth which is critical to staying within the pay zone. Modeling software that has the ability to accurately reconstruct an actual path 2610 may also have increased accuracy when constructing a future wellbore path that has yet to be drilled. Differences in vertical and horizontal position of the wellbore up to 50 feet can be observed if one does not consider well bore tortuosity.

Graph 2602 is divided by a line of demarcation 2612 separating section 2614 and section 2616. The line of demarcation 2612 may correspond to the position of the drill bit 146. In section 2614, a representation of a drilled portion of the wellbore path 2510 is depicted, and in section 2616 various representations of possible directions the wellbore path 2510 may take with further drilling, are depicted. Thus, the portion of earth represented in section 2616 has not yet been drilled. Accordingly, portions of both an actual wellbore path (e.g., wellbore path 2510) and an undrilled section of the wellbore path are represented in graph 2602.

To reconstruct the actual path of a wellbore, path an underlying drill model may use step-by-step calculations to determine the actual path 2610. For example, although survey data from surveys 2518A, 2518B, and 2518C may provide some information about the orientation and location of the wellbore path at discrete points, additional and more robust information may be gleaned from drilling and directional data in conjunction with the borehole path estimator. As mentioned previously, the EDR 2524 collects drilling and directional data continuously during drilling, or more frequently than survey data is gathered, for example, at a frequency of every foot of measured depth drilled. This data may be used by a borehole path estimator 2526 to reconstruct an actual path 2610 of a drilled wellbore path 2510.

Various inputs to the drill model used to reconstruct the actual path 2610 may be calibrated by comparing an expected result and an output of the drill model, where the output is used to generate the reconstruction of the actual path 2610. More specifically, one set of input parameters that may be modified include: bit steerability (BS), walk angle (WALK), overgauge (OVG) borehole, and coefficient of friction (FF). In some embodiments, the initial set of parameters may be either estimated by a modeling software or simply set as defaults, given that, for example, BS is around 0.1, WALK is around −12 degrees, OVG is about ⅛ inch, and FF is around 0.2.

Once the various inputs have been calibrated and an actual path 2610 is produced that falls within an acceptable margin of error threshold, the various inputs and additional known data of the formations remaining to be drilled may be used to predict a future wellbore path. In various embodiments, a future wellbore path may be defined as a portion of the wellbore that has not yet been drilled. The future wellbore path may be a representation of a prediction of the location and path that may form once a segment of the earth's subsurface has been drilled. The path of a future wellbore may depend on a variety of factors including the drilling parameters, the drilling bit, the BHA, and type of rock being drilled.

Referring to section 2616, where predicted future wellbore paths are shown, a plurality of future trajectories 2620A, 2620B, 2620C, and 2620D are represented. The future trajectories 2620A, 2620B, 2620C, and 2620D are generated based on any known prediction methodology and utilizing the modified input parameters of the drill model. Furthermore, the future trajectories 2620A, 2620B, 2620C, and 2620D are displayed in real-time based on operating parameters selected by the operator by way of buttons 2622. This enables the operator to choose operating parameters that the operator wants to achieve a desired trajectory. In various embodiments, the operator may have a goal of remaining as close as possible to a planned trajectory for a wellbore path, minimizing dog legs, and maximizing a Rate of Penetration (ROP).

For example, given the various drilling parameters specified by the operator by way of buttons 2622, the drill model predicts the resulting future wellbore paths 2620A, 2620B, 2620C, and 2620D corresponding to four different WOBs. Each future wellbore path is specific to one set of parameters. More specifically, a wellbore path may be formed according to future wellbore path 2620A if, for example, a WOB of forty kilo-pounds is applied. As one of the abilities to vary the directional tendency of the assembly comes from varying the WOB, modifying the WOB effectively tunes the directional tendency of the BHA 149 and thus the drilling system 2522. Accordingly, with a WOB of thirty-five kilo-pounds, the drill model predicts a wellbore path may be formed according to the different future wellbore path 2620B.

As mentioned above, various buttons 2622 provide an operator with the ability to select various drilling parameters to see how varying the parameters may impact future wellbore paths. The button 2622A enables an operator to control the distance ahead the operator would like to see. The operator may be planning to drill a next section of the subsurface of the earth, where the next section is a hundred feet long. Thus, in display 2600, setting button 2622A to one hundred feet makes it such that the future wellbore paths 2620A, 2620B, 2620C, and 2620D are shown out to one hundred feet.

Button 2622B allows an operator to specify a distance the drilling system 2522 rotates, and button 2622C allows the operator to specify a distance the drilling system 2522 slides, while using, for example, a steerable mud motor. Additionally, the operator may specify parameters such as the tool face orientation (TFO), WOB, and differential pressure, which are buttons 2622D, 2622E, and 2622F, respectively. The WOB and differential pressure are normally linked or coupled, as the differential pressure represents the difference in pressure when the bit is off-bottom (WOB=0) and on-botttom (WOB >0). As a consequence, the operator can select one or the other.

The rotate and slide buttons (2622B and 2622C) reference the ability of drilling system 2522 to alternate between a rotating and sliding mode. In a rotating mode, an entire drill string 2512 may be rotated by a drilling rig's rotary table or top drive. In the rotation mode, the drilling system 2522 may maintain a straight drilling path. If a drilling system 2522 deviates from an intended course while in rotating mode, the sliding mode may be used. In the sliding mode, the drillstring 2512 does not rotate; instead, the drill bit 146 may be turned by a downhole motor, and the wellbore path may be drilled in the direction the drill bit 146 is pointing. The direction the drill bit 146 is pointing may be controlled by TFO.

The TFO defines an orientation of the deflection tool (e.g., downhole motor), which controls the direction of drilling. The deflection tool is oriented in a particular direction to make a desired deflection within the wellbore. In one example, the toolface orientation may be based on High Side (TFO=0 degrees) or Low Side (TFO=180 degrees), where the TFO is measured from the high side of the borehole in a plane perpendicular to the axis of the hole.

The WOB is the amount of downward force exerted on the drill bit 146 and in some embodiments may be measured in thousands of pounds. Differential pressure defines a pressure of the drilling fluid and may be measured in pounds per square inch and represents the difference in pressure when the bit is off-bottom (WOB=0) and on-botttom (WOB >0).

Given the parameters set by the operators at buttons 2622B, 2622C, 2622D, 2622E, and 2622F, the underlying borehole path estimator 2526 may utilize the drill model to output a buildup rate (BUR) indicator 2624, and a turn rate (TR) indicator 2626 over the course length selected at 2622A. The directional behavior of the system can be quantified by the build or drop rate of the system and the turn rate of the system. The build or drop rate may be further defined as the rate of change of the inclination of the wellbore over a given distance. The turn rate may be further defined as the rate of azimuth change over the same given distance. An example unit for a build/drop rate and turn rate is degree/100 ft.

