Methods and systems for well spacing

Abstract

A method for well planning for optimized production results may include generating, by a computer system, a first arrangement of a plurality of well slot positions, defining, by the computer system, a plurality of nested perimeters of the first arrangement of the plurality of well slot positions, determining, by the computer system, an initial kick off direction for each well slot position in a perimeter of the plurality of nested perimeters, and rearranging, by the computer system, at least two well slot positions in the perimeter of the plurality of nested perimeters.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application is related to U.S. Published application Ser. No. 17 / 656,223, issued as U.S. Pat. No. 12,136,054, entitled “Systems and Methods of Iterative Well Planning for Optimized Results,” issued on Nov. 5, 2019, which is hereby incorporated by reference in its entirety.BACKGROUNDField of the Disclosure

[0002] The present disclosure provides systems and methods useful for well planning for optimized production results. The systems and methods can be computer-implemented using processor executable instructions for execution on a processor and can accordingly be executed with a programmed computer system.Description of the Related Art

[0003] Well planning and the optimal spacing of wells on pads and platforms are critical for maximizing the extraction of minerals while minimizing operational costs. For instance, closely spacing wells can improve the efficiency of mineral extraction, but wells that are spaced too closely can cause collisions and / or interference between adjacent wells. Well collisions and / or interference can have catastrophic consequences, including reduced mineral extraction and increased operational challenges, ultimately impacting the efficiency and profitability of mineral extraction.

[0004] To minimize the risk of well collisions and / or interference, conventional well spacing methods utilize a calculated separation factor to determine the well spacing and well layout on pads and platforms. However, these methods are suboptimal when the separation factor falls below a certain threshold, often requiring shutting down adjacent wells while drilling, ultimately impacting the efficiency and profitability of mineral extraction.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] 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:

[0006] FIG. 1 depicts a drilling system for drilling a borehole;

[0007] FIG. 2 depicts a drilling environment including the drilling system for drilling a borehole;

[0008] FIG. 3 depicts a borehole generated in the drilling environment;

[0009] FIG. 4 depicts a drilling architecture including the drilling environment;

[0010] FIG. 5 depicts an image of a series of well trajectories from a pad generated in the pre-planning phase;

[0011] FIG. 6 depicts a computer-generated arrangement of well slot positions laterally spaced on a drilling surface;

[0012] FIG. 7 depicts a computer-generated arrangement of well slot positions being further defined into a plurality of nested perimeters;

[0013] FIG. 8 depicts an alternative computer-generated arrangement of well slot positions being further defined into a plurality of nested perimeters;

[0014] FIG. 9 depicts a kick off depth assigned to each well slot position in a perimeter;

[0015] FIG. 10 depicts a kick off depth assigned to each well slot position in the plurality of nested perimeters;

[0016] FIG. 11 depicts an overhead view of a drilling target configuration for each well slot position in the plurality of nested perimeters;

[0017] FIG. 12 depicts an initial kick off direction assigned to each well slot position in the plurality of nested perimeters;

[0018] FIG. 13 depicts an initial kick off direction assigned to each well slot position in an outermost perimeter of the plurality of nested perimeters;

[0019] FIG. 14 depicts an initial kick off direction assigned to each well slot position in an intermediate perimeter of the plurality of nested perimeters;

[0020] FIG. 15 depicts an initial kick off direction assigned to each well slot position in an innermost perimeter of the plurality of nested perimeters;

[0021] FIG. 16 depicts a nudge angle assigned to each well slot position in the plurality of nested perimeters;

[0022] FIG. 17 depicts an initial kick off direction and a nudge angle assigned to each well slot position in the plurality of nested perimeters;

[0023] FIG. 18 depicts cropped and uncropped portions of the projected well paths for each well slot position in the plurality of nested perimeters; and

[0024] FIG. 19 depicts, from an alternate perspective, cropped and uncropped portions of the projected well paths for each well slot position in the plurality of nested perimeters.

[0025] FIG. 20 depicts a block diagram of various operations that can be performed in different phases of well planning.DESCRIPTION OF PARTICULAR EMBODIMENT(S)

[0026] In the following description, details are set forth by way of example to facilitate discussion of the disclosed subject matter. It is noted, however, that the disclosed embodiments are exemplary and not exhaustive of all possible embodiments.

[0027] Well planning and drilling a well typically involves a substantial amount of human decision-making. 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 drilling plan, and how to handle issues that arise during drilling. In particular, wells must be optimally spaced to maximize the extraction of minerals while minimizing operational costs resulting from various errors, such as well collisions and / or well interference. However, even the best geologists and drilling engineers perform some guesswork due to various factors, including, among other things, the existence of adjacent wells and / or other nearby pads or platforms, positioning uncertainties as to a wellbore's location (and that of nearby wellbores), errors and uncertainties associated with well surveying, and deviations of the actual well path from the original planned well path during drilling. Consequently, a multitude of input information and other factors may affect a planning and / or drilling decision being made by a human operator or specialist, such that the amount of information may overwhelm the cognitive ability of the human to properly consider and factor into the decision. Furthermore, the quality or the error involved with the planning and / or drilling decision may improve with larger amounts of input data being considered, for example, such as well spacing data from a large number of wells spaced on a pad or platform. For these reasons, human specialists may be unable to achieve desirable planning and / or drilling decisions, particularly when such decisions are made under time constraints, such as during drilling operations when continuation of drilling is dependent on the drilling decision and, thus, the entire drilling rig waits idly for the next drilling decision. Furthermore, human decision-making for drilling decisions can result in expensive mistakes, such as well collisions and / or interference, because drilling errors can add significant cost to drilling operations. In some cases, drilling errors may permanently lower the output of a well, resulting in substantial long term economic losses due to the lost output of the well.