Referring now to FIG. 27, one embodiment of a three-dimensional borehole space 2700 is illustrated with two measured survey points 2702 (also labeled as “A”) and 2704 (also labeled as “C”). A borehole path (not shown) extends between the two survey points 2702 and 2704, but the actual path is unknown. Current borehole projection methods frequently use a minimum curvature technique for estimating the borehole projection between the two survey points 2702 and 2704. Assuming the initial borehole position is known as well as its initial survey trajectory, there may be only a subsequent measure of additional borehole length and a new survey trajectory that can be measured from surface and downhole instruments that are available.

In FIG. 27, the borehole space is presented in Cartesian space with a North-South (N) axis 2708, an East-West include axis 2710, an Up-Down Vertical (V) axis 2712, and a borehole trajectory where an inclination angle represents the vertical component, and a compass style azimuth angle represents the horizontal component. The initial survey points 2702 has an inclination and azimuth trajectory of α1 and ε1, respectively, and the second survey point 2704 has an inclination and azimuth trajectory of α2 and ε2, respectively.

With only new survey trajectory and path length information available, an assumption must be made about the shape of the borehole between the survey points 2702 and 2704. The minimum curvature method works off the assumption that the borehole moves along the smoothest possible arc between two survey points. This arc is represented by arc 2714. The change in trajectory angle from survey point 2702 to survey point 2704 (β) is often referred to as a dogleg in the context of surveying. The path ABC (where B is also labeled as point 2706) represents the balanced tangential method path, whereby a borehole projection is estimated by two line segments which intersect at the point where the curvature angle, β, is evenly bisected. This bisection point is point 2706 in the present example. This is a useful case, as the minimum curvature method represents a special case of the balanced tangential method where the two line segments are substituted with a circular arc curve (e.g., the arc 2714) that also passes through points 2702 and 2704 with tangents at those points aligned with their respective trajectories. The equations for the curve AB are the same as the balanced tangential method for calculating path ABC except for the application of the ratio factor (RF):

$\begin{matrix} Δ V = \frac{Δ M D}{2} [\cos α1 + \cos α2] \times RF & (Equation 1) \end{matrix}$

$\begin{matrix} Δ N = \frac{Δ M D}{2} [\sin α1 \times \cos ε1 + \sin α2 \times \cos ε2] \times RF & (Equation 2) \end{matrix}$

$\begin{matrix} Δ E \frac{Δ M D}{2} [\sin α1 \times \sin ε1 + \sin α2 \times \sin ε2] \times RF & (Equation 3) \end{matrix}$

When using Equations 1-3 for estimating borehole positions between measured survey points, ΔMD represents an increase in measured depth progress between two survey trajectory measurements.

The ratio factor (RF) is used to account for the path length difference between the length of ABC and the length of the minimum curvature arc which crosses through AC. RF is given by the equation:

$\begin{matrix} R F = \frac{2}{β} \tan \frac{β}{2} & (Equation 4) \end{matrix}$

The minimum curvature method may result in significant inaccuracy as shown in the following examples. There are two basic assumptions in these examples. The first is that the example starts from a ninety degree inclination. The second is that all sliding is two-dimensional in the vertical plane.

Table 1, shown below, illustrates a scenario where a slide has occurred.

TABLE 1

Description
Value
Units

Total MD Increment
100
ft

Between Surveys

Slide/Build Duration
15
ft

Instantaneous Build Rate
12
Degrees/100 feet

Inclination Change
1.8
Degrees

For purposes of illustration, the distance between surveys is equal to one hundred feet and is used as a surface measurement of the total measured depth increment. Accordingly, the total measured depth increment between surveys in Table 1 is one hundred feet. The slide lasted for fifteen feet and had an instantaneous build rate of twelve degrees per one hundred feet, so the inclination change over the twelve foot slide was 1.8 degrees.

Table 2, shown below, illustrates two scenarios where a slide has occurred. The first column contains two rows, with each row indicating whether the slide occurred at the beginning of the one hundred foot distance or at the end.

TABLE 2

Interpreted

Traditional

Formation Dip

Curve Fit

Error Over

MD
TVD
TVD
Interpreted
Survey Period

change
change
change
TVD error
Due to TVD

(ft)
(ft)
(ft)
(ft)
Error (degrees)

Slide before
100
2.906
1.571
1.335
0.765

Rotate

Rotate
100
0.236
1.571
−1.335
−0.765

before Slide

In the first row where sliding occurred before rotation, the TVD change is 2.906 feet. Using the previously presented equations for curve fitting, the curve fit TVD change is 1.571 feet. This results in an interpreted TVD error of 1.335 feet and an interpreted formation dip error of 0.765 degrees. In the second row where sliding occurred after rotation, the TVD change is 0.236 feet. Using the previously presented equations for curve fitting, the curve fit TVD change is 1.571 feet. In other words, the curve fit TVD change is the same as in row one. The curve fit TVD change of 1.571 results in an interpreted TVD error of −1.335 feet and an interpreted formation dip error of −0.765 degrees.

Although the errors may cancel each other out relative to the entire well (e.g., an error in one direction may be canceled by an equal error in the opposite direction), the errors in a given direction accumulate and there is more accumulation the longer that a slide occurs in a particular direction.

As illustrated in Table 2, the curve fit TVD change for a particular set of slide/build duration and instantaneous build rate values remains constant regardless of whether sliding occurs before or after rotation even though the TVD change is different based on whether sliding occurs before or after rotation. This difference between the curve fit TVD change and the total TVD change occurs for different values of slide/build duration and instantaneous build rate in Table 1. The curve fit TVD change and the total TVD change may only match in two scenarios. The first is when the slide occurs for the full one hundred feet (e.g., slide/build duration is set to 100 in Table 1), as the borehole shape may be estimated as an arc between the two survey points. The second is when the slide is symmetrically centered on the midpoint between survey points.

Accordingly, using only information from two measured survey points to estimate the state of the drilling (e.g., orientation of the bit and distance drilled) between the two survey points may result in significant inaccuracies. These inaccuracies may negatively impact drilling efficiency, the ability to objectively identify well plan corrections, the ability to characterize formation position and dip angles, and/or similar issues. Furthermore, problems such as tortuosity may be more difficult to identify and address. Inaccurate TVD information may result in difficulties in following the target layer (e.g., the layer 272A of FIG. 2A), as even seemingly minor variations in inclination (e.g., one half of one degree) may cause the drill bit to exit the target layer.

Referring now to FIG. 28, details of a mud additive system 2800 is depicted. Specifically, FIG. 28 depicts different kinds of additives and corresponding equipment that may be included with mud additive system 2800. FIG. 28 is a schematic diagram for descriptive purposes and omits various implementation details for clarity. As shown, mud additive system 2800 includes a mud additive mixer 2810 that may be associated with additive processing equipment (not shown) and individual control systems for the additive processing equipment. For example, mud additive system 2800 or mud additive mixer 2810 may include one or more processors with an accessible memory media (not shown) that is enabled to execute instructions, such as instructions for controlling additive or mixing equipment, and instructions to receive commands to control the additive or mixing equipment, among other instructions. Mud additive system 2800 may be used to introduce additives into drilling mud 153 in a manner that is consistent, controlled, and safe. Mud additive system 2800 may include an automated delivery system for additives to be introduced into drilling mud 153 that achieves consistency, high feed rates, and process control to support various densities, particle sizes, and uniform distribution of the additives to be added to drilling mud 153. The automated delivery system included in mud additive system 2800 may also provide safety benefits by reducing manual handling and interactions with various additives that may include hazardous chemicals. The safety benefits may result from a decreased risk of injury from manually handling the hazardous chemicals, which may be present in bulk form in large quantities, as well as from manually handling the packaging of the additives and manually mixing the additives in batches. By removing or avoiding such manual operations associated with handling additives and packaging using the automated delivery system, the risks to human personnel may be reduced by the use of mud additive system 2800. The additive may be selected from any one or more of: a liquid, a colloid, a solid-liquid mixture, a solute dissolved in a solvent, a powder, and a particulate.