[0028] Accordingly, methods and systems are disclosed herein for well planning for optimized production results that balance decisions to minimize costs and maximize expected production in order to maximize the overall expected value of the well.

[0029] 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.

[0030] 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.

[0031] 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.

[0032] In drilling system 100, drilling equipment 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, a positional / rotary control system, a fluid circulation control system, and a sensor system. 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 may be for obtaining sensor data about the drilling operation and drilling system 100, including the downhole equipment. For example, sensor system 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 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 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.

[0033] 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.

[0034] 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.

[0035] In operation, steering control system 168 may be accessible via a communication network, 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.

[0036] 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.

[0037] 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.

[0038] 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. 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.

[0039] 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 FIG. 4). 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.

[0040] 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. 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.

[0041] 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, 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.

[0042] 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.

[0043] 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.

[0044] 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.

[0045] 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.

[0046] 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 that control drilling equipment, see also FIG. 2). Drilling rig 210 may provide feedback information using rig controls 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 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.

[0047] Referring now to FIG. 2, 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. 2, 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.

[0048] 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. 2 extending through strata layers 268-1 and 270-1, while terminating in strata layer 272-1. Accordingly, as shown, borehole 106 does not extend or reach underlying strata layers 274-1 and 276-1. A target area 280 specified in the drilling plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1. 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, that 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 272-1. 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 172 as far as possible, target area 280 may be defined as strata layer 272-1 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.

[0049] Also visible in FIG. 2 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 268-1, 270-1, 272-1, 274-1, and 276-1 are unshifted by fault line 278. On the other side of fault line 278, strata layers 268-2, 270-3, 272-3, 274-3, and 276-3 are shifted downwards by fault line 278.

[0050] 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. 2, directional drilling may be used to drill the horizontal portion of borehole 106, which increases an exposed length of borehole 106 within strata layer 272-1, and which may accordingly be beneficial for hydrocarbon extraction from strata layer 272-1. 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 172. As such, directional drilling may involve multiple vertical adjustments that complicate the trajectory of borehole 106.

[0051] Referring now to FIG. 3, 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 318 of borehole 106 may be started from a vertical portion 310. In order to make the transition from vertical to horizontal, a curve may be defined that specifies a so-called “build up” section 316. Build up section 316 may begin at a kick off point 312 in vertical portion 310 and may end at a begin point 314 of horizontal portion 318. The change in inclination in build up section 316 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 every one hundred feet drilled. The build rate for a particular build up section may remain relatively constant or may vary.

[0052] 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 string 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).

[0053] 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 310 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 build up section 316.

[0054] 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.

[0055] 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 2, 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.

[0056] Specifically, in a region 401-1, 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 401-2, a drilling hub 410-2 may serve as a remote processing resource for drilling rigs 210 located in region 401-2, 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.

[0057] 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.

[0058] 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 center 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.

[0059] 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.

[0060] In some embodiments, the formulation of a drilling plan for drilling a well with 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.

[0061] 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.

[0062] Well planning is a crucial aspect of drilling operations, particularly in resource-intensive areas such as unconventional plays and offshore developments. A well plan may be developed through a comprehensive process that integrates geological, engineering, and regulatory considerations to optimize the design and trajectory of each wellbore. For example, this process may include a subsurface analysis to identify resource targets, followed by the creation of a plan that specifies the well path, drilling parameters, and operational logistics. This plan may guide the drilling process, ensuring that the wellbore is drilled safely and efficiently to access the intended resource zone. In multi-well scenarios on pads and platforms, establishing well boundaries is essential to prevent conflicts and ensure compliance with legal and technical requirements. For example, leasing agreements may define the geographic area within which operators are authorized to drill, and well paths therefore must remain within these boundaries to avoid legal disputes or trespass claims. Additionally, the close proximity of wells on a single pad or platform raises concerns about collisions and interference between wellbores.

[0063] Consequently, well planning and the optimal spacing of wells on pads and platforms are critical for maximizing the extraction of minerals while minimizing operational costs. For instance, closely spacing wells can improve the efficiency of mineral extraction, but wells that are spaced too closely can cause collisions and / or interference between adjacent wells. Collisions may occur when wellbores are drilled too closely together, potentially resulting in mechanical contact during drilling. For example, in multi-well pads, insufficient spacing between trajectories can lead to a collision between a drilling assembly and an existing wellbore, causing equipment damage, well control issues, or even blowouts. Additionally, interference may occur when wells are spaced so closely that their operations or reservoir performance negatively impact one another. For example, in unconventional plays, hydraulic fracturing in one well can create “frac hits” on adjacent wells, damaging their casing or reducing production efficiency by redistributing pressure and fluids. Similarly, overlapping drainage areas in a reservoir due to poor spacing can result in premature pressure depletion, lowering the recovery factor of hydrocarbons. Thus, collisions and interference can cause significant safety, operational, and financial consequences, emphasizing the importance of precise well planning and anti-collision analysis to optimize spacing and prevent such risks.