As shown in FIG. 28, mud additive system 2800 may be communicatively coupled to steering control system 168, such as by using a wired or a wireless network connection. Accordingly, mud additive system 2800 is enabled to be responsive to control signals or commands received from steering control system 168. In some embodiments, mud additive system 2800 may be responsive to commands received from a human operator. The control signals or commands received by mud additive system 2800 from steering control system 168 may originate as a decision made by mud control 2820 or may be in response to user input. For example, from steering control system 168, the user may be provided user interface elements, such as on user interface 850, to select types and amounts of available additives to add to drilling mud 153, as well as user interface elements to specify the timing or rate of introduction of the additives to drilling mud 153. Thus, in addition to controlling the content and amount of the additives being added to drilling mud 153, mud additive system 2800 may control the timing of mixing a desired additive having a given composition, such as from other additives, and outputting the desired additive to merge point 2818 for mixing with drilling mud 153. It is noted that the timing of delivery of additives to drilling mud 153 may be an important factor for optimal drilling. For example, polytetrafluoroethylene (PTFE or Teflon™) beads may be used as an additive to lubricate drilling mud 153 during slide drilling. If the PTFE beads are delivered to drill bit 146 too early or too late with respect to the slide drilling, the PTFE beads may fail to lubricate the slide drilling as intended, which is undesirable for drilling purposes, but also because the cost and effort to introduce the lubricating PTFE beads is wasted. In one example, the user interface can enable the user to specify additive parameters such as fiber size, density, granular particulate size, and composition of a mixture of different additives or additive components, such as various chemical agents, bentonite, PTFE beads, among others. The user input provided to steering control system 168 may result in immediate dosing of the specified additives to drilling mud 153 without delay. The user input to steering control system 168 may also specify a delay or a timestamp in the future when the specified additives are to be added to drilling mud 153. In addition, the user input provided to steering control system 168 may specify certain process parameters, such as a feed rate, a chopper rate, among others, in order to control the size and consistency of individual additives to be added to drilling mud 153.

As shown in FIG. 28, mud additive system 2800 includes mud additive mixer 2810 having an output line 2802 that may couple to mud analysis and control system 2824 via return line 2822. Also shown with mud additive system 2800 is a dry feeder 2808 that may be used as a feed line for dry material to be added to drilling mud 153, such as powders, fibers, particles, and various dry mixtures that can be gravitationally dispensed using a hopper, for example. The refilling of the hopper (or other storage means) of dry feeder 2808 may be manually performed, such as in response to a corresponding indication provided on user interface 850, or locally at mud additive system 2800. In other embodiments, additional equipment may be provided to automate a sufficient supply feed of a dry additive for dispensing by dry feeder 2808. Dry feeder 2808 may be an automated device that is enabled to volumetrically or gravitationally dispense quantities of the dry additive to mud additive mixer 2810. Although one instance of dry feeder 2808 is shown in FIG. 28 for descriptive clarity, it is noted that a plurality of dry feeders 2808 may be used, such as for a corresponding plurality of dry additives. Because dry feeder 2808 can precisely dispense quantitatively accurate amounts of the dry additive, dry feeder 2808 may be controlled to dispense a desired amount of the dry additive at a desired time.

In FIG. 28, also shown with mud additive system 2800 is a mud supply tank 2812, along with a control valve 2814. Mud supply tank 2812 may be used to supply fresh mud into drilling mud 153, such as when the circulating mud supply in borehole 106 is lost during drilling. Additionally, mud supply tank 2812 may be used to provide low concentrations of an additive, such when a predilution of the additive using the fresh mud from mud supply tank 2812 is indicated, prior to mixing with drilling mud 153. Control valve 2814 may be used to meter the output from mud supply tank 2812, and may accordingly be a servo-actuated valve, such as a ball valve for example. It is noted that mud supply tank 2812 can be a fixed structure, or can be a terrestrial pit, such as mud pit 154, while additional mud pumps and mud lines (not shown) may be used to provide the fresh mud to mud additive mixer 2810. Also shown with mud additive system 2800 is a liquid additive tank 2816, along with a control valve 2818. Liquid additive tank 2816 may bused to supply a liquid additive to mud additive mixer 2810 that can be controlled using control valve 2818. It is noted that although one liquid additive tank 2816 is shown for one liquid additive, a plurality of liquid additive tanks and control valves for a respective plurality of different or the same liquid additive may be used.

Also shown in FIG. 28 are packaged additives 2806 that can be supplied to mud additive mixer 2810. Packaged additives 2806 may represent certain substances that are packaged in small units for environmental stability and preservation prior to addition to drilling mud 153. Accordingly, the packaging used for packaged additives 2806 may protect them against moisture, temperature, water, air, oxygen, or otherwise prevent degradation from undesirable environments to ensure a desired efficacy when used in borehole 106. In some embodiments, the packaging used for packaged additives 2806 itself may comprise a desired additive, such as one or more materials that are soluble in drilling mud 153, for example. It should be further appreciated that, in one aspect of the present disclosure, one or more packaged additives 2806 may be customized to be particularly useful for a particular type of well, a particular region in which the well is located, or for particular geological formations, among other criteria. In some embodiments, a particular well owner may specify the form and composition of packaged additives 2806 for use in borehole 106. It is noted that even when packaged additives 2806 are manually fed from feed spools 2804, the rope or cable form may itself be useful for standardizing the delivery of packaged additives 2806 to drilling mud 153 and may improve the consistency of the delivery.

In some embodiments, the packaged additives 2806 may be removably joined together in a continuous series, such as when sausages are linked together in a chain arrangement or when laminated condiment packages are removably joined together at their ends. The contents and amounts of the additives in the packaged additives 2806 can be precisely and accurately controlled and reproduced. This approach may allow the easier and more precise delivery of the desired number of additives at the desired time and should help sustain better and easier environmental control and stability in transit. The contents of the packaged additives 2806 may contain a single additive or chemical, or a mixture of liquids, solids, and chemicals in a preselected and predictable relative mixture. Rope and cable structures, as discussed in more detail elsewhere, can contain layers of different types of additives, such as fibrous materials, solids, and liquids.