[0064] To minimize the risk of well collisions and / or interference, conventional well spacing methods utilize a calculated separation factor to determine the well spacing and well layout on pads and platforms. However, these methods are suboptimal when the separation factor falls below a certain threshold, often requiring shutting down production from previously drilled adjacent wells while drilling a wellbore, ultimately impacting the efficiency and profitability of mineral extraction. According to methods and systems of the present disclosure, well planning for optimized planning of well spacing and drilling disclosed herein may enable a well spacing layout for a well pad for maximal production, minimizing costs associated with wells and reducing risk associated with the wells. FIG. 5 depicts an image of a series of exemplary well trajectories from a pad generated in the pre-planning phase.

[0065] One optimization, amongst others, that can be performed in the site planning phase for well spacing is the actual well trajectory. One method for optimizing the planned well trajectory in the site planning phase may perform the following operations:

[0066] Minimize a collision risk between wells and the lease boundary and maximize the overall Production Probability Percentages (PPP) by adjusting the well spacing;

[0067] Adjust the kick off depth over a window above and below the original kick off depth;

[0068] Adjust the kick off rate over a window above and below the original kick off rate;

[0069] Adjust the kick off direction within a window left and right of the original kick off direction;

[0070] Adjust drilling parameters for other well zones in the well plan before adjusting the drilling parameters for the landing curve;

[0071] Minimize collision risk between the trajectory of the well being drilled and the trajectory of wells previously analyzed;

[0072] Rejoin the well trajectory to the planned or original intended landing curve; and

[0073] Repeat the above operations for every row / column, slot-to-target combination to ensure that the planned or original intended row / column-to-target does not also need to be reviewed.

[0074] FIG. 6 depicts a computer-generated arrangement 600 of well slot positions 602 laterally spaced on a drilling surface 604. Generally, a well slot position 602 corresponds to a specific location on a drilling surface 604, such as a pad or platform, where a well is planned or drilled. For example, in offshore drilling, well slot positions 602 can be part of a platform's structural design, where the slots correspond to conductor pipes that guide the wellbore through the seabed. The drilling surface 604 may correspond to a pad, platform, or any other suitable surface for drilling. The well slot positions 602 may be arranged in a grid pattern, as shown in FIG. 6, or any other type of arrangement, including but not limited to circular arrangements, linear arrangements, cluster arrangements, or other geometric, irregular, or custom arrangements. The non-limiting exemplary layout depicted in FIG. 6 contains 8 columns and 6 rows. The number of well slot positions 602 generated may vary depending on the requirements of the particular application, and thus may be customized for the particular application.

[0075] FIG. 7 depicts a computer-generated arrangement 600 of well slot positions 602 being further defined, by a computer system, into a plurality of nested perimeters 700. A perimeter in the plurality of nested perimeters 700 may be defined by a subset of adjacently successive well slot positions 602 that form a loop (with the exception of the innermost perimeter 704, which may not necessarily form a loop, as discussed later). For example, as shown in FIG. 7, an outermost perimeter 702 may be defined by a subset of adjacently successive well slot positions 602 that form the outer boundary of the arrangement 600 of well slot positions 602. Inner perimeters may be similarly defined in a similar manner, and the innermost perimeter 704 may define a well center 706 such that the well center 706 may be the center point of the innermost perimeter 704. However, the well center 706 may also be defined as the center point of the arrangement 600 of well slot positions 602, the center point of the drilling surface (shown in FIG. 6), or any other suitable point. Moreover, the plurality of nested perimeters 700 may be defined simultaneously, or they may be defined sequentially using any suitable order for efficiently and effectively defining the nested perimeters 700. For example, in some embodiments, it may be preferable to define the outermost perimeter 702 first, followed the next inwardly successive perimeter, until the innermost perimeter 704 is defined. However, other orders may also be utilized, and in other embodiments, the innermost perimeter 704 may be defined first, followed the next outwardly successive perimeter, until the outermost perimeter 702 is defined. Additionally, as shown by comparing FIG. 7 with FIG. 8, the resulting shapes of the nested perimeters 700 will vary depending on the number of well slot positions 602 and arrangement 600 generated. For example, as will be made apparent in FIG. 8, if the number of rows or columns is odd, the innermost perimeter 704 may form a different shape (other than a loop), such as a line.

[0076] FIG. 8 depicts an alternative computer-generated arrangement 800 of well slot positions 802 being further defined, by a computer system, into a plurality of nested perimeters 804. The arrangement 800 includes 8 columns and 7 rows. The plurality of nested perimeters 804 may be defined in the same or similar manner as described above. However, in FIG. 8, the number of well slot positions 802 and the arrangement 800 generated are different than in FIG. 7, and thus the resulting shapes of the nested perimeters 804 are also different. Notably, due to the number of well slot positions 802 and arrangement 800 generated, the innermost perimeter 806 defining the well center 808 does not form a loop, and thus may form a different shape, such as a line.

[0077] FIG. 9 depicts a kick off depth 900 assigned, by a computer system, to each well slot position 902 in a perimeter 904. Generally, each kick off depth 900 may correspond to a specific depth at which a wellbore is intentionally deviated from the vertical to begin drilling at an angle. The kick off depth 900 may be determined via various methods that consider geological, geophysical, and operational factors to ensure efficient and cost-effective well trajectories. For example, target location and trajectory requirements, including the step-out distance and build rate necessary to reach the objective, may be defined. Geological and formation data, such as seismic surveys and geological studies, may be analyzed to map subsurface features such as faults, salt domes, and pressure zones, while also evaluating formation properties such as rock strength, pore pressure, and fracture gradients to identify stable zones for the kickoff point. The casing design and well integrity parameters may also be reviewed to ensure the kickoff depth 900 aligns with casing setting depths and stabilizes the wellbore, typically placing the kickoff point below the surface casing shoe. Computerized systems may be utilized to simulate well trajectories by inputting geological, geophysical, and operational data into advanced modeling software, which processes parameters such as formation mechanics and directional drilling constraints to recommend optimized kick off depths 900. Operational and tool constraints, including the capabilities of directional drilling tools and budgetary considerations, may be evaluated to confirm the feasibility of the recommended kick off depth 900. Wellbore stability factors, such as drilling fluid design and pressure management, may also be considered to ensure the kickoff depth 900 is located in a stable zone, minimizing risks like collapse or instability. Regulatory and environmental compliance may be verified, ensuring the selected kick off depth 900 adheres to local laws and obtaining necessary approvals if required. Collaboration with geologists, drilling engineers, and other stakeholders often further refines the selected kick off depth 900, ensuring its practicality and effectiveness.

[0078] As noted earlier, well slot positions 902 may correspond to specific locations on a drilling surface (shown in FIG. 6) where wells are planned or drilled. Thus, adjacent well slot positions 902 (corresponding to adjacent wells) may be assigned different kick off depths 900 to avoid adjacent wells kicking off at the same depth. For example, as shown in FIG. 9, kick off depths 900 may be assigned in an alternating fashion to each well slot position 902 in the perimeter 904, alternating between a first kick off depth 906 and a second kick off depth 908, with the first kick off depth 906 being greater than the second kick off depth 908. Additionally, kick off depths 900 may be assigned in any other fashion such that adjacent well slot positions 902 are assigned different kick off depths 900.

[0079] FIG. 10 depicts a kick off depth 1000 assigned, by a computer system, to each well slot position 1002 in the plurality of nested perimeters 1004. As explained earlier, adjacent well slot positions 1002 in each perimeter 1004 may be assigned different kick off depths 1000 to avoid adjacent well slot positions 1002 kicking off at the same depth. The kick off depth 1000 assigned to each well slot position 1002 in the plurality of nested perimeters 1004 may also increase with each inwardly successive perimeter. For example, as shown in FIG. 10, kick off depths 1000 may be assigned in an alternating fashion to each well slot position 1002 in the outermost perimeter 1006, alternating between a first kick off depth 1008 and a second kick off depth 1010, with the first kick off depth 1008 being greater than the second kick off depth 1010. Kick off depths 1000 may also be assigned in an alternating fashion to each well slot position 1002 in the second most outer perimeter 1012, alternating between a third kick off depth 1014 and a fourth kick off depth 1016, with the third kick off depth 1014 being greater than the second kick off depth 1016, and the third kick off depth 1014 and the second kick off depth 1016 being greater than the first kick off depth 1008 and the second kick off depth 1010. Kick off depths 1000 may be assigned in a similar fashion to the well slot positions 1002 of each inwardly successive perimeter 1004, until kick off depths 1000 have been assigned to each well slot position 1002 of the plurality of nested perimeters 1004. As shown in FIG. 10, assigning kick off depths 1000 in this fashion will result in the adjacent well slot positions 1002 in each perimeter 1004 being assigned different kick off depths 1000, and the kick off depth 1000 increasing with each inwardly successive perimeter.

[0080] However, kick off depths 1000 may be assigned in using other suitable methods, and are not necessarily limited to the method discussed and illustrated in FIG. 10. As noted earlier, kick off depths 1000 for each perimeter 1004 may be assigned in any fashion such that adjacent well slot positions 1002 are assigned different kick off depths 1000, and are not necessarily limited to alternating kick off depths 1000. Additionally, kick off depths 1000 may be assigned for each perimeter 1004 simultaneously, or they may be assigned sequentially using any suitable order for efficiently and effectively assigning kick off depths 1000 to each well slot position 1002 in the plurality of nested perimeters 1004. For example, in some embodiments, kick off depths 1000 may be assigned to well slot positions 1002 in the outermost perimeter 1006 first, followed by the next inwardly successive perimeter, until kick off depths 1000 are assigned to well slot positions 1002 in the innermost perimeter 1018. In other embodiments, kick off depths 1000 may be assigned to well slot positions 1002 in the innermost perimeter 1018 first, followed by the next outwardly successive perimeter, until kick off depths 1000 are assigned to well slot positions 1002 in the outermost perimeter 1006.