As shown in FIG. 28, three different types of packaged additives 2806A, 2806B, and 2806C are depicted being respectively supplied as ropes or cables using feed spools 2804A, 2804B, 2804C. Although three different kinds of packaged additives 2806 are depicted, it is noted that various numbers of packaged based additives 2806 may be supplied to mud additive mixer 2810. In FIG. 28, each packaged additive 2806 is shown with a different packaged form that may indicate a different composition, respectively. Although packaged additives 2806 are shown having discrete packages tied together, it will be understood that packaged additives 2806 may include a continuous form, such as a clear tube filled with the additive that may be dosed on the basis of length of the clear tube, for example. Other types of packaged additives (not shown) may be added in discrete form, such as blocks, sticks, bricks, rods, among other forms.

In addition, the orientation of feed spools 2804 shown in FIG. 28 is schematic and feed spools 2804 may be physically installed in various orientations. In various implementation, packaged additives 2806 may be servo mechanically fed to mud additive mixer 2810, such as by powering feed spools 2804 or using another means, and may enable precise quantitative dosing of packaged additives 2806, such as by controlling a feed rate of powered feed spools 2804. In addition, mud additive system 2800 may include one or more choppers or grinders (not shown) that may be enabled to decimate or separate individual portions of packaged additives 2806. In one example (not shown), packaged additives 2806 can be fed vertically into mud additive mixer 2810 using gravity feeding. In another embodiment, packaged additives 2806 may be fed to mud additive mixer 2810 using one or more powered rollers, or using the choppers or grinders in mud additive mixer 2810 feed packaged additives 2806. In mud additive system 2800, packaged additives 2806 may be mixed with liquid additives, dry additives, or drilling mud, among other types of liquid and solid mixtures that may be used.

With reference to FIG. 28, one particular kind of additive for drilling mud 153 is referred to as a loss circulation material (LCM). As drilling mud 153 is circulated into borehole 106 to reduce the friction and heat generated by the drill bit 146 working on the geological formation, under certain conditions, a certain amount of drilling mud 153 may seep into cracks in the geological formation. Drilling mud 153 seeping into the geological formation may result in undesirable loss of drilling mud 153 and may accordingly adversely affect drilling, such as by increasing the friction and heat at drill bit 146. To reduce the loss of drilling mud 153 into the geological formation, or other losses, various LCM may be added to drilling mud 153. The LCM in drilling mud 153 may seal off holes, cracks, or other openings in the geological formation, and may result in reduced loss of drilling mud 153. LCM compositions may vary from fibrous materials (e.g., tree bark and cane stalks) to granular materials (e.g., wood and nuts hulls). Typically, LCM is manually added by humans to drilling mud 153, which can result in significant inconsistencies, or errors that can damage costly drilling equipment. For example, if a mud line transporting drilling mud 153 becomes clogged due to improper or excessive addition of LCM, various drilling equipment may fail, and the failure may result in an unexpected tripping that can add delay, expense, and additional safety risks.

However, with the use of mud analysis and control system 2824, downhole or surface sensors can be used to monitor various properties of drilling mud 153 during drilling as various drilling operations and drilling parameters are being controlled. Then, for example, steering control system 168 may be enabled to detect significant changes to the condition and amount of drilling mud 153 being circulated during drilling without delay, such as by using mud analysis system 2826 as described previously herein. Once steering control system 168 detects an unsuitable condition of drilling mud 153, an indication may be transmitted or displayed to the uSerial The indication may be a communication, such as a message, a short-message service (SMS) message, an email, an audible alert, a visual alert (e.g., a colored indicator that can be red, blinking, yellow, or green, according to specified criteria). The unsuitable condition may be a significant loss of drilling mud 153, that may be indicated when the loss exceeds a predetermined amount. For example, the loss may be indicated when a drilling parameter associated with drilling mud 153 exceeds a predetermined range of values, or another alarm condition occurs. In response to the indication of excessive loss of drilling mud 153, steering control system 168 may be enabled to control mud additive system 2800 to automatically or semi-automatically add large particles sizes of LCM to drilling mud 153 to pump downhole and seal the geological formation. Similarly, in response to an indication that a slide drilling operation is coming up soon (which can be based on time, MD, WOB, ROP, etc.), steering control system 168 may be enabled generate a corresponding user notification of the desirability of adding certain types of LCM to drilling mud 153 within a particular time window and in a particular amount. In this manner, steering control system 168 is enabled to improve the chances that the appropriate amount of LCM be added to drilling mud 153 in a timely manner. In other embodiments, steering control system 168 may automatically control mud additive system 2800 to automatically deliver a specified LCM to drilling mud 153 at a desired and preprogrammed start time and schedule. In particular embodiments, steering control system 168 may automatically control a feed rate and grinding operations for an LCM, such as by grinding the LCM for a longer period of time to obtain a smaller particle size of the LCM.

Referring now to FIGS. 29-33, methods of optimizing drilling operations are shown.

FIG. 29 is a flowchart of an example process 2900 associated with systems and methods to optimize drilling operations. In some implementations, one or more process blocks of FIG. 29 may be performed by a drilling rig controller (e.g., controller 1000 of FIG. 10). In some implementations, one or more process blocks of FIG. 29 may be performed by another device or a group of devices separate from or including the controller 1000. Additionally, or alternatively, one or more process blocks of FIG. 29 may be performed by one or more components of device 1000, such as processor 1001, memory media 1010, input device 1008, output device 1009, bus 1002, instructions 1024A and 1024B, network adapter 1020, display adapter 1004, display 1005.

At block 2910, the process 2900 can include receiving strategy information from a drilling plan or roadmap. The drilling roadmap can provide formation and deposit information. The drilling roadmap information can be stored in a memory. In various embodiments, the drilling roadmap information can be downloaded from storage system (e.g., a cloud-based storage system) via a network (e.g., the Internet). In various embodiments, the drilling roadmap information can be received via a non-transitory computer readable medium (e.g., a flashdrive, a hard drive, or another medium for storing data). In various embodiment, the drilling roadmap information can be entered manually by a driller.

At block 2920, the process 2900 can include receiving a plurality of operating parameters from one or more sensors, which may be downhole sensors, surface sensors, or a combination thereof. The operating parameters can include one or more of a differential pressure, weight on bit, rate of penetration, and toolface, and rate of rotation of the drilling rig. In various embodiments, the one or more operating parameters can be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. In various embodiments, the plurality of operating parameters from the one or more sensors can be processed with computer vision.

The values for the one or more operating parameters can be communicated from the one or more sensors to the controller via a wired and/or wireless communication means. The one or more sensors can be downhole sensors or external sensors part of the drilling rig. The one or more sensors can include but are not limited to a pressure sensor, a torque sensor, a weight-on-bit sensor, a toolface sensor, a temperature sensor, a rotation sensor, a depth sensor, etc. The values for the one or more received operating parameters can be stored in a memory of the controller.

At block 2930, the process 2900 can include receiving a selection of one or more factors for optimizing drilling operations. The selection can be received via a user interface. In various embodiments, the one or more factors can include one or more of environmental, social, governance (ESG) or greenhouse gas (GHG) measurements for power generation for a rig site. In various embodiments, the one or more factors concern a top detection update and a landing target for the formation. In various embodiments, the one or more factors concern a drilling dysfunction measurement or a drilling mechanical specific energy (MSE) measurement trend. In various embodiments, the one or more factors for optimizing drilling operations concern a lifespan of bottom hole assembly (BHA) equipment.

At block 2940, the process 2900 can include generating one or more instructions based at least in part on the drilling roadmap, the plurality of operating parameters, and the one or more selected factors for optimizing drilling operations. The one or more instructions can be stored in the memory.

At block 2940, the process 2900 can include transmitting the one or more instructions to a drilling controller. The instructions can be transmitted via wired or wireless communication systems and methods.

At block 2950, the process 2900 can include drilling according to the one or more instructions. The one or more control systems can adjust one or more of the drilling parameters based at least in part on the instructions.

In various embodiments, a controller can include one or more memories and one or more processors in communication with the one or more memories and configured to execute instructions stored in the one or more memories to performing operations of a method described above.

In various embodiments, a computer-readable medium may store a plurality of instructions that, when executed by one or more processors of the controller, cause the one or more processors to perform operations of any of the methods described above.

Although FIG. 29 shows example steps of process 2900, in some implementations, process 2900 can include additional steps, fewer steps, different steps, or differently arranged steps than those depicted in FIG. 29. Additionally, or alternatively, two or more of the steps of process 2900 can be performed in parallel.

FIG. 30 illustrates a flowchart for an example process 3000 for communication systems and methods for drilling operations. In some implementations, one or more process blocks of FIG. 30 may be performed by a drilling rig controller (e.g., controller 1000 of FIG. 10). In some implementations, one or more process blocks of FIG. 30 may be performed by another device or a group of devices separate from or including the controller 1000. Additionally, or alternatively, one or more process blocks of FIG. 30 may be performed by one or more components of device 1000, such as processor 1001, memory media 1010, input device 1008, output device 1009, bus 1002, instructions 1024A and 1024B, network adapter 1020, display adapter 1004, display 1005.

At block 3010, the process 3000 can include receiving strategy information from a drilling roadmap. The drilling roadmap can provide formation and deposit information. The drilling roadmap information can be stored in a memory. In various embodiments, the drilling roadmap information can be downloaded from storage system (e.g., a cloud-based storage system) via a network (e.g., the Internet). In various embodiments, the drilling roadmap information can be received via a non-transitory computer readable medium (e.g., a flash drive, a hard drive, or another medium for storing data). In various embodiment, the drilling roadmap information can be entered manually by a driller.

At block 3020, the process 3000 can include receiving a plurality of operating parameters from one or more sensors. The operating parameters can include one or more of a differential pressure, weight on bit, rate of penetration, and toolface, and rate of rotation of the drilling rig. In various embodiments, the one or more operating parameters can be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. In various embodiments, the plurality of operating parameters from the one or more sensors can be processed with computer vision.

At block 3030, the process 3000 can include generating a report based at least in part on the strategy information and plurality of operating parameters. The report can be generated in various formats and layouts. The report can be generated just one time during an operation, or at various other intervals, for example including daily, hourly, or whenever the plurality of operating parameters changes. In various embodiments, the report generated may include an automated status, providing various readings reflecting the current conditions of the drilling operation. Such conditions may include, for example, current formation and deposit information, drilling speed and operation parameters, current slide conditions, and/or the status (on/off) of various auxiliary control systems (e.g., mud system as shown in FIG. 28). In various embodiments, the report may include a forecast of operating parameters, including, for example, zones and restriction areas. In various embodiments, the forecast may be a 3D forecast.

In various embodiments, the report may include a listing of all system configuration changes. Such configuration changes may be changes made manually by personnel associated with the drilling operation or may in addition or in the alternative include automated changes, such as those made by various automated or computerized drilling systems. The listing of changes may include changes made in a pre-set amount of time, such as the previous day or week, or may include changes made since the occurrence of a predetermined event, such as changes which have occurred since the last report was generated, since a certain drilling condition was changed, or since the beginning of the drilling operation.

In various embodiments, the report may include a depiction (such as a graphical or computer-generated depiction) which includes information regarding one or more of: offset historical performance, real-time performance, adjacent rig performance, or theoretical best-case performance. Such depictions can be displayed graphically or numerically (such as an automated image, graph, or table). The information depicted can be formatted for comparison purposes to understand a broader picture of the progress of the drilling operation compared to multiple benchmarks. In various embodiments, the report may include a depiction (such as a graphical or computer-generated depiction) which includes information of the lithology and/or anticipated changes in conjunction with application tools. In various embodiments, the report may include a depiction (such as a graphical or computer-generated depiction) which includes information of ECD/hole cleaning based in-part on all forms of cuttings tracking. For example, forms of cuttings tracking may include PWD, shaker vision, and volumetric measurement. Such forms of cuttings tracking provide drilling operation information to identify the hole cleaning status, which may be used for planning of hole cleaning timeline, or for example necessary equipment and personnel.

At block 3040, the process 3000 can include transmitting the report to an operator. The report can be transmitted by various means, including for example, wired or wireless transmittal, email, facsimile, uploading to a shared database or cloud-based storage system. Such a report can be formatted in various means, including for example, text and graphics within an email, a .pdf or word-processing file, or graphically through a spreadsheet (such as Microsoft Excel).

Although FIG. 30 shows example steps of process 3000, in some implementations, process 3000 can include additional steps, fewer steps, different steps, or differently arranged steps than those depicted in FIG. 30. Additionally, or alternatively, two or more of the steps of process 3000 can be performed in parallel.

FIG. 31 illustrates a flowchart for an example process for improved safety systems and methods for drilling operations. In some implementations, one or more process blocks of FIG. 31 may be performed by a drilling rig controller (e.g., controller 1000 of FIG. 10). In some implementations, one or more process blocks of FIG. 31 may be performed by another device or a group of devices separate from or including the controller 1000. Additionally, or alternatively, one or more process blocks of FIG. 31 may be performed by one or more components of device 1000, such as processor 1001, memory media 1010, input device 1008, output device 1009, bus 1002, instructions 1024A and 1024B, network adapter 1020, display adapter 1004, display 1005.

At block 3110, the process 3100 can include receiving a plurality of operating parameters from one or more sensors. The operating parameters can include one or more of a differential pressure, weight on bit, rate of penetration, and toolface, and rate of rotation of the drilling rig. In various embodiments, the one or more operating parameters can be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. In various embodiments, the plurality of operating parameters from the one or more sensors can be processed with computer vision.

At block 3120, the process 3100 can include determining a probability score of an unsafe condition based at least in part on the plurality of operating parameters. An unsafe condition can include, for example, risk of injury to personnel, the environment, or to drilling equipment. A probability of an unsafe condition may be determined based on a predetermined unsafe reading value from various sensors. For example, within the controller there may be one or several threshold values indicative of a high or severe value for a particular sensor. In various embodiments, multiple sensors recording the same or different parameters can be utilized to calculate one probability score of an unsafe condition. For example, in certain circumstances a single condition measured by a sensor may not in itself lead to a probability of an unsafe condition (e.g., rotation speed), but when measured in combination with one or more additional conditions may lead to a higher probability score of an unsafe condition (e.g., rotation speed and torque).