[0081] FIG. 11 depicts an overhead view of a drilling target configuration 1100 for each well slot position in the plurality of nested perimeters. A drilling target configuration 1100 may correspond to a path defining a distance from the well center 1102 to a drilling target 1104. Generally, the drilling target 1104 corresponds to a specific subsurface location that a well is intended to reach and produce from. For example, as shown in FIG. 11, the drilling target configuration 1100 may be determined by determining a path from the well center 1102 to the drilling target 1104 and calculating the resulting distance from the well center 1102 to the drilling target 1104. The drilling target configuration 1100 for each well slot position may be ordered, grouped, categorized, or otherwise organized based on their relative distances from the well center 1102. In FIG. 11, for example, the drilling target configurations 1100 are grouped into zones 1106, 1108, and 1110 based on their relative distances from the well center 1102, with zone 1106 corresponding to the farthest drilling target configurations 1100, zone 1108 corresponding to intermediate drilling target configurations 1100, and zone 1110 corresponding to the closest drilling target configurations 1100. A drilling target configuration 1100 may then be assigned, by a computer system, to each well slot position in the plurality of nested perimeters such that the drilling target configuration 1100 assigned to each well slot position may increase with each outwardly successive perimeter. For example, in some embodiments, and as illustrated in FIG. 11, each drilling target configuration 1100 may be ordered by descending distances from the well center 1102, and then sequentially assigned to each well slot position in the plurality of nested perimeters, such that the largest drilling target configurations 1100 are assigned to the outermost perimeter, the smallest drilling target configurations 1100 are assigned to the innermost perimeter, and the drilling target configuration 1100 assigned to each well slot position increases with each outwardly successive perimeter. However, drilling target configurations 1100 may be ordered, grouped, categorized, or otherwise organized using other suitable methods, and are not necessarily limited to the method discussed and illustrated in FIG. 11. Likewise, drilling target configurations 1100 may be assigned simultaneously, or they may be assigned sequentially using any suitable order for efficiently and effectively assigning drilling target configurations 1100 to each well slot position in the plurality of nested perimeters.

[0082] FIG. 12 depicts an initial kick off direction 1200 assigned, by a computer system, to each well slot position 1202 in the plurality of nested perimeters. The initial kick off direction 1200 for each well slot position 1202 may be determined at least partially by evaluating the corresponding drilling targets associated with each well slot position 1202, and the corresponding drilling targets may be analogous to those illustrated and discussed in relation to FIG. 11. The initial kick off directions 1200 may be assigned to each perimeter using any suitable order for efficiently and effectively assigning initial kick off directions 1200 to each well slot position 1202 in each perimeter. For example, in some embodiments, such as those further discussed herein in relation to FIGS. 13-15, initial kick off directions 1200 may be assigned sequentially, with initial kick off directions 1200 assigned to well slot positions 1202 in the outermost perimeter first, followed by the next inwardly successive perimeter, until initial kick off directions 1200 are assigned to well slot positions 1202 in the innermost perimeter. However, in other embodiments, initial kick off directions 1200 may be assigned to well slot positions 1202 in the innermost perimeter first, followed by the next outwardly successive perimeter, until initial kick off directions 1200 are assigned to well slot positions 1202 in the outermost perimeter. Alternatively, to facilitate assigning initial kick off directions 1200 to each well slot position 1202 in each perimeter, initial kick off directions 1200 may be pre-determined, pre-assigned, and stored in a database, such as the database described earlier. The initial kick off directions 1200 may then be assigned to each perimeter for current and / or future wells, and if necessary, further modified, for example after a first well has been drilled, in accordance with one or more of the processes described herein.

[0083] FIG. 13 depicts an initial kick off direction 1300 assigned, by a computer system, to each well slot position 1302 in an outermost perimeter 1304 of the plurality of nested perimeters. As previously discussed, the initial kick off directions 1300 for each well slot position 1302 may be determined at least partially by evaluating the corresponding drilling targets associated with each well slot position 1302. The initial kick off directions 1300 may be ordered, grouped, categorized, or otherwise organized based on their relative angular distances from a reference direction 1306. In FIG. 13, for example, the initial kick off directions 1300 are ordered based on their azimuthal directions from the reference direction 1306, in which case the reference direction 1306 is true north. The initial kick off directions 1300 may then be assigned, by a computer system, to each well slot position 1302 in the outermost perimeter 1304 such that the initial kick off direction 1300 increases with each adjacently successive well slot position in the outermost perimeter 1304. In some embodiments, the lowest initial kick off direction 1300 may be assigned to the well slot position 1302 that has the lowest azimuthal direction from the reference direction 1306, and the remaining initial kick off directions 1300 may be assigned to each well slot position 1302 in the outermost perimeter 1304 in a clockwise direction such that the initial kick off direction 1300 increases with each adjacently successive well slot position in the outermost perimeter 1304. However, as noted above, the initial kick off directions 1300 may be assigned to each perimeter simultaneously, or they may be assigned to each perimeter sequentially using any suitable order for efficiently and effectively assigning initial kick off directions 1300 to each well slot position 1302 in each perimeter, including counterclockwise and other suitable orders.

[0084] In some embodiments, each well slot position 1302 in the outermost perimeter 1304 may be evaluated, by a computer system, for overlapping projected well paths. The projected well paths for each well slot position 1302 in the outermost perimeter 1304 may be generated, by a computer system, by at least partially by evaluating the initial kick off direction 1300 and / or the initial kick off depth (as described earlier) associated with each well slot position 1302. If overlapping projected well paths are identified, at least two well slot positions 1302 in the outermost perimeter 1304 may be rearranged, by a computer system, to remove the overlap. For example, if two well slot positions 1302 have overlapping projected well paths, those two well slot positions 1302 may be swapped to remove the overlap. Alternatively, an iterative approach may be utilized in rearranging the at least two well slot positions 1302, such that well slot positions 1302 are rearranged until overlapping projected well paths are removed.