At block 3130, the process 3100 can include determining a severity score of the unsafe condition based at least in part on stored historical data. Not all unsafe conditions are of the same degree of severity. By, at least in part, appreciating historical data where similar operating parameters were present, the process 3100 can determine a severity score. For example, if historical data includes the same or similar operating parameters, the process 3100 can take into account the ultimate outcome of the historical data to determine what severity the unsafe condition possesses. For example, if a previous operation resulted in a failure due to the same or similar operating parameters that may result in a higher severity score than if historical data shows no problems occurring as a result of the operating parameters. Similarly, multiple sets of historical data, corresponding with a plurality of past occurrences, may be used in determining the severity score.

At block 3140, the process 3100 can include calculating an overall risk score based at least on the probability score and risk score. By combining at least, the probability score (of 3120) and the severity score (of 3130), an overall risk score can be calculated that may take into account both the likelihood of an unsafe condition and the severity of the unsafe condition. As such, the score appreciates both the probability of the unsafe condition but also the potential consequences of the unsafe condition, based on its severity.

At block 3150, when the overall risk score exceeds a risk threshold, the process 3100 can include implementing a mitigation strategy. In various embodiments, the mitigation strategy may include employing or deploying a safe mode configuration. In various embodiments, the mitigation strategy may include lockout for certain pre-defined drilling events. Such pre-defined drilling events, can prevent, for example that certain drilling procedures be utilized which may further elevate the overall risk score. In various embodiments, the mitigation strategy may include adjusting operations of the drilling operation. Such adjustments may be made at least in part based on the proximity of rig crews to the rig floor. Computer vision or other sensing means may be utilized to determine the proximity of rig crews (or other personnel) to the rig floor.

In various embodiments, the mitigation strategy may include employing a safety oversite mode or a plurality of safety oversight modes. Such safety oversite may allow for a remote operator to have increased visibility of the drilling operation. The increased visibility may allow the remote operator to monitor and/or control aspects of the drilling operation which generally are not in their purview outside of the safety oversite mode. This increased visibility may provide a mitigation strategy where more closely monitoring various parameters of the drilling operation helps to mitigate and reduce the overall risk score. In various embodiments, the mitigation strategy may include identifying and tracking one or more danger zones.

In various embodiments, the mitigation strategy may include determining whether protective equipment is being properly utilized. Such determination may include determination of personal protective equipment, or other safety devices generally present in the drilling operation. The determination of whether the protective equipment is being properly utilized may be determined by various sensors and/or by means of computer vision.

Although FIG. 31 shows example steps of process 3100, in some implementations, process 3000 can include additional steps, fewer steps, different steps, or differently arranged steps than those depicted in FIG. 31. Additionally, or alternatively, two or more of the steps of process 3000 can be performed in parallel.

FIG. 32 illustrates a flowchart for an example process 3200 for determining mud weight properties for drilling operations. In some implementations, one or more process blocks of FIG. 32 may be performed by a drilling rig controller (e.g., controller 1000 of FIG. 10). In some implementations, one or more process blocks of FIG. 32 may be performed by another device or a group of devices separate from or including the controller 1000. Additionally, or alternatively, one or more process blocks of FIG. 30 may be performed by one or more components of device 1000, such as processor 1001, memory media 1010, input device 1008, output device 1009, bus 1002, instructions 1024A and 1024B, network adapter 1020, display adapter 1004, display 1005.

At block 3210, the process 3200 can include receiving strategy information from a drilling roadmap. The drilling roadmap can provide formation and deposit information. The drilling roadmap information can be stored in a memory. In various embodiments, the drilling roadmap information can be downloaded from storage system (e.g., a cloud-based storage system) via a network (e.g., the Internet). In various embodiments, the drilling roadmap information can be received via a non-transitory computer readable medium (e.g., a flash drive, a hard drive, or another medium for storing data). In various embodiment, the drilling roadmap information can be entered manually by a driller.

At block 3220, the process 3200 can include receiving a plurality of operating parameters from one or more sensors. The operating parameters can include one or more of a differential pressure, weight on bit, rate of penetration, and toolface, and rate of rotation of the drilling rig. In various embodiments, the one or more operating parameters can be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. In various embodiments, the plurality of operating parameters from the one or more sensors can be processed with computer vision. The operating parameters may include bit information. In various embodiments, the process 3200 can include determining bit TFS for one or more operating conditions to verify bit cleaning and cooling.

At block 3230, the process 3200 can include receiving a selection of one or more mud weight properties. Mud weight (or mud density) can be used to control hydrostatic pressure in a wellbore and may prevent unwanted flow into the well. Mud weight properties above a certain threshold can cause a loss in circulating. Mud weight properties can be based at least in part on formation change or operation change. In various embodiments, the process 3200 can further include identifying a formation change or an operations change. At least based in part on the formation change or operations change, one or more mud weight properties may be determined. In some embodiments, a recommendation may be provided to an operator based on the one or more mud weight properties.

At block 3240, the process 3200 can include generating one or more instructions based at least in part on the drilling roadmap, the plurality of operating parameters, and the one or more mud weight properties. Such instructions may include parameters discussed for example in FIG. 28, such as type of mud additive to add to the drilling mud, the amount of mud additive to add to the drilling mud, the rate at which to introduce the mud additive to the drilling mud, and the timing of when to introduce of the mud additive to the drilling mud. The instructions may be more specific to the physical components of the drilling operation or of physical attributes of the mud additive. For example, the instructions may include feed rate, a chopper rate, among other things to control the size and consistency of individual additives being added to the drilling mud. In various embodiments, the instructions may include specific qualities of the mud additive, such as fiber size, density, and/or granular particulate size. In various embodiments, the instructions may include instructions for operation of the dry feeders, mud additive system, and of other aspects of the system described for example in FIG. 28.

At block 3250, the process 3200 can include transmitting the one or more instructions to a drilling controller. The one or more instructions may be transmitted using any of various communication means, such as wired or wireless means.

At block 3260, the process 3200 can include drilling according to the one or more instructions. Such drilling may be initiated manually by an operator, semi-automatically by means of a recommendation or proposed computer provided drilling operation, or automatically without manual input from an operator.

In various embodiments, the process 3200 may include detecting one or more operating parameters indicative of sliding operations. In various embodiments, based on the detecting of one or more operating parameters indicative of sliding operations, providing a recommendation (to an operator, for example) to add an additive, such as a Teflon bead additive, for example, to the drilling operation in anticipation of sliding operations. Parameters to indicate a sliding operation may be current or future parameters, and may be based on, for example, time, MD, WOB, ROP, etc.

In various embodiments, the process 3200 may include detecting one or more operating parameters indicative of lost circulation zones. In various embodiments, based on detecting the one or more operating parameters indicative of lost circulation zones, the process 3200 may further include providing a recommendation of lost circulation materials (LCM) into the mud system. Parameters indicative of lost circulation zones may include, for example, a detection in signification changes to the condition and amount of drilling mud. Such a recommendation to introduce lost circulation materials into the mud system may be provided to an operator, for example, for the purpose of manual introduction of lost circulation materials or for introduction by an automated or semi-automated system (such as the mud analysis and control system 2824, discussed in FIG. 28). In some embodiments, such a recommendation can be provided directly to the mud analysis and control system for an automated adjustment in LCM.