[0085] FIG. 14 and FIG. 15 depict this process performed for each inwardly successive perimeter. FIG. 14 depicts an initial kick off direction 1400 assigned to each well slot position 1402 in an intermediate perimeter 1404 of the plurality of nested perimeters. Similarly, FIG. 15 depicts an initial kick 1500 off direction assigned to each well slot position 1502 in an innermost perimeter 1504 of the plurality of nested perimeters. It should be noted that the process for assigning initial kick off directions to well slot positions and / or rearranging well slot positions with overlapping projected well paths may be identical or substantially similar with each perimeter, or may vary for each perimeter, whether performed simultaneously or sequentially. For example, FIGS. 13-15 depict one example of this process being performed sequentially starting with an outermost perimeter and ending with an innermost perimeter, in a substantially similar manner for each perimeter, until initial kick off directions have been assigned to each well slot positions in the plurality of nested perimeters and any overlapping projected well paths have been removed, resulting in the arrangement depicted in FIG. 12.

[0086] FIG. 16 depicts a nudge angle assigned to each well slot position 1600 in the plurality of nested perimeters. Generally, a nudge or nudge angle refers to a deviation of a projected well path from the vertical or initial path to steer the wellbore in a specific direction, such as in a direction that voids another well. In some embodiments, a nudge angle may be assigned, by a computer system, to each well slot position 1600 in the plurality of nested perimeters. The nudge angle assigned to each well slot position 1600 in the plurality of nested perimeters may be oriented in a direction away from the well center 1602 and increases with each outwardly successive perimeter, such as that shown in FIG. 16. Additionally, nudge angles may be assigned to each well slot position 1600 in the plurality of nested perimeters simultaneously, or they may be assigned sequentially using any suitable order for efficiently and effectively assigning nudge angles to each well slot position 1600 in the plurality of nested perimeters, ultimately resulting in the arrangement depicted in FIG. 17. As shown, FIG. 17 depicts an initial kick off direction 1700 and a nudge angle 1702 assigned to each well slot position 1704 in the plurality of nested perimeters.

[0087] FIG. 18 depicts cropped and uncropped portions 1800, 1802 of the projected well paths 1804 for each well slot position in the plurality of nested perimeters. As described earlier, the projected well paths 1804 for each well slot position in the plurality of nested perimeters may be generated, by a computer system, by at least partially by evaluating the initial kick off direction associated with each well slot position. A portion of the projected well paths 1804 may then be cropped, by a computer system, to define a cropped portion 1800 and an uncropped portion 1802. The cropped portion 1800 and the uncropped portion 1802 may be defined by a first radius and a second radius extending from a common origin 1808, with the first radius forming an upper dome 1806 and the second radius forming a lower dome (shown in FIG. 19). The area between upper dome 1806 and the lower dome may define the uncropped portion 1802, and the area outside of the upper dome 1806 and the lower dome may define the cropped portion 1800. The resulting uncropped portion 1802 may be characterized by a generally hemispherical shell shape, such as that shown in FIG. 18. The resulting uncropped portion 1802 the projected well path may be visualized for well planning and during drilling. Additionally, while the common origin 1808 is illustrated in FIG. 18 as being centered on the drilling surface 1810, the common origin 1808 may be located location on the drilling surface 1810, thus adjusting the visualization of the uncropped portion 1802. The first radius and second radius forming the upper dome 1806 and lower dome may also be modified to adjust the visualization of the uncropped portion 1802. For example, FIG. 19 depicts, from an alternate perspective, cropped and uncropped portions 1900, 1902 of the projected well paths 1904 for each well slot position in the plurality of nested perimeters. In FIG. 19, the upper dome is not shown while the lower dome 1906 is shown, and the common origin (not shown) is not centered on the drilling surface (not shown).

[0088] FIG. 20 depicts a block diagram 2000 of various operations that can be performed in different phases of well planning. Such phases of well planning can include pre-planning, site planning, and planning while drilling phases of well planning. Block diagram 2000 may include, at block 2002, determining, by a computer system, an initial well plan for a plurality of wells on a pad. The initial well plan may be determined via one or more of the methods and systems disclosed herein for well planning, such as those discussed in connection with FIGS. 1-19. Block diagram 2000 may further include, at block 2004, drilling a first well according to the initial well plan; and at block 2006, monitoring, by the computer system, a real-time drilling parameter for each well. The real-time drilling parameter may include any suitable drilling parameter that can be monitored and utilized for maximizing the efficiency and profitability of mineral extraction, including but not limited to a kick off depth, a kick off direction, a nudge angle, a kick off rate, a build-up rate, or combinations thereof. Block diagram 2000 may further include, at block 2008, updating, by the computer system, a projected well path for one or more wells based on the real-time drilling parameter, defining an updated well plan; and at block 2010, drilling a second well according to the updated well plan.