In various embodiments, the process 3200 may include adjusting one or more of the operating parameters proactively in conjunction with the borehole cleaning status. By adjusting parameters of the drilling operation in alignment or consideration of the borehole cleaning status, timing and efficiency in the drilling operation can be optimized to allow minimal downtime and reduced delays in maintenance and cleaning operations. In some embodiments, it may be determined that changing or adjusting one or more operating parameters allows for a preferred schedule for planning of borehole cleaning, based at least in part on maintenance schedules, crew availability, and targeted deadlines.

Although FIG. 32 shows example steps of process 3200, in some implementations, process 3000 can include additional steps, fewer steps, different steps, or differently arranged steps than those depicted in FIG. 32. Additionally, or alternatively, two or more of the steps of process 3200 can be performed in parallel.

FIG. 33 illustrates a flowchart for an example process 3300 for improving logistics processes for drilling operations. In some implementations, one or more process blocks of FIG. 33 may be performed by a drilling rig controller (e.g., controller 1000 of FIG. 10). In some implementations, one or more process blocks of FIG. 33 may be performed by another device or a group of devices separate from or including the controller 1000. Additionally, or alternatively, one or more process blocks of FIG. 29 may be performed by one or more components of device 1000, such as processor 1001, memory media 1010, input device 1008, output device 1009, bus 1002, instructions 1024A and 1024B, network adapter 1020, display adapter 1004, display 1005.

At block 3310, the process 3300 can include receiving strategy information from a drilling roadmap. The drilling roadmap can provide formation and deposit information. The drilling roadmap information can be stored in a memory. In various embodiments, the drilling roadmap information can be downloaded from storage system (e.g., a cloud-based storage system) via a network (e.g., the Internet). In various embodiments, the drilling roadmap information can be received via a non-transitory computer readable medium (e.g., a flash drive, a hard drive, or another medium for storing data). In various embodiment, the drilling roadmap information can be entered manually by a driller.

At block 3320, the process 3300 can include receiving a plurality of operating parameters from one or more sensors. The operating parameters can include one or more of a differential pressure, weight on bit, rate of penetration, and toolface, and rate of rotation of the drilling rig. In various embodiments, the one or more operating parameters can be received from at least one of an automated application to include a geosteering tool, a computer vision tool, and an iterative well planning tool. In various embodiments, the plurality of operating parameters from the one or more sensors can be processed with computer vision.

At block 3330, the process 3300 can include comparing the plurality of operating parameters to one or more sequenced tasks in the drilling roadmap. By comparison of the operating parameters to the sequenced tasks in the drilling roadmap, the process 3300 can compare the planned tasks in the roadmap to the actual conditions of the drilling operation. From this information, a difference between the proposed and actualized drilling operation can be obtained.

At block 3340, the process 3300 can include generating one or more instructions based at least in part on the comparing the plurality of operating parameters to one or more sequenced tasks in the drilling roadmap. The one or more instructions can be stored in the memory. In some embodiments, comparing a planned roadmap to operating parameters of the drilling operation can provide insight on differences or deviations from the roadmap or planned schedule. In some embodiments, instructions can be generated which provide means to adjust the operating parameters to, for example, better conform with the strategy information of the roadmap.

In various embodiments, the one or more instructions may provide real-time updates to anticipated project management events. Such project management events may include, for example, scheduling of personnel for anticipated upcoming tasks, ordering supplies and equipment for tasks (e.g., cement trucks, ordering a BHA, raw materials), aligning maintenance tasks with one another, etc.

In various embodiments, the process 3300 can include adjusting one or more drilling parameters based at least in part on logistics limitations. As discussed herein, such limitations can be of a variety of forms, and may include any required aspect of the drilling operation, such as personnel, equipment, etc. For example, in the case of casing of a drill site, a logistic limitation may be the unavailability a cement truck, in which case the process 3300 can adjust drilling parameters to slow down the drilling operation to effectively delay drilling until a cement truck is available for casing.

In various embodiments, the process 3300 can include scheduling one or more logistic events based at least in part on progress through the one or more sequenced tasks in the drilling roadmap. Some logistic events may be more beneficial if performed prior or subsequent to a particular sequenced task in the drilling roadmap, such that performing them in a non-preferred order may result in lost efficiency, time, energy, or cost. In some embodiments, logistic events, including maintenance or scheduled downtime, for example, can be aligned such that the sequence of tasks provides increased efficiency.

In various embodiments, the process 3300 can include tracking a number of crews present at a drilling site in conjunction with one or more drilling activities being performed. Such tracking may be either current or future tracking, such that the process 3300 may track current personnel at a drilling site, or track crews which will be present at a future time. Such tracking can be performed, for example, with computer vision, time schedules, etc.

In various embodiments, the process 3300 can include scheduling one or more roaming crews at least in part on rig status. Rig status can include, but is not limited to, current operating parameters, formation information, strategy information, etc. Certain rig statuses (both currently encountered and future predicted statuses) may require varying crew personnel. By having too few crew members in a drilling operation, a task may not be capable of being performed, or may lead to delays and waste. Conversely, having more crew than is necessary for a particular task at a drilling operation may result in idle crew members and lost efficiency. As such, in some embodiments, the process 3300 may include scheduling roaming crews to manage efficiency in workflow allocation and personnel assignments.

At block 3350, the process 3300 can include transmitting the one or more instructions to a scheduling module. The instructions can be transmitted via wired or wireless communication systems and methods.

Although FIG. 33 shows example steps of process 3300, in some implementations, process 3000 can include additional steps, fewer steps, different steps, or differently arranged steps than those depicted in FIG. 33. Additionally, or alternatively, two or more of the steps of process 3300 can be performed in parallel.

FIG. 34 illustrates a controller located remotely from the drilling rig at a central control location for multiple drilling rigs. FIG. 34 may include any of the embodiments as described in U.S. Pat. No. 9,157,309, issued on Oct. 13, 2015, entitled “System and Methods for Remotely Controlled Surface Steerable Drilling,” which is hereby incorporated by reference in its entirety and for all purposes.

FIG. 34 illustrates an embodiment wherein the rig control and exchange platform system 1100, rather than being located at the drilling rig 3402, is located at a central control site 3404 that may be remote from the location of the rig. The rig control and exchange platform system 1100 can be located at the central control site 3404 and can be programmed to allow operators at the site 3404 to monitor and/or control drilling operations for one or more drilling rigs 3402 simultaneously while the rigs 3402 are each drilling a well and may be engaged in different drilling operations, via various types of communication links 3406. Use of the rig control and exchange platform system 1100 at a central control site 3404 allows for centralization of control and data storage functions at a single location to enable more cost effective monitoring and/or control of the drilling process.