[0089] One or more of the operations shown in block diagram 2000 may be performed and repeated in an iterative fashion to maximize the efficiency and profitability of mineral extraction. For example, as noted earlier, an initial well plan (and thus one or more projected well paths) may be determined via one or more of the methods and systems disclosed herein for well planning. A first well may then be drilled according to the initial well plan, and one or more real-time drilling parameters may be monitored before, during, and / or after the first well is drilled. A projected well path for one or more of the wells may be updated based on the real-time drilling parameter, defining an updated well plan, and a second well may then be drilled according to the updated projected well path. Accordingly, one or more real-time drilling parameters may be iteratively altered for one or more of the plurality of wells on the pad until a desired arrangement is achieved. For example, a kick off depth may be assigned to each well on the pad, and the kick off depths may be iteratively raised or lowered until an optimal arrangement is achieved. Alternatively, a kick off direction may be assigned to each well on the pad, and the kick off direction may be iteratively raised and lowered until an optimal arrangement is achieved. In such instances, an optimal arrangement may be one that maximizes the extraction of minerals while minimizing operational costs. For example, since most companies require an adjacent well to be shut in when a certain proximity is reached, the optimal result may be the arrangement with a minimum predicted production loss. The same operation may be performed for other parameters, such as a nudge angle or kick off rate, and may be performed either sequentially or simultaneously when monitoring more than one real-time drilling parameters.

[0090] The above disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other embodiments which fall within the true spirit and scope of the present disclosure. Thus, to the maximum extent allowed by law, the scope of the present disclosure is to be determined by the broadest permissible interpretation of the following claims and their equivalents, and shall not be restricted or limited by the foregoing detailed description.

Claims

1. A method for drilling a plurality of wells on a pad, the method comprising:generating, by a computer system, a first arrangement of a plurality of well slot positions, wherein the plurality of well slot positions are laterally spaced on a pad in the first arrangement;defining, by the computer system, a plurality of nested perimeters of the first arrangement of the plurality of well slot positions, the plurality of nested perimeters comprising an outermost perimeter defined by a subset of the plurality of well slot positions in the first arrangement that form an outer boundary of the first arrangement, and an innermost perimeter that defines a well center;determining, by the computer system, an initial kick off direction for each well slot position in a perimeter of the plurality of nested perimeters;rearranging, by the computer system, at least two well slot positions in the perimeter of the plurality of nested perimeters, wherein the at least two well slot positions are rearranged such that the initial kick off direction corresponding to each well slot position in the perimeter increases with each adjacently successive well slot position in the perimeter;drilling a first well;monitoring, by the computer system, a real-time drilling parameter for each well slot position in the plurality of nested perimeters;updating, by the computer system, a projected well path for at least one well slot position based on the real-time drilling parameter, defining an updated projected well path; anddrilling a second well according to the updated projected well path.

2. The method of claim 1, further comprising:evaluating, by the computer system, each well slot position in the perimeter for overlapping well paths; andif overlapping projected well paths are identified, further rearranging, by the computer system, at least two well slot positions in the perimeter.

3. The method of claim 1, further comprising:assigning, by the computer system, a kick off depth to each well slot position in each perimeter of the plurality of nested perimeters, wherein adjacent well slot positions within each perimeter are assigned different kick off depths, and the kick off depth assigned to each well slot position in the plurality of nested perimeters increases with each inwardly successive perimeter.

4. The method of claim 1, further comprising:assigning, by the computer system, a drilling target configuration to each well slot position of the plurality of well slot positions, the drilling target configuration corresponding to a distance from the well center to a drilling target, wherein the drilling target configuration assigned to each well slot position in the plurality of nested perimeters increases with each outwardly successive perimeter.

5. The method of claim 1, further comprising:assigning, by the computer system, a nudge angle to each well slot position in the plurality of nested perimeters, wherein the nudge angle assigned to each well slot position in the plurality of nested perimeters is oriented in a direction away from the well center and increases with each outwardly successive perimeter.

6. The method of claim 1, further comprising:visualizing a portion of the projected well path, the portion of the projected well path generated by cropping, by the computer system, a portion of the projected well path so as to define a cropped portion of the projected well path and an uncropped portion of the projected well path, wherein the uncropped portion of the projected well path is characterized by a generally hemispherical shell shape, the generally hemispherical shell shape defined by an inner radius and an outer radius extending from a common origin, and the common origin being located below the pad.

7. A method for well planning for optimized production results, the method comprising:generating, by a computer system, a first arrangement of a plurality of well slot positions, wherein the plurality of well slot positions are laterally spaced on a drilling surface in the first arrangement;defining, by the computer system, a plurality of nested perimeters of the first arrangement of the plurality of well slot positions, the plurality of nested perimeters comprising an outermost perimeter defined by a subset of the plurality of well slot positions in the first arrangement that form an outer boundary of the first arrangement, and an innermost perimeter that defines a well center;determining, by the computer system, an initial kick off direction for each well slot position in a perimeter of the plurality of nested perimeters; andrearranging, by the computer system, at least two well slot positions in the perimeter of the plurality of nested perimeters, wherein the at least two well slot positions are rearranged such that the initial kick off direction corresponding to each well slot position in the perimeter increases with each adjacently successive well slot position in the perimeter.

8. The method of claim 7, further comprising:assigning, by the computer system, a drilling target configuration to each well slot position in the plurality of nested perimeters, the drilling target configuration corresponding to a distance from the well center to a drilling target, wherein the drilling target configuration assigned to each well slot position in the plurality of nested perimeters increases with each outwardly successive perimeter.