According to various embodiments, a drilling roadmap may be provided to rig control and exchange platform system 1100 and used to monitor and/or control drilling operations. The drilling roadmap may be updated by the rig control and exchange platform system 1100 from time to time as the well is being drilled, based on the information obtained during drilling. An updated drilling roadmap generated by the rig control and exchange platform system 1100 may be transmitted from the central control site 3404 to the one or more drilling rigs 3402 to whom the updated roadmap is intended (i.e., the particular rig drilling the well that is the subject of the updated roadmap).

According to some embodiments, rig control and exchange platform system 1100 may be programmed to automatically generate an improvement to the drilling roadmap based at least in part on changes to the drilling roadmap provided by the operator. For example, in response to receiving an updated drilling parameter from an operator (e.g., ROP, WOB, a new auto driller setpoint, etc.), the system 1100 can be programmed to generate and output a recommendation or otherwise suggest a different plan or a modification to the drilling roadmap as an update thereof. One or more drilling parameters, configurations or settings of the drilling roadmap may be modified in such an update.

The rig control and exchange platform system 1100 may be configured to automatically generate one or more new drilling instructions or updated parameters to implement an updated drilling plan and then send appropriate control signals to one or more control systems of the drilling rig to drill in accordance with such instructions and/or parameters. According to various embodiments, an operator may remain in control of the drilling rig. In such a mode of operation, the rig control and exchange platform system 1100 may send one or more signals to alert the operator of the suggested instructions and/or parameters, but the operator ultimately may need to approve or veto the implementation of such instructions and/or parameters.

In an embodiment, the rig control and exchange platform system 1100 may be coupled to one or more other computer systems that are configured to receive information regarding the drilling of a well, generate a report of the drilling operations over a previous time period, and then send the report and/or messages regarding the same to one or more stakeholders, such as described in more detail in co-pending U.S. patent application Ser. No. 18/477,323, filed in Jun. 25, 2015, entitled “Systems and Methods for Drilling Operations”, which is hereby incorporated by reference in its entirety as if fully set forth herein.

In one embodiment, the rig control and exchange platform system 1100 generates an updated drilling plan, which is then provided to a system for generating a video report. The updated drilling roadmap may be included in the video report (in addition to any or all of the information, graphics, video, animation, and audio information included in the video report as set forth in the pending patent application Ser. No. 18/477,323) as a proposed alternative to the existing drilling plan, so that the recipients of the video report can see the proposed changes to the existing drilling plan that are proposed to be implemented with the updated drilling roadmap. In another embodiment, the information included in the updated drilling roadmap provided by the rig control and exchange platform system 1100 can be used to automatically generate one or more animations, voice or audio descriptions, graphics, or the like, such as with the systems and methods described in more detail in the pending patent application Ser. No. 18/477,323. Such graphics, animations, videos, and/or audio information may be included in the video report provided to recipients thereof so that they easily and quickly understand the updated roadmap and the proposed changes to the existing drilling plan.

FIG. 35 illustrates a schematic for providing information and software updates in a drilling rig ecosystem. According to various embodiments described herein, a plurality of drilling rigs may be controlled by a central control site at a location remote from at least one of the plurality of drilling rigs. Furthermore, each of the plurality of drilling rigs may be running a different version of one or more software programs intended to receive and provide information, signals and instructions to one or more computer systems such as rig control and exchange platform system 1100. In some circumstances, an older version of the software may not be able to perform all of the operations that a newer release or version of the software is configured to perform. Accordingly, embodiments of the present disclosure include a controller 3502 (which may comprise rig control and exchange platform system 1100) in communication with a rig controller 3504, and the two exchange a data stream 3506. The controller 3502 may determine what version(s) of software each drilling rig has (e.g., what modules the software includes, what actions the rig's software is or is not capable of, etc.) by analyzing the data stream 3506 from the rig's controller 3504. Based at least in part on the determination, the controller 3502 may be configured to transmit only a limited set of drilling instructions and/or modified drilling parameters to the rig; in effect, the controller 3502 determines from the data stream 3506 the version or release of the software that is running on the rig controller 3504, and adjusts the provision of drilling instructions and/or parameters for an update to the drilling roadmap accordingly to those that the rig is able to handle and implement. In some embodiments, the controller 3502 may be configured to determine which, if any, software updates are to be provided to a rig, and then push those software updates to the rig via the data stream 3506.

In some embodiments, the controller 3502 queries the rig controller 3504 and determines software status of the rig control system (not shown). A program logic controller (PLC) may be part of the rig controller 3504 and may enable operations received from rig control and exchange platform system 1100 to proceed or may block such operations from proceeding in response to a determination that the software is not capable of supporting one or more of such operations. In at least some embodiments, the controller 3502 determines a version of the software running on the rig controller 3504 and, in response to determining the software is out of date, updates the software accordingly.

FIG. 36 illustrates a schematic of a user interface useful for improved drilling operations. In particular, FIG. 36 illustrates a GUI of a rig control and exchange platform system 1100 as disclosed herein for monitoring the drilling of a well by a rig. The interface 3600 may include one or more tabs 3602 for altering a viewing mode (e.g., displays) of the drilling roadmap. One or more tabs 3602 may be active at any given time. The interface 3600 may also include various drilling parameters 3604 (e.g., WOB, torque, ROP, differential pressure, top drive speed in rpms, top drive torque, etc.) and each parameter 3604 may indicate what version of software is run by the rig for that parameter 3604. For example, each version of software running on the rig may be indicated by a different color for the affected drilling parameters 3604 in at least some embodiments. Each parameter 3604 may be enabled or not enabled for operation by the rig as indicated by box 3606 and associated measurements may be visible to a user. According to some embodiments, each row of the interface 3600 corresponds to a distinct segment or portion of a well being drilled (or previously drilled) and an enabled indicator may be used to record whether the rig control and exchange platform system 1100 was used for the respective section or portion of the well.

The interface 3600 as shown in FIG. 36 further includes a digital roadmap active indicator 3608 for indicating when the rig control and exchange platform system 1100 is running and a driller override indicator 3610 is provided for indicating that the driller as operator of the rig has overridden the operation of the rig drilling operations by rig control and exchange platform system 1100. Further shown in FIG. 36, the interface 3600 may include identifying information about the well 3612 and time stamp information 3614 associated with the information presented at a given time. An operator may further include comments 3616 describing any modifications made.

According to some embodiments, interface 3600 may include various dialogue warnings in response to determining one or more of the parameters 3604 is using a version of software that does not support one or more operations of the software running on rig control and exchange platform system 1100

The above description of exemplary embodiments of the disclosure has been presented for the purposes of illustration and description. It is not intended to be exhaustive or to limit the disclosure to the precise form described, and many modifications and variations are possible in light of the teaching above. The embodiments were chosen and described in order to best explain the principles of the disclosure and its practical applications to thereby enable others skilled in the art to best utilize the disclosure in various embodiments and with various modifications as are suited to the particular use contemplated.

All publications, patents, and patent applications cited herein are hereby incorporated by reference in their entirety for all purposes.

SYSTEMS AND TECHNIQUES FOR AUTOMATED DRILLING

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CPC

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