9. The method of claim 7, further comprising:generating, by the computer system, a projected well path for each well slot in the perimeter, the projected well path being at least partially determined by the initial kick off direction corresponding to each well slot position in the perimeter;evaluating, by the computer system, each well slot position in the perimeter for overlapping projected well paths; andif overlapping projected well paths are identified, further rearranging, by the computer system, at least two well slot positions in the perimeter.

10. The method of claim 7, further comprising:assigning, by the computer system, a kick off depth to each well slot position in each perimeter of the plurality of nested perimeters, wherein adjacent well slot positions within each perimeter are assigned different kick off depths, and the kick off depth assigned to each well slot in the plurality of nested perimeters increases with each inwardly successive perimeter.

11. The method of claim 7, further comprising:assigning, by the computer system, a nudge angle to each well slot position in the plurality of nested perimeters, wherein the nudge angle assigned to each well slot position in the plurality of nested perimeters is oriented in a direction away from the well center and increases with each outwardly successive perimeter.

12. The method of claim 7, further comprising:generating, by the computer system, a projected well path for each well slot in the plurality of nested perimeters, the projected well path being at least partially determined by the initial kick off direction corresponding to each well slot position in the plurality of nested perimeters;monitoring, by the computer system, a real-time drilling parameter for each well slot position in the plurality of nested perimeters; andupdating, by the computer system, the projected well path for at least one well slot based on the real-time drilling parameter.

13. The method of claim 7, further comprising:generating, by the computer system, a projected well path for the plurality of well slot positions, the projected well path being at least partially determined by the initial kick off direction corresponding to each well slot in the plurality of nested perimeters;cropping, by the computer system, a portion of the projected well path so as to define a cropped portion of the projected well path and an uncropped portion of the projected well path, wherein the uncropped portion of the projected well path is characterized by a generally hemispherical shell shape, the generally hemispherical shell shape defined by an inner radius and an outer radius extending from a common origin, and the common origin being located below the drilling surface; andevaluating the uncropped portion of the projected well path.

14. A computer system for well planning, the computer system comprising:a processor;a memory coupled to the processor, wherein the memory comprises a plurality of instructions executable by the processor, the plurality of instructions comprising instructions for:generating, by the computer system, a first arrangement of a plurality of well slot positions, wherein the plurality of well slot positions are laterally spaced on a drilling surface in the first arrangement;defining, by the computer system, a plurality of nested perimeters of the first arrangement of the plurality of well slot positions, the plurality of nested perimeters comprising an outermost perimeter defined by a subset of the plurality of well slot positions in the first arrangement that form an outer boundary of the first arrangement, and an innermost perimeter that defines a well center; andassigning, by the computer system, a kick off depth to each well slot position in the plurality of nested perimeters, wherein adjacent well slot positions within each perimeter are assigned different kick off depths, and the kick off depth assigned to each well slot in the plurality of nested perimeters increases with each inwardly successive perimeter.

15. The computer system of claim 14, further comprising instructions for:determining, by the computer system, an initial kick off direction for each well slot position in a perimeter of the plurality of nested perimeters; andrearranging, by the computer system, at least two well slot positions in the perimeter of the plurality of nested perimeters, wherein the at least two well slot positions are rearranged such that the initial kick off direction corresponding to each well slot position in the perimeter increases with each adjacently successive well slot position in the perimeter.

16. The computer system of claim 15, further comprising instructions for:generating, by the computer system, a projected well path for each well slot position in the perimeter, the projected well path being at least partially determined by the initial kick off direction corresponding to each well slot position in the perimeter;evaluating, by the computer system, each well slot position in the perimeter for overlapping projected well paths; andif overlapping projected well paths are identified, further rearranging, by the computer system, at least two well slot positions in the perimeter.

17. The computer system of claim 14, further comprising instructions for:assigning, by the computer system, a drilling target configuration to each well slot position in the plurality nested perimeters, the drilling target configuration corresponding to a distance from the well center to a drilling target, wherein the drilling target configuration assigned to each well slot position in the plurality of nested perimeters increases with each outwardly successive perimeter.

18. The computer system of claim 14, further comprising instructions for:assigning, by the computer system, a nudge angle to each well slot position in the plurality of nested perimeters, wherein the nudge angle assigned to each well slot position in the plurality of nested perimeters is oriented in a direction away from the well center and increases with each outwardly successive perimeter.

19. The computer system of claim 14, further comprising instructions for:generating, by the computer system, a projected well path for each well slot position in the plurality of nested perimeters, the projected well path being at least partially determined by the kick off depth corresponding to each well slot position in the plurality of nested perimeters;monitoring, by the computer system, a real-time drilling parameter for each well slot position in the plurality of nested perimeters; andupdating, by the computer system, the projected well path for at least one well slot based on the real-time drilling parameter.

20. The computer system of claim 14, further comprising instructions for:generating, by the computer system, a projected well path for the plurality of well slot positions, the projected well path being at least partially determined by the kick off depth corresponding to each well slot position in the plurality of nested perimeters;cropping, by the computer system, a portion of the projected well path so as to define a cropped portion of the projected well path and an uncropped portion of the projected well path, wherein the uncropped portion of the projected well path is characterized by a generally hemispherical shell shape, the generally hemispherical shell shape defined by an inner radius and an outer radius extending from a common origin, and the common origin being located below the drilling surface; andevaluating the uncropped portion of the projected well path.

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